-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, IabMHjbns6iMZpJ1dVPJ0hWBaYau91BXO6dV1toEZwDp/8sL1ynZspBZzKAsR024 zU6DtZGdapxzn9MAh5iL8g== 0000950134-98-002623.txt : 19980331 0000950134-98-002623.hdr.sgml : 19980331 ACCESSION NUMBER: 0000950134-98-002623 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 12 CONFORMED PERIOD OF REPORT: 19971231 FILED AS OF DATE: 19980330 SROS: NYSE SROS: PCX 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-K SEC ACT: SEC FILE NUMBER: 001-03473 FILM NUMBER: 98577747 BUSINESS ADDRESS: STREET 1: 8700 TESORO DR CITY: SAN ANTONIO STATE: TX ZIP: 78217 BUSINESS PHONE: 2108288484 10-K 1 FORM 10-K FOR YEAR ENDED DECEMBER 31, 1997 1 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 --------------------- FORM 10-K (MARK ONE) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1997 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM . . . . TO . . . . COMMISSION FILE NUMBER 1-3473 TESORO PETROLEUM CORPORATION (Exact name of registrant as specified in its charter) DELAWARE 95-0862768 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.)
8700 TESORO DRIVE, SAN ANTONIO, TEXAS 78217-6218 (Address of principal executive offices) (Zip Code) REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 210-828-8484 --------------------- SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
NAME OF EACH EXCHANGE TITLE OF EACH CLASS ON WHICH REGISTERED ------------------- --------------------- Common Stock, $0.16 2/3 par value New York Stock Exchange Pacific Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None 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 [ ] --------------------- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] --------------------- At February 27, 1998, the aggregate market value of the voting stock held by nonaffiliates of the registrant was approximately $404,566,324 based upon the closing price of its Common Stock on the New York Stock Exchange Composite tape. At February 27, 1998, there were 26,661,845 shares of the registrant's Common Stock outstanding. --------------------- DOCUMENTS INCORPORATED BY REFERENCE Portions of the registrant's Proxy Statement pertaining to the 1998 Annual Meeting of Stockholders are incorporated by reference into Part III hereof. ================================================================================ 2 TESORO PETROLEUM CORPORATION ANNUAL REPORT ON FORM 10-K TABLE OF CONTENTS
PAGE ---- PART I Item 1. Business.................................................... 1 Recent Development..................................... 1 Refining and Marketing................................. 2 Exploration and Production............................. 6 Marine Services........................................ 14 Competition and Other.................................. 15 Government Regulation and Legislation.................. 17 Employees.............................................. 19 Executive Officers of the Registrant................... 20 Item 2. Properties.................................................. 21 Item 3. Legal Proceedings........................................... 21 Item 4. Submission of Matters to a Vote of Security Holders......... 21 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.................................... 22 Item 6. Selected Financial Data..................................... 23 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.............................. 25 General................................................ 25 Results of Operations.................................. 26 Capital Resources and Liquidity........................ 37 Forward-Looking Statements.................................. 42 Item 8. Financial Statements and Supplementary Data................. 43 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure............................... 76 PART III Item 10. Directors and Executive Officers of the Registrant.......... 76 Item 11. Executive Compensation...................................... 76 Item 12. Security Ownership of Certain Beneficial Owners and Management............................................. 76 Item 13. Certain Relationships and Related Transactions.............. 76 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.................................................... 76 SIGNATURES............................................................ 83
THIS ANNUAL REPORT CONTAINS STATEMENTS WITH RESPECT TO THE COMPANY'S EXPECTATIONS OR BELIEFS AS TO FUTURE EVENTS. THESE TYPES OF STATEMENTS ARE FORWARD-LOOKING AND SUBJECT TO UNCERTAINTIES. SEE "FORWARD-LOOKING STATEMENTS" ON PAGE 42. i 3 PART I ITEM 1. BUSINESS Tesoro Petroleum Corporation together with its subsidiaries ("Tesoro" or the "Company") is a natural resource company engaged in petroleum refining, distributing and marketing of petroleum products, marine logistics services and the exploration and production of natural gas and oil. These operations are conducted through three business segments: Refining and Marketing, Exploration and Production, and Marine Services. Downstream, the Company's Refining and Marketing segment owns and operates a petroleum refinery at Kenai, Alaska ("Kenai Refinery"), markets refined products through a large network of branded stations in Alaska and is expanding its marketing presence in the Pacific Northwest. This segment is also a major supplier of jet fuel to the Anchorage airport and diesel fuel to Alaska's fishing and marine industry. The Company's Marine Services segment operates through a network of 23 marine terminals located in Louisiana and Texas and on the U.S. West Coast, distributing petroleum products and providing logistics services to the offshore Gulf of Mexico drilling industry and other customers. Upstream, the Company's Exploration and Production segment focuses on exploration, development and production of natural gas and oil onshore in Texas, Louisiana and Bolivia. The Company's net proved worldwide reserves totaled 517 billion cubic feet equivalents ("Bcfe") of natural gas at year-end 1997. The Company is focused on its long-term strategy to maximize returns and develop full value of its assets through strategic expansions, acquisitions and diversifications in all three of its operating segments. Tesoro was incorporated in Delaware in 1968 (a successor by merger to a California corporation incorporated in 1939). Its principal executive offices are located at 8700 Tesoro Drive, San Antonio, Texas 78217-6218 and its telephone number is (210) 828-8484. For financial and statistical information relating to the Company's operations, see Management's Discussion and Analysis of Financial Condition and Results of Operations in Item 7 and Note B of Notes to Consolidated Financial Statements in Item 8. RECENT DEVELOPMENT On March 18, 1998, the Company entered into a stock sale agreement ("Stock Sale Agreement") with BHP Hawaii Inc. and BHP Petroleum Pacific Islands Inc. (collectively, the "Sellers"), subsidiaries of The Broken Hill Proprietary Company Limited ("BHP"), whereby Tesoro will purchase all of the outstanding stock of BHP Petroleum Americas Refining Inc. ("BHP Refining") and BHP Petroleum South Pacific Inc. ("BHP South Pacific"). BHP Refining owns and operates a 95,000-barrel a day refinery in Kapolei, Hawaii on the island of Oahu, approximately 20 miles west of Honolulu, and 32 retail gasoline stations on the islands of Oahu, Maui and Hawaii. The acquisition, which is subject to regulatory review and other customary conditions, is anticipated to close on May 29, 1998. Under the terms of the Stock Sale Agreement, the Company has deposited $5 million into an escrow account for this acquisition. At closing Tesoro will pay the Sellers a cash purchase price currently estimated to be approximately $275 million, less the $5 million escrow deposit, for the stock of BHP Refining and BHP South Pacific. The cash purchase price will be adjusted after the closing based on the amount by which net working capital of BHP Refining and BHP South Pacific at closing is in excess of or less than $100 million. In addition, Tesoro will issue an unsecured, non-interest bearing, promissory note in the amount of $50 million payable in five equal annual installments of $10 million each, beginning on the eleventh anniversary date of closing. The note provides for earlier payment to the extent of one-half of the amount by which earnings from the acquired assets, before interest expense, income taxes and depreciation, depletion and amortization, as specified in the note, exceed $50 million in any calendar year. Upon acceleration due to an event of default, the amount outstanding to be paid under the note will be reduced to present value using a discount rate of 9%. The Stock Sale Agreement contains representations and warranties and other general provisions that are customary for transactions of this nature. 1 4 The parties will execute a separate environmental agreement at closing, whereby the Sellers will indemnify Tesoro and BHP Refining and BHP South Pacific for environmental costs arising out of conditions which exist at, or existed prior to, closing subject to a maximum limit of $9.5 million. Under the environmental agreement, the first $5 million of these liabilities will be the responsibility of the Sellers and the next $6 million will be shared on the basis of 75% by the Sellers and 25% by Tesoro. The environmental indemnity will survive for a ten-year period. Certain environmental claims arising out of prior operations will not be subject to the $9.5 million limit or the ten-year time limit for claims made. BHP will guarantee all of the obligations of the Sellers under the Stock Sale Agreement and the environmental agreement. Tesoro and an affiliate of BHP will enter into a crude supply agreement pursuant to which the BHP affiliate will assist Tesoro in acquiring crude oil feedstock sourced outside of North America and arrange for transportation of such crude oil to the Hawaiian refinery. The crude supply agreement will be for a period of two years and provides for annual payments of $1.4 million by Tesoro to the BHP affiliate for such services. For further information regarding the proposed acquisition, see Management's Discussion and Analysis of Financial Condition and Results of Operations in Item 7 and Note O of Notes to Consolidated Financial Statements in Item 8. REFINING AND MARKETING OVERVIEW The Company conducts petroleum refining operations in Alaska and sells refined products to a wide variety of customers in Alaska, along the U.S. West Coast, primarily in the Pacific Northwest, and in certain Far Eastern markets, including Russia. During 1997, products from the Kenai Refinery accounted for approximately 78% of these sales volumes, including products received on exchange in the U.S. West Coast market, with the remaining 22% being purchased from other refiners and suppliers. REFINERY The Kenai Refinery in Alaska has a rated throughput capacity of 72,000 barrels per day and is capable of producing liquefied petroleum gas, gasoline, jet fuel, diesel fuel, heating oil, liquid asphalt, heavy oils and residual products. Alaska North Slope ("ANS") and Cook Inlet crude oils are the primary feedstocks for the Kenai Refinery. To assure the availability of crude oil to the Kenai Refinery, the Company has a royalty crude oil purchase contract with the State of Alaska ("State") and contracts with various Cook Inlet producers (see "Crude Oil Supply" discussed below). During 1997, the Kenai Refinery processed approximately 71% ANS crude oil, 26% Cook Inlet crude oil and 3% other feedstocks, which yielded refined products consisting of approximately 25% gasoline, 42% middle distillates, 29% heavy oils and residual products and 4% other products. Throughput at the Kenai Refinery was reduced during both 1997 and 1996 for scheduled 30-day maintenance turnarounds. In early October 1997, the Company completed an expansion of the Kenai Refinery's hydrocracker unit, which increased the unit's capacity by approximately 25% to 12,500 barrels per day and enables the Company to produce more jet fuel, a product in short supply in Alaska. The expansion, together with the addition of a new, high-yield jet fuel hydrocracker catalyst, cost approximately $19 million and has a projected payback period of two years. The expansion began to improve the Kenai Refinery's product slate during the fourth quarter of 1997. CRUDE OIL SUPPLY The Kenai Refinery is designed to process crude oil with up to 1.0% sulphur content. As such, the Kenai Refinery can process Cook Inlet, ANS and certain other foreign and domestic crude oils. 2 5 ANS Crude Oil. ANS crude oil, a heavy crude oil which has a sulphur content of approximately 1.0%, accounted for 71% of the Kenai Refinery's feedstock in 1997. The Company purchased approximately 35,700 barrels per day of ANS crude oil during 1997 under the royalty crude oil purchase contract with the State. This contract, which covers the period January 1, 1996 through December 31, 1998, provides for the purchase of 30% of the State's ANS royalty crude oil produced from the Prudhoe Bay Unit at prices based on royalty values computed by the State. The contract contains provisions that, under certain conditions, allow the Company to temporarily or permanently reduce its purchase obligation. Under the contract, the Company is required to utilize in its refinery operations volumes equal to at least 80% of the ANS crude oil purchased from the State. The Company is presently in discussions with the State in regard to extending this contract for an additional year. The Company also purchases approximately 6,000 barrels per day of ANS crude oil from a producer under a contract with a term of one year beginning January 1, 1998. ANS crude oil feedstock is delivered to the Kenai Refinery by tanker through the Kenai Pipe Line Company ("KPL") marine terminal, which is owned and operated by the Company. For information related to a settlement of a contractual dispute with the State in 1993, see Note I of Notes to Consolidated Financial Statements in Item 8. Cook Inlet Crude Oil. Cook Inlet crude oil, a lighter crude oil that contains an average of 0.1% sulphur, accounted for 26% of the Kenai Refinery's feedstock in 1997. In the first nine months of 1997, the Company processed approximately 9,300 barrels per day of Cook Inlet crude oil, or 19% of the Kenai Refinery's throughput, which was obtained from several producers on the Kenai peninsula under short-term contracts. During October 1997, the Company began purchasing all of the approximately 34,000 barrels per day of Cook Inlet production from various producers under contracts that extend through December 1998. A contract to purchase 4,500 barrels per day, of the 34,000 barrels per day, has been extended through March 31, 2001. During the fourth quarter of 1997, the Company processed approximately 24,900 barrels per day of Cook Inlet crude oil, or approximately 44% of the Kenai Refinery's throughput. Cook Inlet crude oil is delivered by tanker through KPL's marine terminal or by pipeline to the Kenai Refinery. Other Supply. In 1997, the Kenai Refinery obtained 3% of its feedstock supply from other sources. The other supply primarily consisted of spot purchases of crude oil which were delivered to the Kenai Refinery by tanker through KPL's marine terminal. The Company evaluates the economic viability of processing various types of foreign and domestic crude oils in the Kenai Refinery and will occasionally purchase spot quantities to supplement its normal crude oil supply. MARKETING IN ALASKA Gasoline. The Company distributes gasoline to end users in Alaska, either by retail sales through 35 Company-operated stations, by wholesale sales through 129 branded and 28 unbranded dealers and jobbers or by deliveries to major oil companies for their retail operations in Alaska in exchange for gasoline delivered to the Company on the U.S. West Coast. The Company holds an exclusive license agreement for all 7-Eleven convenience stores in Alaska, which are operated by the Company. During 1997, these Company-operated retail stations sold an average of 93,000 gallons of gasoline per day. In 1997, the Company initiated a three-year, $50 million retail marketing expansion program focused primarily in Anchorage, Alaska, the State's largest motor fuel market. During the year, two new retail facilities were built, three stations were remodeled and two uneconomic outlets were closed. In addition, in late 1997, the Company purchased the Union 76 marketing assets in Alaska, which included two retail stations located in Southeast Alaska and the rights to use the Union 76 trademark within Alaska. Gasoline produced in excess of Alaska's market demand is shipped to the U.S. West Coast or exported to the Far East by chartered vessel. 3 6 Middle Distillates. The Company is a major supplier of commercial jet fuel into the Alaskan marketplace, with a majority of its production being marketed to passenger and cargo airlines. The demand for jet fuel in Alaska is growing and currently exceeds the production of all refiners in Alaska. Several marketers, including the Company, import jet fuel into Alaska to meet excess demand. The expansion of the Kenai Refinery's hydrocracker unit has increased the Company's jet fuel production to help meet this growing market. Substantially all of the Company's diesel fuel production is sold on a wholesale basis in Alaska, primarily for marine, transportation and industrial purposes. As part of the purchase of the Union 76 marketing assets discussed above, the Company acquired a terminal with a 110,000-barrel capacity in Ketchikan, Alaska. Diesel fuel will be supplied to this terminal from the Kenai Refinery and the U.S. West Coast. The product will be delivered to the terminal by marine barge. Generally, the production of diesel fuel by refiners in Alaska is in balance with demand; however, because of the variability of the demand, there are occasions when diesel fuel is imported into or exported from Alaska. See "Government Regulation and Legislation -- Environmental Controls" for a discussion of the effect of governmental regulations on the production of low-sulphur diesel fuel for on-highway use in Alaska. Heavy Oils and Residual Products. The Kenai Refinery's vacuum unit uses crude tower bottoms as a feedstock and further processes these volumes into light vacuum gas oil ("LVGO"), heavy vacuum gas oil ("HVGO") and vacuum tower bottoms ("VTBs"). The LVGO is further processed in the Kenai Refinery's hydrocracker, where it is converted into gasoline and jet fuel. HVGO is sold to refiners on the U.S. West Coast, where it is used as fluid catalytic cracker feedstock. The VTBs are used to produce liquid asphalt or the VTBs are sold on the U.S. West Coast where they are blended with light cycle oil to produce bunker fuel. The Company sells its liquid asphalt, which is used in the manufacturing of highway paving materials, primarily in Alaska where the demand is seasonal because mild weather conditions are needed for highway construction. During 1997, the Company opened an asphalt marketing facility in Anchorage, which helped increase sales of this product in Alaska. MARKETING OUTSIDE OF ALASKA U.S. West Coast. The Company conducts wholesale marketing operations along the U.S. West Coast, primarily in Oregon and Washington, selling refined products in the bulk market and through eight terminal facilities, including three operated by the Company. In 1997, these operations sold approximately 10,300 barrels per day of refined products, primarily gasoline and diesel fuel, of which approximately 25% was received from major oil companies in exchange for products from the Kenai Refinery, approximately 24% was received directly from the Kenai Refinery and 51% was purchased from other suppliers. In January 1998, operations of the three Company-operated facilities on the U.S. West Coast were transferred to the Company's Marine Services segment. The Company's retail presence in Oregon and Washington was expanded during 1997 by adding twelve branded stations, bringing the number of "Tesoro Alaska" branded gasoline stations in the Pacific Northwest to 30 at year-end. Far East. From time to time, the Company exports refined products from the Kenai Refinery to certain markets in the Far East, including Russia. These exported products, primarily gasoline, are transported to the Far East by a chartered Russian flag vessel, described below, or at times by spot charters. TRANSPORTATION The Company charters two American flag vessels, the Potomac Trader and the Chesapeake Trader. These vessels are used to transport ANS crude oil from the Trans Alaska Pipeline System ("TAPS") terminal at Valdez, Alaska and Cook Inlet crude oil from the Drift River terminal to the Kenai Refinery. The vessels are also used to transport heavy oils and residual products to the U.S. West Coast and occasionally to transport other feedstocks or products to the Kenai Refinery. The Potomac Trader and Chesapeake Trader are chartered under five-year agreements expiring in 2000. The Company charters a Russian flag vessel, the Igrim, to primarily transport refined products from the Kenai Refinery to the Far East. The Igrim is chartered under 4 7 an agreement expiring in June 1998, which may be extended at the Company's option through June 2000. The Company plans to continue marketing its products in the Far East and is evaluating transportation alternatives. From time to time, the Company also charters tankers and ocean-going barges to transport petroleum products to its customers within Alaska, on the U.S. West Coast and in the Far East. The Company operates a common carrier petroleum products pipeline from the Kenai Refinery to its terminal in Anchorage. This ten-inch diameter pipeline has a capacity to transport approximately 40,000 barrels of petroleum products per day and allows the Company to transport light products to the terminal throughout the year, regardless of weather conditions. During 1997, the pipeline transported an average of approximately 24,100 barrels of petroleum products per day, all of which were transported for the Company. The Company also owns and operates KPL, a common carrier pipeline and marine dock facility, which assures the Company of uninterrupted use of the dock and pipeline for unloading crude oil feedstocks and loading product inventory on tankers and barges. During 1997, KPL transported approximately 49,700 barrels of crude oil per day and 37,300 barrels of refined products per day, all of which were transported for the Company. For further information on transportation in Alaska, see "Government Regulation and Legislation -- Environmental Controls." REFINING AND MARKETING STATISTICS The following table summarizes the Company's refining and marketing operations for the years ended December 31, 1997, 1996 and 1995:
1997 1996 1995 ------- ------- ------- Kenai Refinery Throughput: Barrels per day..................................... 50,207 47,486 50,569 % ANS crude oil..................................... 71% 72% 68% Refined Products Manufactured (average daily barrels): Gasoline and gasoline blendstocks................... 12,851 12,763 14,298 Middle distillates, including jet fuel and diesel fuel............................................. 21,636 19,975 20,693 Heavy oils and residual products.................... 14,752 13,739 14,516 Other............................................... 2,279 2,600 2,489 ------- ------- ------- Total Refined Products Manufactured......... 51,518 49,077 51,996 ======= ======= ======= Total Segment Product Sales (average daily barrels)(a): Gasoline............................................ 17,393 17,427 24,526 Middle distillates.................................. 30,576 29,651 37,988 Heavy oils and residual products.................... 17,929 15,089 14,787 ------- ------- ------- Total Product Sales......................... 65,898 62,167 77,301 ======= ======= ======= Total Segment Product Sales Prices ($/barrel): Gasoline............................................ $ 33.71 $ 32.72 $ 28.21 Middle distillates.................................. $ 28.36 $ 29.01 $ 24.40 Heavy oils and residual products.................... $ 17.30 $ 17.61 $ 13.66 Number of Stations Selling the Kenai Refinery's Gasoline(b): Alaska -- Company-operated(c).............................. 35 33 32 Branded.......................................... 129 126 99 Unbranded........................................ 28 29 28 Pacific Northwest -- branded........................ 30 18 10 ------- ------- ------- Total Stations.............................. 222 206 169 ======= ======= =======
- --------------- (a) Sources of total product sales include products manufactured at the Kenai Refinery, products drawn from inventory balances and products purchased from third parties. The Company's purchases of refined 5 8 products for resale were approximately 11,300, 11,600 and 25,500 average daily barrels for 1997, 1996 and 1995, respectively. (b) Branded gasoline stations sell the Kenai Refinery's gasoline under the "Tesoro Alaska" name in Alaska, Oregon and Washington (total of 192 stations) and under the "Union 76" name in Southeast Alaska (total of two stations). Stations that sell the Company's gasoline under a different name are considered unbranded. (c) Company-operated stations include branded 7-Eleven convenience store locations in Alaska. EXPLORATION AND PRODUCTION OVERVIEW The Company's Exploration and Production segment is engaged in the exploration, development and production of natural gas and oil onshore in Texas, Louisiana and Bolivia. This segment also includes the transportation of natural gas, including the Company's production, to common carrier pipelines in South Texas. During 1997, the Company increased its worldwide net proved reserves by 39% to 517 Bcfe of natural gas. Worldwide net production of natural gas and oil averaged 109 million cubic feet equivalents ("MMcfe") per day during 1997 and increased to approximately 125 MMcfe per day in January 1998. In the U.S., the Company has made significant progress in diversifying its operations to areas other than the mature Bob West Field in South Texas. The Company's U.S. production from fields other than the Bob West Field rose to 50% of its total U.S. production in January 1998, as compared to 7% at year-end 1996. During the past two years, the Company has acquired approximately 120,000 net undeveloped acres in the U.S., bringing its total to approximately 133,000 net undeveloped U.S. acres at December 31, 1997. During 1996 and 1997, the Exploration and Production segment purchased interests in the Frio/Vicksburg Trend and the Wilcox Trend in South Texas, in the Val Verde Basin in Southwest Texas and in the East Texas Basin. By January 1998, the Company served as operator of 44% of its U.S. net production, compared to 5% at year-end 1996. During 1997, the Company's U.S. net proved reserve volumes increased 27% to 150 Bcfe and net production averaged 87 MMcfe per day. The Company participated in the completion of nine gross development wells and eight gross exploratory wells in 1997, with seven gross wells drilling at year-end. In Bolivia, the Company operates under four contracts with the Bolivian government to explore for and produce hydrocarbons. The Company's Bolivian natural gas production is sold under contract to the Bolivian government for export to Argentina. The majority of the Company's natural gas and oil reserves in Bolivia are shut-in awaiting access to gas-consuming markets which is expected to be provided by a 1,900-mile pipeline from Bolivia to Brazil. Pipeline construction began in 1997 and first gas deliveries are expected in early 1999. In July 1997, the Company acquired the interests of its former joint venture participant, increasing its net proved reserve volumes in Bolivia by 35%. During 1997, the Company's Bolivian net proved reserve volumes increased in total by 45% to 366 Bcfe and net production averaged 23 MMcfe per day. UNITED STATES WILCOX TREND The Company has 23,088 net acres, including 17,147 net undeveloped acres, under lease in the Wilcox Trend. Approximately 52% (78.4 Bcfe) of the Company's U.S. net proved reserve volumes are located in eleven producing fields in this trend, including the Bob West Field, the Company's largest U.S. field. The Wilcox Trend extends from Northern Mexico through South Texas into the other Gulf Coast states. Multiple pay sands exist within the Wilcox Trend, where extensive faulting has trapped hydrocarbons in numerous producing zones. Bob West Field. The Bob West Field, which was discovered by the Company in 1990, is located in the southern part of the Wilcox Trend in Starr and Zapata Counties, Texas. Continued successful development of the Bob West Field led to the completion of three development wells during 1997. This concluded the drilling program in this 4,000-acre field, after drilling and completing a total of 77 gross wells since 1991, 14 of which were sold during 1995. During 1997, the Company's net natural gas production from the Bob West Field 6 9 averaged approximately 66 million cubic feet ("MMcf") per day. The Company's estimated net proved reserve volumes in the Bob West Field totaled 59 Bcfe at December 31, 1997. The Company's working interests in wells located in the Bob West Field range from 33% to 70%. In addition, the Company owns a 70% interest in the field's central gas processing facility which has a gross capacity of 350 MMcf per day. The Company also owns 25% of a central compression facility, rated at 17,770 horsepower with an estimated gross capacity of 150 MMcf per day. Berry R. Cox Field. In December 1997, a development well, the Gonzales No. 8, located in Webb County, Texas, was completed in the Berry R. Cox Field. Tesoro has a 100% working interest in the Gonzales unit. The Company purchased its working interest in the unit in transactions during 1996 and 1997 for a total of $3.2 million. At the time of the initial purchase, the unit had two wells producing a total of 1.8 MMcf per day and three shut-in wells. The Company began a drilling program in the fall of 1996 that included the drilling and completion of the Gonzales No. 7 exploratory well in 1996 and the Gonzales No. 8 development well plus a recompletion of one existing well in 1997. Production from this field, including the Gonzales No. 8 well, averaged 33 MMcf per day gross (25 net) in January 1998. The locations for the Gonzales No. 8 well and the currently drilling Gonzales No. 9 well were identified using three-dimensional ("3-D") seismic data. Because there is an offset operator in the reservoir containing the Gonzales No. 7 and No. 8 wells, the Company has applied to the Texas Railroad Commission for the determination of a fair allocation formula governing allowable production from the reservoir by each operator. On February 24, 1998, the Commission issued a temporary order restricting each operator's production from that reservoir to 25 MMcf per day gross (19 net) until final disposition is made related to the Company's application. The Company's estimated net proved reserve volumes in the Berry R. Cox Field totaled 8.6 Bcfe at December 31, 1997. FRIO/VICKSBURG TREND The Company has 7,667 net acres, including 2,897 net undeveloped acres, under lease in the Frio/Vicksburg Trend. Approximately 24% (36.5 Bcfe) of the Company's U.S. net proved reserve volumes are located in eight producing fields in this trend, primarily the Los Indios, La Reforma and Kent Bayou Fields. The Frio/Vicksburg Trend lies between the Gulf Coast shoreline and the Wilcox Trend. Los Indios and La Reforma Fields. In December 1996, the Company purchased 25% to 50% working interests in portions of the Los Indios and La Reforma Fields, located in Hidalgo and Starr Counties in South Texas, for $15 million. The Company's working interest covers 11,700 gross acres, which is being evaluated using 50 square miles of 3-D seismic data. During 1997, two exploratory wells and two development wells were completed in the La Reforma Field. These two fields produced an average of 5 MMcfe per day net in 1997. Additional drilling is planned in 1998. The Company's estimated net proved reserve volumes in these fields totaled 23 Bcfe at December 31, 1997, an increase of 17% over year-end 1996. Kent Bayou Field. In November 1997, the Company purchased a 73.7% working interest in one producing well and a 100% working interest in 920 acres adjoining the producing unit located in the Kent Bayou Field in Terrebonne Parish, Louisiana. Production for January 1998 averaged 3 MMcf per day gross (1.5 net) of natural gas and 114 barrels per day gross (59 net) of condensate. A 3-D seismic survey is being analyzed to identify potential development locations. The Company's estimated net proved reserve volumes in the Kent Bayou Field totaled 10.5 Bcfe at December 31, 1997. EAST TEXAS BASIN The Company has 16,988 net acres, including 14,064 net undeveloped acres, under lease in the East Texas Basin. The undeveloped acreage is located on prospects in the Cotton Valley Pinnacle Reef play and on prospects targeting various Cretaceous aged objectives. The Company is currently acquiring 3-D seismic surveys to evaluate its acreage holdings. Approximately 14% (21.3 Bcfe) of the Company's U.S. net proved reserve volumes are in this basin, which is located in the northeastern part of Texas. Oak Hill, Woodlawn and Carthage Fields. In December 1997, the Company purchased interests in three natural gas fields in East Texas from private interests for approximately $5.1 million. The properties included 7 10 interests in the Oak Hill Field in Rusk County, the Woodlawn Field in Harrison County and the Carthage Field in Panola County. The Company purchased an average 90% working interest in seven mature producing wells and approximately 3,500 net acres. The Company serves as operator of these properties. Under current spacing rules regulating development of these fields, approximately 30 infill drilling locations have been identified. A drilling program in these fields commenced during the first quarter of 1998. The Company's estimated net proved reserves in these fields totaled 21 Bcfe at December 31, 1997. Production during January 1998 averaged approximately 1.3 MMcfe per day gross (0.9 net). VAL VERDE BASIN The Company has 94,761 net acres, primarily undeveloped, under lease in the Val Verde Basin in Edwards and Val Verde Counties, Texas. Approximately 10% (14.3 Bcfe) of the Company's U.S. net proved reserve volumes are in this basin, which is located in the southwestern part of Texas. Vinegarone East Field. The Company discovered the Vinegarone East Field, located in Edwards County, Texas, in 1996. The Company's working interests range from 75% to 100%. A second exploration well and two development wells were completed in this field during 1997. The field began production in September 1997 following completion of a 10-mile, 6-inch gathering line. Production from this field averaged 8 MMcf per day net during the last four months of 1997 and 9.5 MMcf per day net during the first two months of 1998. Additional development wells are planned in 1998. The Company's estimated net proved reserves in this field totaled 14 Bcfe at December 31, 1997. RESERVES The following table shows the estimated net proved reserves, based on evaluations audited by Netherland, Sewell & Associates, Inc., and gross producing wells for each of the Company's U.S. fields:
DECEMBER 31, 1997 DECEMBER 31, 1996 ------------------------------------------- ------------------ PRESENT NET PROVED GAS NET PROVED GAS VALUE OF GROSS RESERVES RESERVES PROVED PRODUCTIVE -------------- ------------------ FIELD LOCATION RESERVES(A) WELLS BCFE % BCFE % ----- -------- ------------- ---------- ------ ---- ------- ----- ($ THOUSANDS) Bob West South Texas $ 74,659 63 59.0 39% 88.0 75% Los Indios South Texas 11,751 26 15.3 10 16.8 14 Vinegarone East Southwest Texas 16,457 4 14.3 10 -- -- Kent Bayou South Louisiana 13,749 1 10.5 7 -- -- Oak Hill East Texas 5,389 5 9.9 7 -- -- Berry R. Cox South Texas 14,426 5 8.6 6 2.9 3 La Reforma South Texas 8,558 18 7.7 5 2.8 2 Woodlawn East Texas 3,883 2 6.5 4 -- -- Carthage East Texas 2,740 -- 4.7 3 -- -- Other 15,883 54 13.9 9 7.4 6 -------- --- ----- --- ----- --- $167,495 178 150.4 100% 117.9 100% ======== === ===== === ===== ===
- --------------- (a) Represents the discounted future net cash flows before income taxes. See Note N of Notes to Consolidated Financial Statements in Item 8 for additional information regarding the Company's proved reserves and standardized measure. GAS GATHERING AND TRANSPORTATION The Company owns a 70% interest in the Starr County Gathering System, which consists of two ten-inch diameter pipelines and one twenty-inch diameter pipeline that transport natural gas eight miles from the Bob West Field in South Texas to common carrier pipeline facilities. In addition, the Company owns a 50% interest in the twenty-inch diameter Starr-Zapata Pipe Line, which transports natural gas 26 miles from the Starr County Gathering System to a market hub at Fandango, Texas. The Company does not operate either 8 11 pipeline. During 1997, gross throughput averaged 169 MMcf per day for both the Starr County Gathering System and the Starr-Zapata Pipe Line, with approximately 50% of the throughput consisting of the Company's working interest of Bob West Field production. The Starr County Gathering System receives a transportation fee of $0.06 per Mcf and the Starr-Zapata Pipe Line receives a fee of $0.07 per Mcf for volumes transported. MARKETING The Company's U.S. natural gas production is sold on the spot market and under short-term contracts with a variety of purchasers, including intrastate and interstate pipelines, their marketing affiliates, independent marketing companies and other purchasers who have the ability to move the gas under firm transportation or interruptible agreements. Prices for the Company's natural gas production are subject to regional discounts or premiums tied to regional spot market prices. U.S. ACREAGE AND PRODUCTIVE WELLS The Company holds its U.S. acreage through oil and natural gas leases and lease options. The leases have a variety of primary terms and may require delay rentals to continue the primary term if not productive. The leases may be surrendered by the operator at any time for various reasons, which may include cessation of production, fulfillment of commitments, or failure to make timely payment of delay rentals. The following tables set forth the Company's U.S. gross and net acreage and productive wells at December 31, 1997:
UNDEVELOPED ACREAGE DEVELOPED ACREAGE -------------------- ------------------ LOCATION GROSS NET GROSS NET -------- -------- -------- ------- ------- Val Verde Basin, Southwest Texas............. 98,466 94,401 480 360 East Texas Basin, East Texas................. 56,278 14,064 3,303 2,924 Wilcox Trend, South Texas.................... 37,986 17,147 19,349 5,941 Frio/Vicksburg Trend, South Texas............ 4,034 2,017 10,556 4,538 Frio/Vicksburg Trend, South Louisiana........ 880 880 315 232 ------- ------- ------ ------ Total Leased Acres......................... 197,644 128,509 34,003 13,995 Fee Acres, Various Locations................. 15,838 4,352 338 325 ------- ------- ------ ------ Total Acres................................ 213,482 132,861 34,341 14,320 ======= ======= ====== ======
GAS WELLS OIL WELLS ------------------ ---------------- GROSS NET GROSS NET ------- ------- ------ ------ Productive Wells(a).......................... 168 86.9 10 5.4
- --------------- (a) Includes three gross (1.6 net) gas wells and two gross (1.0 net) oil wells with multiple completions. At December 31, 1997, the Company was participating in the drilling of seven gross (6.3 net) wells. 9 12 U.S. OPERATING STATISTICS The following table summarizes the Company's U.S. exploration and production activities for the years ended December 31, 1997, 1996 and 1995:
1997 1996 1995 ------ ------- -------- Average Daily Net Production: Natural gas (Mcf)................................... 86,052 87,654 114,490 Oil (barrels)....................................... 118 27 1 Total (Mcfe)........................................ 86,760 87,816 114,496 Average Prices: Natural gas ($/Mcf)-- Spot market(a)................................... $ 2.17 $ 1.95 $ 1.34 Average(b)....................................... $ 2.17 $ 2.75 $ 2.57 Oil ($/barrel)...................................... $18.90 $ 21.99 $ 16.82 Average Operating Expenses ($/thousand cubic feet equivalent ("Mcfe")): Lease operating expenses............................ $ 0.20 $ 0.14 $ 0.11 Severance taxes..................................... 0.03 0.03 0.18 ------ ------- -------- Total production costs........................... 0.23 0.17 0.29 Administrative support and other.................... 0.07 0.10 0.06 ------ ------- -------- Total Operating Expenses......................... $ 0.30 $ 0.27 $ 0.35 ====== ======= ======== Depletion ($/Mcfe).................................... $ 0.93 $ 0.79 $ 0.69 Exploratory Wells Drilled(c): Productive -- gross................................. 8.0 4.0 5.0 Productive -- net................................... 6.3 1.7 1.5 Dry holes -- gross.................................. 4.0 2.0 4.0 Dry holes -- net.................................... 2.9 1.0 2.1 Development Wells Drilled(c): Productive -- gross................................. 9.0 15.0 17.0 Productive -- net................................... 5.1 6.3 9.7 Dry holes -- gross.................................. 2.0 1.0 -- Dry holes -- net.................................... 1.0 0.5 --
- --------------- (a) Includes effects of the Company's natural gas commodity price agreements which amounted to losses of $0.05 per Mcf and $0.11 per Mcf in 1997 and 1996, respectively, and a gain of $0.01 per Mcf in 1995 (see Note N of Notes to Consolidated Financial Statements in Item 8). (b) Includes effects in 1996 and 1995 of above-market pricing provisions under a natural gas contract which was terminated effective October 1, 1996 (see Note D of Notes to Consolidated Financial Statements in Item 8). (c) All of the Company's drilling is performed by independent drilling contractors. For further information regarding the Company's U.S. exploration and production operations, see Notes B, C and N of Notes to Consolidated Financial Statements in Item 8. BOLIVIA The Company's Bolivian exploration, development and production operations are located in the Chaco Basin in southern Bolivia near the border of Argentina. The Company has discovered six fields in Bolivia since 1976, five of which have currently estimated proved reserves totaling 366 Bcfe at December 31, 1997. The Company intends to complete additional seismic studies and appraisal wells before assigning proved reserves 10 13 to the sixth field. With gross production of 37 MMcfe per day in 1997, the Company is one of the largest operators in Bolivia. The Company holds four Shared Risk Contracts with Yacimientos Petroliferos Fiscales Bolivianos ("YPFB"), the Bolivian governmental agency responsible for administration of these contracts, covering a total of 879,938 gross acres in Block 18 and Block 20. ACQUISITION In July 1997, the Company purchased the interests held by its former joint venture participant in the then existing two contract blocks, consisting of a 25% interest in Block 18 and a 27.4% interest in Block 20. Upon completion of this purchase, the Company held a 100% interest in both blocks, subject to a farmout agreement discussed below. The purchase price was approximately $20 million, which included working capital and assumption of certain liabilities. The Company's net proved Bolivian reserve volumes increased by approximately 35% as a result of this acquisition. BOLIVIAN HYDROCARBONS LAW In 1996, a new Hydrocarbons Law was passed by the Bolivian government that significantly impacts the Company's operations in Bolivia. The new law, among other matters, granted the Company the option to convert its Contracts of Operation to new Shared Risk Contracts. On November 6, 1997, the Company completed the conversion of its Contracts of Operation into four Shared Risk Contracts. The new contracts, which have an effective date of July 29, 1996, extend the Company's term of operation, provide more favorable acreage relinquishment terms and provide for a more favorable fiscal regime of royalties and taxes. The new contract for Block 18 is extended to the year 2017. The new contracts for Block 20 are extended to the year 2018 for Block 20-Los Suris, which is in the development phase, and to the year 2029 for Block 20-West and Block 20-East, which are in the exploration phase. FARMOUT AGREEMENT A farmout agreement executed June 19, 1997, between the Company and Total Exploration Production Bolivie S.A. ("Total"), an affiliate of Total S.A., covers a portion of Block 20-West. Pursuant to the farmout agreement, Total established a financial guarantee to the Bolivian government to guarantee the performance of exploration work on Block 20-West. Total has the right to drill, at its sole cost, two exploratory wells to earn a 75% interest in the farmout area which consists of 315,000 acres of Block 20-West. If Total drills only one well, Total will earn a 37.5% interest in the farmout area. On December 31, 1997, the Company assigned a 75% interest and operatorship in the farmout area to Total, subject to reversion if Total does not drill two wells. YPF AND YPFB CONTRACT The Company is currently selling all of its natural gas production from Block 18 to YPFB, which in turn sells the natural gas to Yacimientos Petroliferos Fiscales, SA ("YPF"), a publicly-held company based in Argentina. Currently, the Company's sales of natural gas are based on the volume and pricing terms in the contract between YPFB and YPF. The Company has historically provided approximately 20% of the contract volumes required by YPF. The contract to sell gas to YPF expired March 31, 1997 and a contract extension was signed effective April 1, 1997 extending the contract term two years to March 31, 1999, with an option to extend the contract a maximum of one additional year if the pipeline being constructed from Bolivia to Brazil is not complete. In the contract extension, YPF negotiated an 11% reduction in the minimum contract volume that it is required to import from Bolivia, which in turn resulted in a corresponding 11% reduction of the Company's minimum contract volume to 36.9 MMcf per day gross (26.2 net). The contract gas prices fluctuate because they are linked to a monthly average fuel oil price posted in the New York spot market. ACCESS TO NEW MARKETS A lack of market access has constrained natural gas production in Bolivia. With little internal gas demand, all of the Company's Bolivian natural gas production is sold under contract to the Bolivian 11 14 government for export to Argentina. Major developments in South America indicate that new markets will open for the Company's production. Construction of a new 1,900-mile pipeline that will link Bolivia's extensive gas reserves with markets in Brazil commenced in 1997 and is expected to be operational in early 1999. The owners of the new pipeline include Petrobras (the Brazilian state oil company), other Brazilian investors, Enron Corp., Shell International Gas Ltd., British Gas PLC, El Paso Energy Corp., BHP, and Bolivian pension funds. When completed, the new pipeline will have a capacity of approximately 1 billion cubic feet ("Bcf") per day. BLOCK 18 The Company has a 100% working interest in a Shared Risk Contract covering 92,625 acres in Block 18. Approximately 30% (110 Bcfe) of the Company's Bolivian reserve volumes are in the La Vertiente, Escondido and Taiguati Fields of Block 18. During 1997, the Company's net production from this block averaged 19.5 MMcf of gas per day and 518 barrels of condensate per day. A 3-D seismic survey over the Escondido Field was completed in 1997 to identify additional drilling locations. The Block 18 contract provides that the Company will be subject to a 29% royalty to YPFB, and the payment of Bolivian income taxes and taxes on gross revenues equal to 31% of gross revenues, leaving the Company with 40% of Block 18 revenues after royalties and Bolivian taxes. In respect to Block 18, the aftertax effect of the Shared Risk Contract is approximately the same as the previous Contract of Operation. BLOCK 20 The Company has a 100% working interest in two Shared Risk Contracts, Block 20-Los Suris and Block 20-East, and a 25% working interest in a Shared Risk Contract, Block 20-West, which is subject to the provisions of the farmout agreement with Total. Block 20-Los Suris. This contract covers 12,350 acres of the Los Suris Field, where approximately 28% (104.2 Bcfe) of the Company's Bolivian reserve volumes are located. Although this contract is in the development phase, existing wells are shut-in awaiting access to markets. A 3-D seismic survey over Block 20-Los Suris was completed in 1997 to identify additional drilling locations. Block 20-East. This contract, which is in the exploration phase, covers 385,938 acres and includes the Palo Marcado Field, where approximately 42% (152.1 Bcfe) of the Company's proved Bolivian reserves are located. A 3-D seismic survey was completed over the Palo Marcado Field in 1997 to identify additional drilling locations. Block 20-West. This contract covers 389,025 acres, of which 315,000 acres are subject to the Total farmout agreement, and extends into the difficult terrain of the Andes mountains. Total has contracted, at its sole cost, for the drilling of the first well under the farmout agreement and it is anticipated that this well will spud by mid-1998. The drilling cost in this area can exceed $20 million per well due to the mountainous location and depth of the objective. The previous Block 20 Contract of Operation provided for Bolivian taxes equal to 31% of gross revenues and a royalty of 19% to YPFB. Under the Shared Risk Contracts, a combination of Bolivian income taxes and taxes on gross revenues are expected to approximate the 31% gross revenue tax in the previous Contract of Operation and the 19% royalty to YPFB has been eliminated. 12 15 RESERVES The table below shows the estimated proved reserves, based on evaluations prepared by Netherland, Sewell & Associates, Inc., and productive wells for each of the Company's Bolivian fields. Each of the following fields is operated by the Company:
DECEMBER 31, DECEMBER 31, 1997 1996 ----------------------------------------------------------------- ----------------- NET PROVED RESERVES -------------------------------- OIL (MILLIONS PRODUCTIVE OF GAS TOTAL PV-10 AFTER PV-10 AFTER FIELD BLOCK WELLS BARRELS) (BCF) (BCFE) % BOLIVIAN TAXES(A) BOLIVIAN TAXES(A) ----- ----- ---------- --------- ----- ------ --- ----------------- ----------------- ($ THOUSANDS) ($ THOUSANDS) Palo Marcado......... 20 2 2.0 140.1 152.1 42% $ 38,871 $24,667 Los Suris............ 20 2 1.1 97.6 104.2 28 32,685 13,135 Escondido............ 18 4 1.6 78.0 87.6 24 23,926 23,330 La Vertiente......... 18 4 0.5 19.0 22.0 6 5,971 3,090 Taiguati............. 18 1 -- 0.4 0.4 -- -- 221 -- --- ----- ----- --- -------- ------- 13 5.2 335.1 366.3 100% $101,453 $64,443 == === ===== ===== === ======== =======
- --------------- (a) Represents the discounted future net cash flows after Bolivian taxes. See Note N of Notes to Consolidated Financial Statements in Item 8 for additional information regarding the Company's proved reserves and standardized measure. BOLIVIAN ACREAGE AND PRODUCTIVE WELLS The following table sets forth the Company's Bolivian gross and net acreage and productive wells at December 31, 1997:
GROSS NET ------- ------- Acreage: Developed................................................. 92,625 92,625 Undeveloped............................................... 787,313 551,063 Productive Gas Wells(a)..................................... 13 13
- --------------- (a) Included in productive gas wells are five gross (five net) wells with multiple completions. The Company has no producing oil wells in Bolivia. 13 16 BOLIVIA OPERATING STATISTICS The following table summarizes the Company's Bolivian exploration and production activities for the years ended December 31, 1997, 1996 and 1995:
1997 1996 1995 ------- ------- ------- Average Daily Net Production: Natural gas (Mcf)................................... 19,537 20,251 18,650 Condensate (barrels)................................ 518 584 567 Total (Mcfe)........................................ 22,645 23,755 22,052 Average Price: Natural gas ($/Mcf)................................. $ 1.15 $ 1.33 $ 1.28 Condensate ($/barrel)............................... $ 15.71 $ 17.98 $ 14.39 Average Operating Expenses ($/Mcfe): Production costs.................................... $ 0.11 $ 0.10 $ 0.07 Value-added taxes................................... -- 0.05 0.06 Administrative support and other.................... 0.31 0.27 0.35 ------- ------- ------- Total Operating Expenses......................... $ 0.42 $ 0.42 $ 0.48 ======= ======= ======= Depletion ($/Mcfe).................................... $ 0.19 $ 0.15 $ 0.03 Exploratory Wells Drilled: Productive -- gross................................. -- 2.0 1.0 Productive -- net................................... -- 1.5 0.7 Dry holes -- gross.................................. -- -- -- Dry holes -- net.................................... -- -- --
For further information regarding the Company's Bolivian operations, see Notes B, C and N of Notes to Consolidated Financial Statements in Item 8. WORLDWIDE RESERVE REPLACEMENT AND COSTS OF ADDING RESERVES In 1997, the Company's worldwide net proved reserve additions included 156 Bcfe from discoveries, extensions and purchases of proved properties (89 Bcfe in Bolivia and 67 Bcfe domestically) and 30 Bcfe from revisions of previous estimates. Excluding revisions, 156 Bcfe were added for a 390% replacement of 40 Bcfe of production. Additions were realized with a 74% drilling success rate during 1997, reflecting an 82% success rate on 11 development wells and a 67% success rate on 12 exploratory wells. The Company's three-year worldwide average cost of adding these reserves was $0.43 per Mcfe. Domestically, 67 Bcfe were added through discoveries, extensions and acquisitions for a 209% replacement of 32 Bcfe of production. In Bolivia, 89 Bcfe were added through an acquisition, a more than tenfold replacement of 8 Bcfe of production. The three-year average cost of adding reserves was $0.85 per Mcfe in the U.S. and $0.14 per Mcfe in Bolivia. See Note N of Notes to Consolidated Financial Statements in Item 8. MARINE SERVICES OVERVIEW The Company's Marine Services segment markets and distributes a broad range of products, including diesel fuel, lubricants, chemicals and supplies, and provides logistical support services to the marine and offshore exploration and production industries operating in the Gulf of Mexico. These operations were conducted in 1997 through a network of 18 marine and two land terminals located on the Texas Gulf Coast in Galveston, Freeport, Harbor Island, Port O'Connor, Sabine Pass, Channelview and Houston and along the Louisiana Gulf Coast in Cameron, Intracoastal City, Berwick, Venice, Port Fourchon, Amelia and Harahan. The marine terminals are generally deep water and are bulkheaded and dredged to provide easy access to vessels receiving products for delivery to customers. Products are delivered offshore aboard vessels owned or chartered by customers, which include companies engaged in oil and gas exploration and production, seismic 14 17 evaluation, offshore construction and other drilling-related businesses. In January 1998, the Marine Services operations were expanded to include the operations of three terminals located on the U.S. West Coast, previously operated by the Company's Refining and Marketing segment (see "Refining and Marketing -- Marketing Outside of Alaska" discussed above). FUELS AND LUBRICANTS Fuels and lubricants, which are used by operations such as offshore drilling rigs, offshore production and transmission platforms and various ships and equipment engaged in seismic surveys, are marketed and distributed from the Company's terminals. These terminals and a fleet of seven tugboats (including five owned by the Company) and 14 barges (including 12 owned by the Company) serve offshore workboats, tugboats and barges using the Intracoastal Canal System, as well as ships entering the ports of Houston, New Orleans, Lake Charles, Corpus Christi and Port Arthur. Tesoro obtains its supply of fuel from refiners in the Gulf Coast area. Total gallons of fuel, primarily diesel fuel, sold by Marine Services amounted to 156.4 million, 142.7 million and 112.5 million in 1997, 1996 and 1995, respectively. The Company is a distributor of major brands of marine lubricants and greases, offering a full spectrum of grades. Lubricants are delivered to customers by trucks or tugs and barges. Total gallons of lubricants sold by Marine Services amounted to 2.7 million, 2.3 million and 2.5 million in 1997, 1996 and 1995, respectively. LOGISTICAL SERVICES Through many of its terminals, the Company provides full-service shore-based support for offshore drilling rigs and production platforms. These quayside services provide cranes, forklifts and loading docks for supply boats serving the offshore exploration and production industry. In addition, the Company provides long-term parking for offshore workers, helicopter landing pads and office space with living quarters. Tesoro terminals also serve as delivery points for drilling products, primarily mud, by providing warehousing, blending, inventory control and delivery services. In 1997, 1996 and 1995, revenues from these logistical services were $11.3 million, $8.7 million and $0.6 million, respectively. COMPETITION AND OTHER The petroleum industry is highly competitive in all phases, including the refining of crude oil, the marketing of refined petroleum products, the search for and development of oil and gas reserves and the marine services business. The industry also competes with other industries that supply the energy and fuel requirements of industrial, commercial and individual consumers. The Company competes with a substantial number of major integrated oil companies and other companies having materially greater financial and other resources than the Company. These competitors have a greater ability to bear the economic risks inherent in all phases of the industry. In addition, unlike the Company, many of its competitors produce large volumes of crude oil which can then be used in connection with their refining operations. The North American Free Trade Agreement has further streamlined and simplified procedures for the importation and exportation of natural gas among Mexico, the United States and Canada. These changes are likely to enhance the ability of Canadian and Mexican producers to export natural gas and other products to the United States, thereby further increasing competition for domestic sales. The refining and marketing businesses are highly competitive, with price being the principal factor in competition. In the refining industry, the Kenai Refinery competes primarily with other refineries in Alaska and on the U.S. West Coast. The Company's refining competition in Alaska includes two refineries situated near Fairbanks and one refinery situated near Valdez. The Company estimates that such other refineries have a combined capacity to process approximately 184,000 barrels per day of crude oil. The Company believes that ANS crude oil is the only feedstock used in these competing refineries. After processing the crude oil and removing the lighter-end products, which the Company believes represent approximately 30% of each barrel processed, these refiners are permitted, because of their direct connection to the TAPS, to return the remainder of the processed crude back into the pipeline system as "return oil" in consideration for a fee, thereby eliminating their need to market residual products. The Kenai Refinery is not directly connected to 15 18 the TAPS, and the Company, therefore, cannot return its residual products to the TAPS. The Company's refining competition from the U.S. West Coast includes many large, integrated oil companies that do substantial business in Alaska and have materially greater financial and other resources. The Company is a major producer and distributor of gasoline in Alaska through a large network of Company-operated stations and branded and unbranded dealers and jobbers. The Company is also a supplier to a major oil company through a product exchange agreement, whereby gasoline in Alaska is provided in exchange for gasoline delivered to the Company on the U.S. West Coast. Competitive factors affecting the marketing of gasoline in Alaska include such factors as product price, location and quality together with station appearance and brand-name identification. The Company competes with other petroleum companies, distributors and other developers for new locations. Tesoro believes it is in a position to compete effectively as a marketer of gasoline because of its strong presence in its core Alaska market. The Company's jet fuel sales are concentrated in Anchorage, where it is one of the principal suppliers to the Anchorage International Airport, which is a major hub for air cargo traffic between manufacturing regions in the Far East and consuming regions in the United States and Europe. The Company sells its diesel fuel primarily on a wholesale basis. Refined products from foreign sources also compete for distillate markets in the Company's Alaskan market area. The Company's Pacific Northwest marketing business is primarily a distribution business selling to independent dealers and jobbers. In addition, the Company sells its gasoline through 30 branded gasoline stations in the Pacific Northwest. The Company competes against independent marketing companies and integrated oil companies when engaging in these marketing operations. The exploration for and production of natural gas and oil is highly competitive in both the United States and in South America. In seeking to acquire producing properties, new leases, concessions and exploration prospects, the Company faces competition from both major and independent oil and natural gas companies. Many of these competitors have financial and other resources substantially in excess of those available to the Company and, therefore, may be better positioned to acquire and develop prospects, hire personnel and market production. The larger competitors may also be able to better respond to factors that influence the market for oil and natural gas production, such as changes in worldwide prices and governmental regulations. Such factors are beyond the control of the Company. The Company's natural gas production in Bolivia is sold under contract to YPFB, which in turn exports the natural gas to Argentina, as the internal demand for natural gas in Bolivia is limited. The Company believes that the completion of a 1,900-mile pipeline from Bolivia to Brazil will provide access to larger gas-consuming markets. The owners of the new pipeline include Petrobras (the Brazilian state oil company), other Brazilian investors, Enron Corp., Shell International Gas Ltd., British Gas PLC, El Paso Energy Corp., BHP, and Bolivian pension funds. Upon completion of this pipeline, the Company will face intense competition from major and independent natural gas companies operating in Bolivia for a share of the contractual volumes to be exported to Brazil. It is anticipated that each producer's share of the contractual volumes will be allocated by YPFB according to a number of factors, including each producer's reserve volumes and production capacity. Although the Company expects gas deliveries on the pipeline to begin in early 1999, there can be no assurance that the pipeline will be operational by such date. With the exception of the volumes currently under contract with the Bolivian government, the Company cannot be assured of the amount of additional volumes that will be exported to Brazil upon completion of the pipeline. Demand for services and products offered by the Company's Marine Services segment is closely related to the level of oil and gas exploration, development and production in the Gulf of Mexico. Various factors, including general economic conditions, demand for and prices of natural gas, availability of equipment and materials and government regulations and energy policies cause exploration and development activity to fluctuate and directly impact the revenues of the Marine Services segment. Management believes that the principal competitive factors affecting the Marine Services operations are location of facilities, availability of logistical support services, experience of personnel and dependability of service. The market for the Marine Services segment's products and services, particularly diesel fuel, is price sensitive. The Company competes 16 19 with several independent operations, and in certain locations with one or more major mud companies who maintain their own marine terminals. A portion of the Company's operations are conducted in foreign countries where the Company is also subject to risks of a political nature and other risks inherent in foreign operations. The Company's operations outside the United States in recent years have been, and in the future may be, materially affected by host governments through increases or variations in taxes, royalty payments, export taxes and export restrictions and adverse economic conditions in the foreign countries, the future effects of which the Company is unable to predict. GOVERNMENT REGULATION AND LEGISLATION UNITED STATES Natural Gas and Oil Regulations. Historically, all domestic natural gas sold in so-called "first sales" was subject to federal price regulations under the Natural Gas Policy Act of 1978 ("NGPA"), the Natural Gas Act ("NGA") and the regulations and orders issued by the Federal Energy Regulatory Commission ("FERC") in implementing such Acts. Under the Natural Gas Wellhead Decontrol Act of 1989, all remaining federal natural gas wellhead pricing and sales regulation was terminated on January 1, 1993. The FERC also regulates interstate natural gas pipeline transportation rates and service conditions, which affect the marketing of gas produced by the Company, as well as the revenues received by the Company for sales of such gas. Since the latter part of 1985, through a series of orders, the FERC has endeavored to make natural gas transportation more accessible to gas buyers and sellers on an open and non-discriminatory basis, and the FERC's efforts have significantly altered the marketing and pricing of natural gas. These orders have gone through various permutations, but have generally remained intact as promulgated. The FERC considers these changes necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put gas sellers into more direct contractual relations with gas buyers than has historically been the case. The result of the changes has brought to an end the interstate pipelines' traditional role as wholesalers of natural gas in favor of providing only gathering, transportation and storage services for others which will buy and sell natural gas. Although these orders do not directly regulate gas producers, such as the Company, they are intended to foster increased competition within all phases of the natural gas industry. It is unclear what impact, if any, increased competition within the natural gas industry will have on the Company and its gas sales efforts. Several aspects of these orders are still being reviewed by the courts and the FERC. It is not possible to predict what, if any, effect these proceedings will have on the Company. The Company does not believe, however, that it will be affected any differently than other gas producers or marketers with which it competes. The oil and gas exploration and production operations of the Company are subject to various types of regulation at the state and local levels. Such regulation includes requiring drilling permits and the maintenance of bonds in order to drill or operate wells; the regulation of the location of wells; the method of drilling and casing of wells and the surface use and restoration of properties upon which wells are drilled; and the plugging and abandoning of wells. The operations of the Company are also subject to various conservation regulations, including regulation of the size of drilling and spacing units or proration units, the density of wells that may be drilled in a given area and the unitization or pooling of oil and gas properties. In this regard, some states allow the forced pooling or integration of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of crude oil, condensate and natural gas the Company can produce from its wells and the number of wells or the locations at which the Company can drill. Additional proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, the FERC, state regulatory bodies and the courts. The Company cannot predict when or if any such proposals might become effective, or their effect, if any, on the Company's operations. 17 20 Environmental Controls. Federal, state, area and local laws, regulations and ordinances relating to the protection of the environment affect all operations of the Company to some degree. An example of a federal environmental law that will require operational additions and modifications is the Clean Air Act, which was amended in 1990. While the Company believes that its facilities generally are in substantial compliance with current regulatory standards for air emissions, over the next several years the Company's facilities will be required to comply with the new requirements being adopted and promulgated by the U.S. Environmental Protection Agency ("EPA") and the states in which the Company operates. These regulations will necessitate the installation of additional controls or other modifications or changes in use for certain emission sources, such as gasoline tank roof seal replacements at the Kenai Refinery. Specifics as to the cost of these requirements at certain facilities are still being determined. As part of these requirements, the Kenai Refinery as well as some other Company facilities submitted applications for Clean Air Act Amendment Title V permits in 1997. Each application was subsequently deemed complete by the State of Alaska and will undergo technical review in 1998. The Company believes it can comply with these new requirements, and in some cases already has done so, without adversely affecting operations. The passage of the Federal Clean Air Act Amendments of 1990 prompted adoption of regulations by the State of Alaska obligating the Company to produce oxygenated gasoline for delivery to the Anchorage and Fairbanks, Alaska markets starting on November 1, 1992. Controversies surrounding the potential health effects in Arctic regions of oxygenated gasoline containing methyl tertiary butyl ether ("MTBE") prompted early discontinuance of the program in Fairbanks. The EPA has been directed to conduct studies of potential health effects of oxygenated fuel in Alaska. The State of Alaska mandated the use of oxygenated fuels containing ethanol in the Anchorage area. No requirements for use of such products in Fairbanks have been issued, but are expected. Additional federal regulations promulgated on August 21, 1990, which went into effect on October 1, 1993, set limits on the quantity of sulphur in on-highway diesel fuels which the Company produces. The State filed an application with the federal government in February 1993 for a waiver from this requirement since only 5% of the diesel fuel sold in Alaska was for on-highway vehicles. On March 14, 1994, the EPA granted the State of Alaska a waiver from the requirements of the EPA's low sulphur diesel fuel program, permanently exempting Alaska's remote areas and providing a temporary exemption for areas served by the Federal Aid Highway System until October 1, 1996. On August 19, 1996, the EPA extended the temporary exemption until October 1, 1998. The Company estimates that substantial capital expenditures would be required to enable the Company to produce low-sulphur diesel fuel to meet these federal regulations. If the State is unable to obtain a permanent waiver from the federal regulations, the Company would discontinue sales of diesel fuel for on-highway use after October 1, 1998. The Company estimates that such sales accounted for less than 1% of its refined product sales in Alaska during 1997. While the Company is unable to predict the outcome of these matters, their ultimate resolution should not have a material impact on its operations. Oil Spill Prevention and Response. The Federal Oil Pollution Act of 1990 ("OPA 90") and related state regulations require most refining, transportation and oil storage facilities to prepare oil spill prevention contingency plans for use during an oil spill response. The Company has prepared and submitted these plans for approval and, in most cases, has received federal and state approvals necessary to meet various regulations and to avoid the potential of negative impacts on the operation of its facilities. The Company currently charters tankers to transport crude oil from the Valdez, Alaska pipeline terminal through Prince William Sound and Cook Inlet to the Kenai Refinery. In addition, the Company routinely charters, on a long-term and short-term basis, additional tankers and barges for shipment of crude oil and refined products through Cook Inlet, as well as other locations. OPA 90 requires, as a condition of operation, that the Company demonstrate the capability to respond to the "worst case discharge" to the maximum extent practicable. Alaska law requires the Company to provide spill-response capability to contain or control, and clean-up within 72 hours, an amount equal to (i) 50,000 barrels for a tanker carrying fewer than 500,000 barrels of crude oil or (ii) 300,000 barrels for a tanker carrying more than 500,000 barrels. To meet these requirements, the Company has entered into a contract with Alyeska Pipeline Service Company ("Alyeska") to provide initial spill response services in Prince William Sound, with the Company later to assume those responsibilities after mutual agreement with Alyeska and State and Federal On-Scene Coordinators. The 18 21 Company has also entered into an agreement with Cook Inlet Spill Prevention and Response, Incorporated for oil spill response services in Cook Inlet. The Company believes these contracts provide for the additional services necessary to meet spill response requirements established by Alaska and federal law. Transportation, storage and refining of crude oil in Alaska result in the greatest regulatory impact, with respect to oil spill prevention and response. Oil transportation and terminaling operations at other Company facilities also result in compliance mandates for oil spill prevention and response. The Company contracts with various oil spill response cooperatives or local contractors to provide necessary oil spill response capabilities which may be required on a location by location basis. Regulations promulgated by the Alaska Department of Environmental Conservation ("ADEC") would have required the installation of dike liners in secondary containment systems for petroleum storage tanks by January 1997. However, on December 18, 1996, ADEC approved the Company's alternative compliance schedule which allows the Company until the year 2002 to implement alternative secondary containment systems for all of the Company's existing petroleum storage tank facilities. The total estimated cost of these improvements is approximately $9 million, which is expected to be spent over a five-year period beginning in 1998. Underground Storage Tanks. Regulations promulgated by the EPA on September 23, 1988, require that all underground storage tanks used for storing gasoline or diesel fuel either be closed or upgraded not later than December 22, 1998, in accordance with standards set forth in the regulations. The Company's service stations subject to the upgrade requirements are limited to locations in Alaska. The Company is required to make expenditures, that are expected to cost approximately $1 million, for removal or upgrading of underground storage tanks at several of its current and former service stations by December 22, 1998. Total Environmental Expenditures. The Company's total capital expenditures for environmental control purposes were $2.2 million during 1997. Capital expenditures for the alternative secondary containment systems discussed above are estimated to be $2 million in 1998 and $2 million in 1999 with the remaining $5 million to be spent by 2002. Capital expenditures for other environmental control purposes are estimated to be $7 million in 1998 and $2 million in 1999. For further information regarding environmental matters, see "Legal Proceedings" in Item 3 and "Environmental Controls", "Oil Spill Prevention and Response" and "Underground Storage Tanks" discussed above. BOLIVIA The Company's operations in Bolivia are subject to the Bolivian Hydrocarbons Law and various other laws and regulations. In the Company's opinion, neither the Hydrocarbons Law nor other requirements currently imposed by Bolivian laws, regulations and practices will have a material adverse effect upon its Bolivian operations. For information on the Bolivian Hydrocarbons Law and Bolivian taxation, see "Exploration and Production -- Bolivia" discussed above. EMPLOYEES At December 31, 1997, the Company employed approximately 1,100 persons, of which approximately 40 were located in foreign countries. None of the Company's employees are represented by a union. The Company considers its relations with its employees to be satisfactory. 19 22 EXECUTIVE OFFICERS OF THE REGISTRANT The following is a list of the Company's executive officers, their ages and their positions with the Company at February 27, 1998.
NAME AGE POSITION POSITION HELD SINCE ---- --- -------- ------------------- Bruce A. Smith.......... 54 Chairman of the Board of Directors, President and Chief Executive Officer June 1996 William T. Van Kleef.... 46 Executive Vice President, Operations September 1996 James C. Reed, Jr....... 53 Executive Vice President, General Counsel and Secretary September 1995 Donald A. Nyberg........ 46 President, Tesoro Marine Services, Inc. November 1996 Robert W. Oliver........ 43 President, Tesoro Exploration and Production Company September 1995 Stephen L. Wormington... 53 President, Tesoro Alaska Petroleum Company September 1995 Don E. Beere............ 57 Vice President, Controller April 1992 Thomas E. Reardon....... 51 Vice President, Human Resources and Environmental September 1995 Gregory A. Wright....... 48 Vice President and Treasurer September 1995
There are no family relationships among the officers listed, and there are no arrangements or understandings pursuant to which any of them were elected as officers. Officers are elected annually by the Board of Directors at its first meeting following the Annual Meeting of Stockholders, each to hold office until the corresponding meeting of the Board in the next year or until a successor shall have been elected or shall have qualified. All of the Company's executive officers have been employed by the Company or its subsidiaries in an executive capacity for at least the past five years, except for those named below who have had the business experience indicated during that period. Positions, unless otherwise specified, are with the Company.
William T. Van Kleef.... Executive Vice President, Operations since September 1996. Senior Vice President and Chief Financial Officer from September 1995 to September 1996. Vice President, Treasurer from March 1993 to September 1995. Independent financial consultant from January 1992 to February 1993. Donald A. Nyberg........ President of Tesoro Marine Services, Inc., a subsidiary of the Company, since November 1996. Vice President, Strategic Planning, of MAPCO Inc. from January 1996 to November 1996. President and Chief Executive Officer of Marya Resources from August 1994 to January 1996. President and Chief Executive Officer of BP Pipelines Inc. and Vice President, BP Exploration, of The British Petroleum Group, Ltd., from 1991 to 1994. Robert W. Oliver........ President of Tesoro Exploration and Production Company, a subsidiary of the Company, since September 1995. Independent consultant from November 1994 to September 1995. Vice President, Exploration/ Acquisitions, of Bridge Oil (USA) Inc. from December 1988 to November 1994.
20 23
Stephen L. Wormington... President of Tesoro Alaska Petroleum Company, a subsidiary of the Company, since September 1995. Vice President, Supply and Operations Coordination, of Tesoro Alaska Petroleum Company from April 1995 to September 1995. General Manager, Strategic Projects, from January 1995 to April 1995. Executive Vice President, Special Projects, of MG Refining & Marketing, Inc. from January 1994 to January 1995. Executive Vice President of MG Natural Gas Corp. from May 1992 to January 1994. Thomas E. Reardon....... Vice President, Human Resources and Environmental since September 1995. Vice President, Human Resources and Environmental Services of Tesoro Petroleum Companies, Inc., a subsidiary of the Company, from October 1994 to September 1995. Vice President, Human Resources of Tesoro Petroleum Companies, Inc. from February 1990 to October 1994. Gregory A. Wright....... Vice President and Treasurer since September 1995. Vice President, Corporate Communications from February 1995 to September 1995. Vice President, Corporate Communications of Tesoro Petroleum Companies, Inc., a subsidiary of the Company, from January 1995 to February 1995. Vice President, Business Development of Valero Energy Corporation from 1994 to January 1995. Vice President, Corporate Planning of Valero Energy Corporation from 1992 to 1994.
ITEM 2. PROPERTIES See information appearing under Item 1, Business herein and Notes B, C and N of Notes to Consolidated Financial Statements in Item 8. ITEM 3. LEGAL PROCEEDINGS The Company, along with numerous other parties, 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 ("CERCLA") for the Mud Superfund site in Abbeville, Louisiana ("Site"). The Company arranged for the disposal of a minimal amount of materials at the Site, but CERCLA might impose joint and several liability on each PRP at the Site. The EPA is seeking reimbursement for its response costs incurred to date at the Site, as well as a commitment from the PRPs either to conduct future remedial activities or to finance such activities. The extent of the Company's allocated financial contributions to the cleanup of the site is expected to be limited based upon the number of companies, volumes of waste involved, and an estimated total cost of approximately $500,000 among all of the parties to close the Site. The Company is currently involved in settlement discussions with the EPA and other PRPs involved at the Site. The Company expects, based on these discussions, that its liability at the Site will not exceed $25,000. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. 21 24 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The Company's Common Stock is listed under the symbol "TSO" on the New York Stock Exchange and the Pacific Stock Exchange. The per share market price ranges for the Company's Common Stock on the New York Stock Exchange during 1997 and 1996 are summarized below:
1997 1996 ---------------------- ---------------------- QUARTERS ENDED HIGH LOW HIGH LOW -------------- ---- --- ---- --- March 31..................................... $14 1/2 $10 3/8 $9 1/8 $ 8 June 30...................................... $15 $10 1/4 $11 5/8 $8 1/4 September 30................................. $18 3/16 $14 3/4 $13 1/2 $10 1/2 December 31.................................. $18 3/16 $15 $15 1/2 $12 7/8
At February 27, 1998, there were approximately 3,500 holders of record of the Company's 26,661,845 outstanding shares of Common Stock. The Company has not paid dividends on its Common Stock since 1986. For information regarding restrictions on future dividend payments, see Management's Discussion and Analysis of Financial Condition and Results of Operations in Item 7 and Note I of Notes to Consolidated Financial Statements in Item 8. The Board of Directors has no present plans to pay dividends. However, from time to time, the Board of Directors reevaluates the feasibility of declaring future dividends. 22 25 ITEM 6. SELECTED FINANCIAL DATA The selected consolidated financial data should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations in Item 7 and the Company's Consolidated Financial Statements, including the notes thereto, in Item 8.
YEARS ENDED DECEMBER 31, ----------------------------------------------- 1997 1996 1995 1994 1993 ------- -------- -------- ------ ------ (DOLLARS IN MILLIONS EXCEPT PER SHARE AMOUNTS) REVENUES Gross Operating Revenues: Refining and Marketing Refined products.................................... $ 643.7 $ 620.8 $ 664.5 $582.7 $590.9 Other, primarily crude oil resales and merchandise....................................... 77.2 124.6 106.5 104.3 96.3 Exploration and Production U.S.(a)............................................. 73.6 93.8 113.0 90.6 49.4 Bolivia............................................. 11.2 13.7 11.7 13.2 12.6 Marine Services(b).................................... 132.2 122.5 74.5 77.9 80.7 ------- -------- -------- ------ ------ Total Gross Operating Revenues...................... 937.9 975.4 970.2 868.7 829.9 Income from Settlement of a Natural Gas Contract and Other(a).............................................. 5.5 64.4 32.7 3.2 0.5 ------- -------- -------- ------ ------ Total Revenues...................................... $ 943.4 $1,039.8 $1,002.9 $871.9 $830.4 ======= ======== ======== ====== ====== SEGMENT OPERATING PROFIT (LOSS)(C) Refining and Marketing................................ $ 20.5 $ 6.0 $ 0.7 $ 2.4 $ 15.2 Exploration and Production U.S.(a)............................................. 37.3 123.9 102.0 55.0 32.3 Bolivia............................................. 8.6 8.8 7.6 9.3 8.4 Marine Services(b).................................... 6.3 6.1 (4.4) (2.3) (3.6) ------- -------- -------- ------ ------ Total Segment Operating Profit...................... $ 72.7 $ 144.8 $ 105.9 $ 64.4 $ 52.3 ======= ======== ======== ====== ====== EARNINGS BEFORE EXTRAORDINARY ITEM...................... $ 30.7 $ 76.8 $ 57.5 $ 20.5 $ 17.0 EXTRAORDINARY LOSS ON DEBT EXTINGUISHMENTS, NET OF INCOME TAXES(D)................................ -- (2.3) (2.9) (4.8) -- ------- -------- -------- ------ ------ NET EARNINGS............................................ $ 30.7 $ 74.5 $ 54.6 $ 15.7 $ 17.0 ======= ======== ======== ====== ====== NET EARNINGS APPLICABLE TO COMMON STOCK................. $ 30.7 $ 74.5 $ 54.6 $ 13.0 $ 7.8 ======= ======== ======== ====== ====== NET EARNINGS PER SHARE -- BASIC(E)...................... $ 1.16 $ 2.87 $ 2.22 $ 0.58 $ 0.55 NET EARNINGS PER SHARE -- DILUTED(E).................... $ 1.14 $ 2.81 $ 2.18 $ 0.56 $ 0.54 WEIGHTED AVERAGE COMMON SHARES -- BASIC................. 26.4 26.0 24.6 22.6 14.1 WEIGHTED AVERAGE COMMON SHARES AND POTENTIALLY DILUTIVE COMMON SHARES -- DILUTED.............................. 26.9 26.5 25.1 23.2 14.3 EBITDA, CONSOLIDATED(F)................................. $ 102.2 $ 172.0 $ 125.4 $ 80.8 $ 55.8 CASH FLOWS FROM (USED IN) Operations............................................ $ 95.6 $ 178.9 $ 35.4 $ 60.3 $ 21.8 Investing............................................. (151.5) (94.2) 2.4 (91.2) (23.4) Financing............................................. 41.5 (75.9) (37.8) 8.3 (8.7) ------- -------- -------- ------ ------ Increase (Decrease) in Cash and Cash Equivalents.... $ (14.4) $ 8.8 $ -- $(22.6) $(10.3) ======= ======== ======== ====== ====== CAPITAL EXPENDITURES Refining and Marketing................................ $ 43.9 $ 11.1 $ 9.3 $ 32.0 $ 7.1 Exploration and Production U.S................................................. 65.4 59.7 49.6 65.6 29.3 Bolivia............................................. 27.5 6.9 3.8 -- -- Marine Services....................................... 9.4 6.9 0.4 0.2 0.3 Other................................................. 1.3 0.4 0.8 1.8 0.8 ------- -------- -------- ------ ------ Total Capital Expenditures.......................... $ 147.5 $ 85.0 $ 63.9 $ 99.6 $ 37.5 ======= ======== ======== ====== ======
23 26
YEARS ENDED DECEMBER 31, ----------------------------------------------- 1997 1996 1995 1994 1993 ------- -------- -------- ------ ------ (DOLLARS IN MILLIONS EXCEPT PER SHARE AMOUNTS) BALANCE SHEET Current Assets........................................ $ 181.8 $ 237.3 $ 182.5 $182.1 $196.5 Property, Plant and Equipment, Net.................... $ 413.8 $ 316.5 $ 261.7 $273.3 $213.2 Total Assets.......................................... $ 627.8 $ 582.6 $ 519.2 $484.4 $434.5 Current Liabilities................................... $ 107.5 $ 137.8 $ 105.0 $ 96.2 $ 72.0 Long-Term Debt and Other Obligations, Less Current Maturities(d)(g).................................... $ 115.3 $ 79.3 $ 155.0 $192.2 $180.7 Redeemable Preferred Stock(g)......................... $ -- $ -- $ -- $ -- $ 78.1 Stockholders' Equity(g)(h)............................ $ 333.0 $ 304.1 $ 216.5 $160.7 $ 58.5 Current Ratio......................................... 1.69:1 1.72:1 1.74:1 1.89:1 2.73:1 Working Capital....................................... $ 74.3 $ 99.5 $ 77.5 $ 85.9 $124.5 Long-Term Debt and Redeemable Preferred Stock to Capitalization(d)(g)....................... 26% 21% 42% 54% 82% Common Stock Outstanding (millions)(g)................ 26.3 26.4 24.8 24.4 14.1 Book Value Per Common Share........................... $ 12.66 $ 11.51 $ 8.74 $ 6.59 $ 1.81
- --------------- (a) Results for 1996, 1995, 1994 and 1993 include revenues from above-market pricing provisions of a natural gas contract which was terminated effective October 1, 1996. Operating profit included $25 million, $47 million, $39 million and $20 million in 1996, 1995, 1994 and 1993, respectively, from the excess of these contract prices over spot market prices. Upon termination of the contract, the Exploration and Production segment recorded other income and operating profit of $60 million. In 1995, the Exploration and Production segment recorded other income and operating profit of $33 million from the sale of certain interests in the Bob West Field. See Notes C and D of Notes to Consolidated Financial Statements in Item 8. (b) Beginning in February 1996, the Marine Services segment includes the results of operations of an acquired entity. See Note C of Notes to Consolidated Financial Statements in Item 8. (c) Segment operating profit (loss) is gross operating revenues, gains and losses on asset sales and other income less applicable segment costs of sales, operating expenses, depreciation, depletion and other items. Income taxes, interest expense and corporate general and administrative expenses are not included in determining operating profit. (d) Extraordinary losses on debt extinguishments, net of income tax benefits, were $2.3 million ($0.09 per basic and diluted share), $2.9 million ($0.12 per basic share, $0.11 per diluted share) and $4.8 million ($0.21 per basic and diluted share) in 1996, 1995 and 1994, respectively. See Note I of Notes to Consolidated Financial Statements in Item 8. (e) Earnings per share amounts for periods prior to 1997 have been restated, where appropriate, to conform with the requirements of Statement of Financial Accounting Standard ("SFAS") No. 128. See Note A of Notes to Consolidated Financial Statements in Item 8. (f) EBITDA, consolidated, represents earnings before extraordinary item, interest expense, income taxes and depreciation, depletion and amortization. While not purporting to reflect any measure of the Company's operations or cash flows, EBITDA is presented for additional analysis. (g) In 1994, the Company restructured its outstanding debt and preferred stock by completing a recapitalization and equity offering. (h) The Company has not paid dividends on its Common Stock since 1986. 24 27 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Those statements in the Management's Discussion and Analysis that are not historical in nature should be deemed forward-looking statements that are inherently uncertain. See "Forward-Looking Statements" on page 42 for discussion of the factors which could cause actual results to differ materially from those projected in such statements. GENERAL The Company is focused on its long-term strategy to maximize returns and develop full value of its assets through strategic expansions, acquisitions and diversifications in all of its operating segments. In the Refining and Marketing segment, the Company has been engaged in studies to improve profitability and continues to explore and evaluate opportunities for possible expansion through acquisitions, as well as joint ventures and strategic alliances. Operating strategies have been implemented to optimize the refinery product slate, improve efficiencies and reliability, and expand marketing to increase placement of products in Alaska. In 1998, the Company plans to further improve profitability in the Refining and Marketing segment by enhancing processing capabilities, strengthening marketing channels and improving supply and transportation functions. In the Exploration and Production segment, the strategy includes evaluating ways in which the Company can continue to diversify its oil and gas reserve base through both acquisitions and activities at the drill bit and enhance its technical capabilities. The Company has made significant progress in diversifying its U.S. operations to areas other than the mature Bob West Field and has taken steps to begin serving emerging markets in South America. In the Marine Services segment, improved profitability has positioned this segment to participate in the consolidation of the industry by pursuing opportunities for expansion, as well as optimizing existing operations. In March 1998, the Company entered into an agreement to acquire the Hawaiian refining and marketing assets of BHP Petroleum Americas Refining Inc. ("BHP Refining") and BHP Petroleum South Pacific Inc. ("BHP South Pacific"). The acquisition, if consummated, will nearly double Tesoro's annual revenues and significantly increase the scope of Tesoro's refining and marketing operations. The Company expects that the results of the acquisition will be accretive to earnings and cash flows, although it may be neutral in 1998 primarily due to a scheduled maintenance turnaround at the Hawaii refinery to begin in June. The Company is currently in discussions with its investment bankers to arrange for financing of the acquisition and associated working capital and letter of credit requirements, and in connection with such discussions, the Company has been advised that sufficient funds will be made available. The Company will continue to pursue other opportunities that are operationally and geographically complementary with its asset base. For further information regarding the proposed acquisition, see "Capital Resources and Liquidity" herein and Note O of Notes to Consolidated Financial Statements in Item 8. As part of the Company's long-term strategy, growth initiatives are planned in 1998 with a capital budget of $195 million, excluding the acquisition discussed above. The 1998 capital budget represents an increase of 33% over 1997 capital expenditures. Approximately 70% of the 1998 capital budget is directed toward increased drilling, both in Bolivia and the U.S. Another 25% is planned for downstream operations, primarily improvements in the Alaska marketing operations. External growth initiatives are primarily aimed at acquisitions which would add value from the combination with the Company's existing assets, such as strengthening marketing opportunities, reducing logistic expenses or, in the downstream operations, offering increased processing opportunities. Initiatives to improve the profitability of each of the business segments, together with a debt-to-capitalization ratio of 26%, have positioned the Company to fund possible acquisitions and the capital budget with low-cost capital. The Company operates in an environment where its results and cash flows are sensitive to volatile changes in energy prices. Major shifts in the cost of crude oil used for refinery feedstocks and the price of refined products can result in a change in margin from the Refining and Marketing operations, as prices received for refined products may or may not keep pace with changes in crude oil costs. These energy prices, together with volume levels, also determine the carrying value of crude oil and refined product inventory. The 25 28 Company uses the last-in, first-out ("LIFO") method of accounting for inventories of crude oil and U.S. wholesale refined products in its Refining and Marketing segment. This method results in inventory carrying amounts that are less likely to represent current values and in costs of sales which more closely represent current costs. Likewise, changes in natural gas, condensate and oil prices impact revenues and the present value of estimated future net revenues and cash flows from the Company's Exploration and Production operations. The Company may increase or decrease its natural gas production in response to market conditions. The carrying value of oil and gas assets may be subject to noncash write-downs based on changes in natural gas prices and other determining factors. Changes in natural gas prices also influence the level of drilling activity in the Gulf of Mexico. The Company's Marine Services operation, whose customers include offshore drilling contractors and related industries, could be impacted by significant fluctuations in natural gas prices. The Company's Marine Services segment uses the first-in, first-out ("FIFO") method of accounting for inventories of fuels. Changes in fuel prices can significantly impact inventory valuations and costs of sales in this segment. RESULTS OF OPERATIONS SUMMARY Tesoro's net earnings for 1997 were $30.7 million ($1.16 per basic share, $1.14 per diluted share) compared to $74.5 million ($2.87 per basic share, $2.81 per diluted share) in 1996 and $54.6 million ($2.22 per basic share, $2.18 per diluted share) in 1995. In 1996 and 1995, the Company incurred noncash aftertax extraordinary losses of $2.3 million and $2.9 million, respectively, for early extinguishments of debt. Earnings before extraordinary losses amounted to $76.8 million ($2.96 per basic share, $2.90 per diluted share) and $57.5 million ($2.34 per basic share, $2.29 per diluted share) in 1996 and 1995, respectively. Results for 1996 and 1995 included revenues from sales of natural gas at above-market prices under a contract with Tennessee Gas Pipeline Company ("Tennessee Gas") which was terminated effective October 1, 1996. Results of operations in 1997 and future years no longer benefit from above-market revenues under this contract. Significant items, including the impact of the Tennessee Gas contract, which affect the comparability between results for the years ended December 31, 1997, 1996 and 1995 are highlighted in the table below (in millions except per share amounts):
1997 1996 1995 ----- ----- ------ Net Earnings as Reported................................... $30.7 $74.5 $ 54.6 Extraordinary Loss on Debt Extinguishments, Net of Income Tax Benefit.............................................. -- 2.3 2.9 ----- ----- ------ Earnings Before Extraordinary Item......................... 30.7 76.8 57.5 ----- ----- ------ Significant Items Affecting Comparability, Pretax: Income from retroactive severance tax refunds............ 1.8 5.0 -- Income from collection of Bolivian receivable............ 2.2 -- -- Income from settlement of a natural gas contract......... -- 60.0 -- Operating profit from excess of contract prices over spot market prices......................................... -- 24.6 47.1 Interest and reimbursement of fees and costs from resolution of litigation.............................. -- 8.1 -- Gain (loss) on sale of assets............................ -- (0.8) 33.5 Costs to resolve shareholder consent solicitation........ -- (2.3) -- Employee termination costs and other..................... -- (4.5) (5.2) ----- ----- ------ Total Significant Items, Pretax....................... 4.0 90.1 75.4 Income Tax Effect..................................... 1.2 27.2 -- ----- ----- ------ Total Significant Items, Aftertax..................... 2.8 62.9 75.4 ----- ----- ------ Net Earnings (Loss) Excluding Significant Items and Extraordinary Item....................................... $27.9 $13.9 $(17.9) ===== ===== ======
26 29
1997 1996 1995 ----- ----- ------ Earnings Per Share -- Basic: As reported.............................................. $1.16 $2.87 $ 2.22 Extraordinary loss....................................... -- (0.09) (0.12) Impact of contract prices over spot market prices and settlement income..................................... -- 2.28 1.92 Effect of other significant items........................ 0.10 0.15 1.15 ----- ----- ------ Excluding significant items and extraordinary item....... $1.06 $0.53 $(0.73) ===== ===== ====== Earnings Per Share -- Diluted: As reported.............................................. $1.14 $2.81 $ 2.18 Extraordinary loss....................................... -- (0.09) (0.11) Impact of contract prices over spot market prices and settlement income..................................... -- 2.23 1.88 Effect of other significant items........................ 0.10 0.14 1.14 ----- ----- ------ Excluding significant items and extraordinary item....... $1.04 $0.53 $(0.73) ===== ===== ======
As shown above, excluding the significant items, the Company's net earnings would have been $27.9 million ($1.06 per basic share, $1.04 per diluted share) in 1997, as compared to net earnings of $13.9 million ($0.53 per basic and diluted share) in 1996 and a net loss of $17.9 million ($0.73 per basic and diluted share) in 1995. The resulting $14 million increase in net earnings in 1997 was primarily attributable to better refined product margins, higher spot market natural gas prices and lower corporate interest expense. When comparing 1996 to 1995, after excluding significant items, the improvement in net earnings of approximately $32 million was primarily attributable to improvements within the Company's Refining and Marketing and Marine Services segments together with reduced general and administrative expenses and interest expense. These improvements were partially offset by an increase in the Company's total effective tax rate in 1996 as earnings subject to U.S. taxes exceeded available net operating loss and tax credit carryforwards. A discussion and analysis of the factors contributing to these results are presented below. The accompanying consolidated financial statements and related footnotes, together with the following information, are intended to provide shareholders and other investors with a reasonable basis for assessing the Company's operations, but should not serve as the sole criterion for predicting the future performance of the Company. 27 30 REFINING AND MARKETING
1997 1996 1995 ---------- ---------- ---------- (DOLLARS IN MILLIONS EXCEPT PER BARREL AMOUNTS) GROSS OPERATING REVENUES Total refined products............................ $ 643.7 $ 620.8 $ 664.5 Other, primarily crude oil resales and merchandise.................................... 77.2 124.6 106.5 ------- ------- ------- Gross Operating Revenues..................... $ 720.9 $ 745.4 $ 771.0 ======= ======= ======= TOTAL OPERATING PROFIT Gross margin: Refinery(a).................................... $ 93.3 $ 74.6 $ 63.5 Non-refinery(b)(c)............................. 36.6 32.7 34.1 ------- ------- ------- Total gross margin........................... 129.9 107.3 97.6 Operating expenses................................ 96.0 87.9 84.7 Depreciation and amortization..................... 12.7 12.5 11.9 Loss on sales of assets and other................. 0.7 0.9 0.3 ------- ------- ------- Operating Profit............................. $ 20.5 $ 6.0 $ 0.7 ======= ======= ======= CAPITAL EXPENDITURES................................ $ 43.9 $ 11.1 $ 9.3 ======= ======= ======= KENAI REFINERY THROUGHPUT Barrels per day................................... 50,207 47,486 50,569 % Alaska North Slope ("ANS") crude oil............ 71% 72% 68% REFINED PRODUCTS MANUFACTURED (average daily barrels) Gasoline and gasoline blendstocks................. 12,851 12,763 14,298 Middle distillates, including jet fuel and diesel fuel........................................... 21,636 19,975 20,693 Heavy oils and residual products.................. 14,752 13,739 14,516 Other............................................. 2,279 2,600 2,489 ------- ------- ------- Total Refined Products Manufactured.......... 51,518 49,077 51,996 ======= ======= ======= REFINERY PRODUCT SPREAD ($/barrel)(c)............... $ 5.09 $ 4.29 $ 3.44 ======= ======= ======= TOTAL SEGMENT PRODUCT SALES (average daily barrels)(d) Gasoline.......................................... 17,393 17,427 24,526 Middle distillates................................ 30,576 29,651 37,988 Heavy oils and residual products.................. 17,929 15,089 14,787 ------- ------- ------- Total Product Sales.......................... 65,898 62,167 77,301 ======= ======= ======= TOTAL SEGMENT PRODUCT SALES PRICES ($/barrel) Gasoline.......................................... $ 33.71 $ 32.72 $ 28.21 Middle distillates................................ $ 28.36 $ 29.01 $ 24.40 Heavy oils and residual products.................. $ 17.30 $ 17.61 $ 13.66 TOTAL SEGMENT GROSS MARGINS ON PRODUCT SALES ($/barrel)(e) Average sales price............................... $ 26.76 $ 27.28 $ 23.55 Average costs of sales............................ 21.92 23.15 20.53 ------- ------- ------- Gross Margin................................. $ 4.84 $ 4.13 $ 3.02 ======= ======= =======
- --------------- (a) Represents throughput at the Company's refinery ("Kenai Refinery") times refinery product spread. 28 31 (b) Non-refinery margin includes margins on products purchased and resold, margins on products sold in markets outside of Alaska, intrasegment pipeline revenues, retail margins, and adjustments due to selling a volume and mix of products that is different than actual volumes manufactured. (c) Amounts reported in prior periods have been reclassified to conform with current presentation. (d) Sources of total product sales include products manufactured at the Kenai Refinery, products drawn from inventory balances and products purchased from third parties. The Company's purchases of refined products for resale averaged approximately 11,300, 11,600 and 25,500 barrels per day in 1997, 1996 and 1995, respectively. (e) Gross margins on total product sales include margins on sales of purchased products, together with the effect of changes in inventories. 1997 Compared to 1996. The Refining and Marketing segment's operating profit of $20.5 million in 1997 increased $14.5 million from operating profit of $6.0 million in 1996. The improvement in results from Refining and Marketing has been due in part to the Company's initiatives to enhance its product slate, improve efficiencies and sell a larger portion of the Kenai Refinery's production within the core Alaska market. In these regards, in early October 1997, the Company completed an expansion of the Kenai Refinery's hydrocracker unit, which increased the unit's capacity by approximately 25% and enables the Company to produce more jet fuel, a product in short supply in Alaska. The expansion, together with the addition of a new, high-yield jet fuel hydrocracker catalyst, began to favorably impact this segment's results in the fourth quarter of 1997. The Company estimates that its yield of middle distillates will average 45% of total products manufactured at the Kenai Refinery during 1998. With respect to crude oil supply, during 1997, the Company negotiated contracts to purchase the remaining Cook Inlet crude oil production available for sale and, in October 1997, began purchasing approximately 25,000 barrels per day of Cook Inlet crude oil in addition to the approximate 9,000 barrels per day under previously existing contracts. Substantially all of the contracts for purchases of Cook Inlet crude oil are for various periods extending through December 1998. As part of a three-year, $50 million retail marketing expansion program initiated in 1997, the Company built two new retail facilities, remodeled three stations, bought two stations and closed two uneconomic outlets. At year-end 1997, the total number of retail stations selling the Company's gasoline totaled 222 as compared to 206 in 1996. Of these stations, 30 are located in the Pacific Northwest, compared to 18 at year-end 1996. During 1997, the Company's production of refined products increased in total by 5% due to higher throughput levels at the Kenai Refinery. The operational changes, previously discussed, resulted in an 8% increase in the production of middle distillates, primarily jet fuel, while gasoline production remained flat. Production of heavy oils and residual products increased by 7% in 1997. The improved product slate, which better matches the Company's product supply with demand in Alaska, reflected the change of a hydrocracker catalyst in late 1996 and the hydrocracker expansion and catalyst change in late 1997. The Company's sales of refined products within Alaska increased by 6% in 1997 contributing to higher product margins. The improved product slate and marketing efforts, together with generally favorable industry conditions, resulted in an increase in the Company's refinery spread to $5.09 per barrel in 1997, compared to $4.29 per barrel in 1996, reflecting a 10% decrease in the Company's per barrel feedstock cost with only a 5% decline in per barrel yield value. Both years included scheduled 30-day maintenance turnarounds. Revenues from sales of refined products in the Company's Refining and Marketing segment increased during 1997 due primarily to a 6% increase in sales volumes, partially offset by slightly lower average sales prices. Total refined product sales averaged 65,898 barrels per day in 1997 as compared to 62,167 barrels per day in 1996. Other revenues, which included crude oil resales of $44.4 million in 1997 and $93.8 million in 1996, declined due to lower sales volumes and prices. The Company had less crude oil available for resale in 1997 as throughput at the Kenai Refinery increased by 2,721 barrels per day, or 6%, from 1996 and fewer spot purchases of crude oil were made. Export sales of refined products, including sales to the Russian Far East, amounted to $16.1 million in 1997 compared to $22.0 million in 1996. Costs of sales decreased in 1997 due to lower spot purchases of crude oil and lower prices. Margins from non-refinery activities increased to $36.6 million in 1997 due primarily to higher retail sales and improved margins on products sold outside of 29 32 Alaska. Operating expenses increased in 1997 due primarily to higher employee costs, professional fees and marketing expenses. The Company's initiatives to enhance its product slate and sell more product within Alaska, as discussed above, have improved the fundamental earnings potential of this segment. Certain of these initiatives, such as the hydrocracker expansion and additional crude oil supply contracts, were completed in the fourth quarter of 1997. Future years will benefit from the impact of these initiatives for a full period. Future profitability of this segment, however, will continue to be influenced by market conditions, particularly as these conditions influence costs of crude oil relative to prices received for sales of refined products, and other additional factors that are beyond the control of the Company. 1996 Compared to 1995. Results from the Company's Refining and Marketing segment improved during 1996 with operating profit of $6.0 million, compared to operating profit of $0.7 million in 1995. This improvement was achieved during a year when the industry was facing rapidly rising prices in the crude oil market. In addition, the Company's production level at the Kenai Refinery was reduced in September 1996 for a scheduled 30-day maintenance turnaround. Despite these factors, the Company was able to achieve a refinery product spread of $4.29 per barrel for 1996, compared to $3.44 per barrel in 1995. The Company's results were helped by its initiatives to control costs, improve the Kenai Refinery's product slate and expand the marketing program for its refined products. The Company's average refined product yield value per barrel increased by 19% in 1996, while the Company's feedstock costs per barrel increased by 17%. During 1996, the Company's production of refined products declined in total by 6%, which included the impact of the scheduled maintenance period. Of this decline, gasoline production decreased by 11% and middle distillates decreased by only 3%. These reductions reflected the change of a hydrocracker catalyst during the maintenance period, which allows for increased production of jet fuel and reduced production of gasoline beginning in the fourth quarter of 1996, which better matches the Company's product supply with demand in Alaska. During 1996, the Company's marketing efforts added 31 locations in Alaska and eight locations in the Pacific Northwest, bringing the total to 188 branded, unbranded and Company-operated stations in Alaska and 18 branded stations in the Pacific Northwest at year-end 1996. Two uneconomic outlets in these areas were closed in 1996. In addition, the Company began producing and marketing liquid asphalt, which is a seasonal product in Alaska. Export sales of refined products, including sales to the Russian Far East, amounted to $22.0 million in 1996 and $18.5 million in 1995. Revenues from sales of refined products in the Company's Refining and Marketing segment decreased in 1996 due primarily to a 20% decline in sales volumes, partially offset by a 16% increase in average sales prices. Total refined product sales averaged 62,167 barrels per day in 1996 as compared to 77,301 barrels per day in 1995. This decline reflected the lower production volumes and the Company's withdrawal from certain U.S. West Coast markets during 1996, which also reduced the Company's purchases from other refiners and suppliers to 11,600 barrels per day in 1996 as compared to 25,500 barrels per day in 1995. One of the U.S. West Coast facilities was sold in 1996 resulting in a loss of $0.8 million. Sales of previously purchased crude oil increased to $93.8 million in 1996, compared to $75.8 million in 1995, due primarily to higher crude oil prices and in part due to sales of excess crude supply volumes during the maintenance period. Costs of sales decreased in 1996 due to lower volumes of refined products, partially offset by higher prices for crude oil and refined products. Operating expenses were higher in 1996 due primarily to higher environmental and employee costs partially offset by lower insurance costs. 30 33 EXPLORATION AND PRODUCTION
1997 1996 1995 ---------- ---------- ----------- (DOLLARS IN MILLIONS EXCEPT PER UNIT AMOUNTS) U.S. (a)(b) Gross operating revenues............................. $ 73.6 $ 93.8 $ 113.0 Income from settlement of a natural gas contract..... -- 60.0 -- Other income, including gain on asset sale in 1995... 3.2 4.8 33.5 Production costs..................................... 7.4 5.3 12.0 Administrative support and other operating expenses.......................................... 2.3 3.8 3.2 Depreciation, depletion and amortization............. 29.8 25.6 29.3 ------- ------- -------- Operating Profit -- U.S........................... 37.3 123.9 102.0 ------- ------- -------- BOLIVIA Gross operating revenues............................. 11.2 13.7 11.7 Other income related to collection of a receivable... 2.2 -- -- Production costs..................................... 0.9 0.8 0.6 Administrative support and other operating expenses.......................................... 2.4 2.8 3.2 Depreciation, depletion and amortization............. 1.5 1.3 0.3 ------- ------- -------- Operating Profit -- Bolivia....................... 8.6 8.8 7.6 ------- ------- -------- TOTAL OPERATING PROFIT -- EXPLORATION AND PRODUCTION... $ 45.9 $ 132.7 $ 109.6 ======= ======= ======== U.S. Average Daily Net Production: Natural gas (Mcf)................................. 86,052 87,654 114,490 Oil (barrels)..................................... 118 27 1 Total (thousand cubic feet equivalent "Mcfe")..... 86,760 87,816 114,496 Average Prices: Natural gas ($/Mcf) -- Spot market(c).................................. $ 2.17 $ 1.95 $ 1.34 Average(b)...................................... $ 2.17 $ 2.75 $ 2.57 Oil ($/barrel).................................... $ 18.90 $ 21.99 $ 16.82 Average Operating Expenses ($/Mcfe): Lease operating expenses.......................... $ 0.20 $ 0.14 $ 0.11 Severance taxes................................... 0.03 0.03 0.18 ------- ------- -------- Total production costs....................... 0.23 0.17 0.29 Administrative support and other.................. 0.07 0.10 0.06 ------- ------- -------- Total Operating Expenses..................... $ 0.30 $ 0.27 $ 0.35 ======= ======= ======== Depletion ($/Mcfe)................................... $ 0.93 $ 0.79 $ 0.69 Capital Expenditures (including U.S. gas transportation)................................... $ 65.4 $ 59.7 $ 49.6
31 34
1997 1996 1995 ---------- ---------- ----------- (DOLLARS IN MILLIONS EXCEPT PER UNIT AMOUNTS) BOLIVIA Average Daily Net Production: Natural gas (Mcf)................................. 19,537 20,251 18,650 Condensate (barrels).............................. 518 584 567 Total (Mcfe)...................................... 22,645 23,755 22,052 Average Prices: Natural gas ($/Mcf)............................... $ 1.15 $ 1.33 $ 1.28 Condensate ($/barrel)............................. $ 15.71 $ 17.98 $ 14.39 Average Operating Expenses ($/Mcfe): Production costs.................................. $ 0.11 $ 0.10 $ 0.07 Value-added taxes................................. -- 0.05 0.06 Administrative support and other.................. 0.31 0.27 0.35 ------- ------- -------- Total Operating Expenses..................... $ 0.42 $ 0.42 $ 0.48 ======= ======= ======== Depletion ($/Mcfe)................................... $ 0.19 $ 0.15 $ 0.03 Capital Expenditures................................. $ 27.5 $ 6.9 $ 3.8
- --------------- (a) Represents the Company's U.S. oil and gas operations combined with gas transportation activities. (b) Results for 1996 and 1995 included revenues from above-market pricing provisions of a contract with Tennessee Gas which was terminated effective October 1, 1996. Operating profit for 1996 and 1995 included $24.6 million and $47.1 million, respectively, for the excess of these contract prices over spot market prices. Net natural gas production sold under the contract averaged approximately 11 million cubic feet ("MMcf") per day in 1996 and 20 MMcf per day in 1995. Upon termination of the contract, the Company recorded other income and operating profit of $60 million during the fourth quarter of 1996. See Note D of Notes to Consolidated Financial Statements in Item 8. (c) Includes effects of the Company's natural gas commodity price agreements which amounted to losses of $0.05 per thousand cubic feet ("Mcf") and $0.11 per Mcf in 1997 and 1996, respectively, and a gain of $0.01 per Mcf in 1995. EXPLORATION AND PRODUCTION -- U.S. 1997 Compared to 1996. Operating profit from the Company's U.S. operations was $37.3 million in 1997, compared with $123.9 million in 1996. Comparability between these years was impacted by several major transactions in 1996, including the favorable resolution in August 1996 of litigation regarding the Tennessee Gas contract and the termination of the remainder of the contract effective October 1, 1996. As provided for in the Tennessee Gas contract, which was to expire in January 1999, the Company was selling a portion of the gas produced in the Bob West Field pursuant to a contract price, which was above the average spot market price. In total, during 1996 the Company received approximately $120 million in cash for the resolution of litigation and termination of the Tennessee Gas contract, with the Company's Exploration and Production segment recording operating profit of $60 million upon termination of the contract. In 1996 and 1995, the Exploration and Production segment's operating profit also included $24.6 million and $47.1 million, respectively, from the excess of Tennessee Gas contract prices over spot market prices. See Note D of Notes to Consolidated Financial Statements in Item 8. Additionally, during 1996, substantially all of the Company's proved producing reserves in the Bob West Field were certified by the Texas Railroad Commission as high-cost gas from a designated tight formation, eligible for state severance tax exemptions from the date of first production through August 2001. Accordingly, no severance tax is recorded on current production from the exempt wells in the Bob West Field beginning in 1996. In 1997 and 1996, the Company recognized income of $1.8 million and $5.0 million, respectively, for retroactive severance tax refunds for production in prior years. 32 35 Excluding the impact of the incremental contract value and income from the severance tax refunds, operating profit from the Company's U.S. operations would have been $35.5 million in 1997 compared to $34.3 million in 1996. The resulting increase of $1.2 million was primarily attributable to higher spot market prices for sales of natural gas, partially offset by higher depletion and operating expenses. Prices realized by the Company on its natural gas production sold in the spot market increased 11% to $2.17 per Mcf in 1997 from $1.95 per Mcf in 1996. The Company's weighted average sales price, which included the above-market pricing of the Tennessee Gas contract in 1996, decreased in 1997 due to the termination of the contract. The Company's net production averaged 86.8 MMcfe per day in 1997, a decrease of 1.0 MMcfe per day from 1996. This decrease consisted of a 16.1 MMcf per day decline from the Bob West Field, partially offset by a 15.1 MMcfe per day increase from other U.S. fields. The Company's U.S. production outside of the Bob West Field rose to 50% of its total U.S. production by January 1998, as compared to 7% at 1996 year-end. Gross operating revenues from the Company's U.S. operations, after excluding amounts related to Tennessee Gas, increased due to the higher spot market prices. Production costs were higher by $2.1 million ($0.06 per Mcfe) due mainly to costs at the Bob West Field, including increased compression costs and a charge for ad valorem taxes in 1997 as well as the impact of lower processing fees in 1996. Administrative support and other operating expenses decreased by $1.5 million. Depreciation and depletion increased by $4.2 million, or 16%, due to a higher depletion rate. From time to time, the Company enters into commodity price agreements to reduce the risk caused by fluctuations in the prices of natural gas in the spot market. During 1997, 1996 and 1995, the Company used such agreements to set the price of 9%, 30% and 38%, respectively, of the natural gas production that it sold in the spot market. During 1997 and 1996, the Company realized losses of $1.6 million ($0.05 per Mcf) and $3.1 million ($0.11 per Mcf), respectively, from these price agreements. In 1995, the effects of natural gas price agreements resulted in a gain of $0.3 million ($0.01 per Mcf). The Company had no remaining price agreements outstanding at December 31, 1997. 1996 Compared to 1995. Operating profit of $123.9 million from the Company's U.S. operations in 1996 increased $21.9 million from operating profit of $102.0 million in 1995. Comparability between these years was impacted by several major transactions. As discussed above, the 1996 results included the impact of the incremental value of the Tennessee Gas contract. Operating profit for 1995 included a gain of $33.5 million from the sale of certain interests in the Bob West Field (see Note C of Notes to Consolidated Financial Statements in Item 8). Excluding the impact of the incremental contract value from both years and the gain on sale of assets from 1995, operating profit from the Company's U.S. operations for 1996 would have been $34 million compared to $21 million for 1995. The resulting increase was primarily due to higher spot market prices for sales of natural gas, as industry demand increased due to unusually cold weather combined with below-normal storage levels. Prices realized by the Company on its natural gas production sold in the spot market increased 46% to $1.95 per Mcf in 1996 from $1.34 per Mcf in 1995. Excluding 24,500 Mcf per day related to the sold interests from 1995, the Company's spot production increased by 6,600 Mcf per day during 1996. The Company's exploration and acquisition programs outside of the Bob West Field contributed 3,800 Mcf per day of the increase in spot production with the remaining increase attributable to sales to Tennessee Gas at spot prices effective October 1, 1996. The Company's weighted average sales price increased 7% to $2.75 per Mcf in 1996 as compared to $2.57 per Mcf in 1995. For the Bob West Field, production declined by 6,100 Mcf per day after excluding amounts related to sold interests in 1995. Gross operating revenues from the Company's U.S. operations, after excluding $11.7 million related to the sold interests from 1995, decreased by $7.5 million due primarily to the decline in volumes sold under the Tennessee Gas contract, and losses under commodity price agreements discussed above, partially offset by increases in spot market sales prices and production. The decline in production costs of $6.7 million, or $0.12 per Mcfe, was mainly attributable to the severance tax exemptions in the Bob West Field. Total depreciation, depletion and amortization was lower in 1996 due to lower production volumes, partially offset by a higher depletion rate. 33 36 EXPLORATION AND PRODUCTION -- BOLIVIA The Company's Bolivian natural gas production is sold to Yacimientos Petroliferos Fiscales Bolivianos ("YPFB"), a Bolivian governmental agency, which in turn sells the natural gas to Yacimientos Petroliferos Fiscales, SA ("YPF"), a publicly-held company based in Argentina. Currently, the Company's sales of natural gas production are based on the volume and pricing terms in a contract between YPFB and YPF, which was extended in April 1997 for an additional two years to March 31, 1999, with an option to extend the contract a maximum of one additional year if a pipeline being constructed from Bolivia to Brazil is not complete. In the contract extension, YPF negotiated an 11% reduction in the minimum contract volume that it is required to import from Bolivia, which in turn resulted in a corresponding 11% reduction of the Company's minimum contract volume to 36.9 MMcf per day gross (26.2 net). The contract gas prices fluctuate since they are linked to a monthly average fuel oil price posted in the New York spot market. A lack of market access has constrained natural gas production in Bolivia. The Company believes that the completion of a 1,900-mile pipeline from Bolivia to Brazil will provide access to larger gas-consuming markets. Upon completion of this pipeline, the Company will face intense competition from major and independent natural gas companies operating in Bolivia for a share of the contractual volumes to be exported to Brazil. It is anticipated that each producer's share of the contractual volumes will be allocated by YPFB according to a number of factors, including each producer's reserve volumes and production capacity. Although the Company expects gas deliveries on the pipeline to begin in early 1999, there can be no assurance that the pipeline will be operational by such date. With the exception of the volumes currently under contract with the Bolivian government, the Company cannot be assured of the amount of additional volumes that will be exported to Brazil upon completion of the pipeline. 1997 Compared to 1996. Operating profit from the Company's Bolivian operations decreased to $8.6 million in 1997, from $8.8 million operating profit in 1996. Results for 1997 benefited from income of $2.2 million related to the collection of a receivable for prior years' production. Without this income, operating profit would have decreased by $2.4 million in 1997 due to declines in natural gas and condensate production and prices. With the Company's purchase of interests held by its former joint venture participant in July 1997, the Company's share of production from Bolivia increased by approximately 33% beginning in the 1997 third quarter (see Note C of Notes to Consolidated Financial Statements in Item 8). However, earlier in the year, the Company's Bolivian natural gas production was lower due to a reduction in minimum takes under the new contract between YPFB and YPF and also due to constraints arising from repairs to a non-Company-owned pipeline that transports gas from Bolivia to Argentina. In addition, during 1996, production was higher due to requests from YPFB for additional production from the Company to meet export specifications. Natural gas prices fell 14% to $1.15 per Mcf in 1997, compared to $1.33 per Mcf in 1996. Condensate prices fell 13% to $15.71 per barrel in 1997, compared to $17.98 per barrel in 1996. 1996 Compared to 1995. Operating profit from the Company's Bolivian operations increased to $8.8 million in 1996, from the $7.6 million operating profit in 1995. This improvement was primarily due to a 9% increase in production of natural gas, primarily due to increased demand from YPFB during the second and third quarters of 1996, together with higher prices received for both natural gas and condensate. Operating expenses declined by 12% on a per unit basis reflecting a 6% decrease in costs combined with the increase in volumes. Partially offsetting these improvements was an increase in depreciation, depletion and amortization of $1.0 million. 34 37 MARINE SERVICES
1997 1996 1995 ------ ------ ------ (DOLLARS IN MILLIONS) Gross Operating Revenues Fuels.................................................. $104.5 $ 98.9 $ 61.9 Lubricants and other................................... 16.4 14.9 12.0 Services............................................... 11.3 8.7 0.6 ------ ------ ------ Gross Operating Revenues............................ 132.2 122.5 74.5 Costs of Sales........................................... 96.7 93.0 64.9 ------ ------ ------ Gross Profit........................................ 35.5 29.5 9.6 Operating Expenses and Other............................. 27.5 22.2 13.7 Depreciation and Amortization............................ 1.7 1.2 0.3 ------ ------ ------ Operating Profit (Loss)............................. $ 6.3 $ 6.1 $ (4.4) ====== ====== ====== Sales Volumes (millions of gallons): Fuels, primarily diesel................................ 156.4 142.7 112.5 Lubricants............................................. 2.7 2.3 2.5 Capital Expenditures..................................... $ 9.4 $ 6.9 $ 0.4
1997 Compared to 1996. Gross operating revenues increased by $9.7 million, which included a $7.1 million increase in fuels and lubricant revenues and a $2.6 million increase in service revenues. The increase in fuels and lubricant revenues was primarily due to a 10% increase in sales volumes, partially offset by lower prices. The service revenue increase of 30% was due in part to increased rig activity in the Gulf of Mexico and the Company's focus to serve these customers. Additional terminal locations stemming from an acquisition consummated in February 1996 together with internal growth initiatives have enabled the Company to increase its sales activity. Costs of sales increased in 1997 due to the higher volumes. The improvement of $6.0 million in gross profit was offset by higher operating and other expenses associated with the increased activity together with upgrades to facilities and services. The Marine Service's segment business is largely dependent upon the level of oil and gas drilling, workover, construction and seismic activity in the Gulf of Mexico. 1996 Compared to 1995. In February 1996, the Company acquired Coastwide Energy Services, Inc. ("Coastwide") and combined these operations with the Company's marine petroleum products distribution business, forming a Marine Services segment. Operating results from Coastwide have been included in the Company's Marine Services segment since the date of acquisition. See Note C of Notes to Consolidated Financial Statements in Item 8. The Marine Services segment consisted of 20 terminals at year-end 1996, compared to 14 at the prior year-end. The increase of $39.9 million in fuels and lubricants revenues was primarily due to the added locations and associated volumes combined with higher fuel prices. In addition, revenues from services grew by $8.1 million. These increases in revenues together with improved margins during 1996 were partially offset by higher operating and other expenses associated with the increased activity. Depreciation and amortization increased during 1996 due to capital additions during the year. In total, operating profit of $6.1 million in 1996 reflected a turnaround from the losses incurred in the prior year. GENERAL AND ADMINISTRATIVE EXPENSES General and administrative expenses were $13.6 million in 1997, compared with $12.7 million in 1996 and $16.4 million in 1995. The increase in 1997 was primarily due to higher employee costs partially offset by lower professional fees and insurance costs. When comparing 1996 to 1995, the decrease was primarily due to lower employee and labor costs resulting from cost reduction measures implemented by the Company in late 1995. 35 38 INTEREST EXPENSE AND INTEREST INCOME Interest expense totaled $6.7 million in 1997, compared with $15.4 million in 1996 and $20.9 million in 1995. The Company's redemption of public debt of $74.1 million in November 1996 and $34.6 million in December 1995 contributed to these interest savings. Interest income was $1.6 million in 1997, compared with $8.4 million in 1996 and $1.8 million in 1995. The fluctuation in 1996 included interest of approximately $7 million received from Tennessee Gas in conjunction with the collection of a receivable which resulted from underpayment for natural gas sold in prior periods (see Note D of Notes to Consolidated Financial Statements in Item 8). OTHER EXPENSE, NET Other expense was $4.9 million in 1997, compared with $10.0 million in 1996 and $8.5 million in 1995. In 1996, the Company incurred costs of $2.3 million to resolve a shareholder consent solicitation, together with a write-off of deferred financing costs and increased expenses related to the Company's former operations. There were no material comparable costs recorded in 1997. When comparing 1996 to 1995, the increase in other expense was due to the costs recorded in 1996, partially offset by lower employee termination and restructuring costs. INCOME TAX PROVISION The income tax provision was $18.4 million in 1997, compared with $38.3 million in 1996 and $4.4 million in 1995. Effective income tax rates were 37%, 33% and 7% in 1997, 1996 and 1995, respectively (see Note H of Notes to Consolidated Financial Statements in Item 8). The decrease in the income tax provision in 1997 was primarily attributable to lower earnings, partially offset by a higher effective rate due to Bolivian taxes. When comparing 1996 to 1995, the income tax provision increased due to earnings subject to U.S. taxes exceeding available net operating loss and tax credit carryforwards. 36 39 CAPITAL RESOURCES AND LIQUIDITY OVERVIEW The Company's primary sources of liquidity are its cash and cash equivalents, internal cash generation and external financing. During 1997, the Company made capital expenditures of $147 million, which were funded through a combination of cash flows from operations of $96 million, external financing and available cash balances. At December 31, 1997, the Company's debt-to-capitalization ratio was 26% which enhances the Company's ability to access capital markets. Additional financing will be required for the proposed acquisition of BHP Refining and BHP South Pacific and associated working capital and letters of credit requirements. The Company is currently in discussions with its investment bankers to arrange for such financing, and in connection with such discussions, the Company has been advised that sufficient funds will be made available. See Note O of Notes to Consolidated Financial Statements in Item 8. The Company operates in an environment where its liquidity and capital resources are impacted by changes in the supply of and demand for crude oil, natural gas and refined petroleum products, market uncertainty and a variety of additional risks that are beyond the control of the Company. These risks include, among others, the level of consumer product demand, weather conditions, the proximity of the Company's natural gas reserves to pipelines, the capacities of such pipelines, fluctuations in seasonal demand, governmental regulations, the price and availability of alternative fuels and overall market and economic conditions. The Company's future capital expenditures as well as borrowings under its credit arrangements and other sources of capital will be affected by these conditions. CREDIT ARRANGEMENTS The Company's amended and restated corporate revolving credit agreement ("Credit Facility"), which expires in April 2000, provides total commitments of $150 million from a consortium of nine banks. The Company, at its option, has currently activated $100 million of these commitments. The Credit Facility provides for the issuance of letters of credit, and for cash borrowings up to $100 million, with the aggregate subject to a borrowing base (which amount exceeded total commitments at December 31, 1997). Outstanding obligations under the Credit Facility are collateralized by first liens on substantially all of the Company's trade receivables, product inventories and South Texas natural gas reserves and by a third lien on the Kenai Refinery. At December 31, 1997, the Company had outstanding cash borrowings of $28 million under the Credit Facility. Cash borrowings under the Credit Facility are generally used on a short-term basis to finance working capital requirements and capital expenditures. Under the Credit Facility, at December 31, 1997, the Company had outstanding letters of credit of $34 million, primarily for royalty crude oil purchases from the State of Alaska. Unused availability, including unactivated commitments, under the Credit Facility at December 31, 1997 for additional borrowings and letters of credit totaled $88 million. The Company is also permitted to utilize unsecured letters of credit outside of the Credit Facility up to $40 million (none outstanding at December 31, 1997). The Credit Facility, which has been amended from time to time, requires the Company to maintain specified levels of consolidated working capital, tangible net worth, cash flow and interest coverage and contains other covenants customary in credit arrangements of this kind. Among other matters, the terms of the Credit Facility allow for general open market stock repurchases and the payment of cash dividends subject to a cumulative amount available for restricted payments (defined as the difference of (i) the sum since December 31, 1995, of (a) $5 million and (b) 50% of consolidated net earnings of the Company in any calendar year and (ii) any restricted payments made since June 1996). At December 31, 1997, the cumulative amount available for restricted payments was approximately $58 million. In addition to the cumulative restriction, the Credit Facility further limits these general open market stock repurchases and cash dividends to a maximum of $5 million annually. The Credit Facility also permits the Company to repurchase a limited amount of Common Stock, up to $10 million annually, specifically for oddlot buyback programs and employee 37 40 benefit or compensation plans. The Board of Directors has no present plans to pay dividends. However, from time to time, the Board of Directors reevaluates the feasibility of declaring future dividends. For further information on the Company's credit arrangements, see Note I of Notes to Consolidated Financial Statements in Item 8. DEBT AND OTHER OBLIGATIONS Under an agreement reached in 1993, which settled a contractual dispute with the State of Alaska ("State"), the Company is obligated to make variable monthly payments to the State through December 2001 based on a per barrel charge on the volume of feedstock processed through the Kenai Refinery's crude unit. In 1997 and 1996, based on a per barrel throughput charge of 24 cents, the Company's variable payments to the State totaled $4.4 million and $4.0 million, respectively. In 1995, based on a per barrel throughput charge of 16 cents, the Company's variable payments to the State totaled $2.9 million. The per barrel charge increases to 30 cents in 1998 with one cent annual incremental increases thereafter through 2001. In January 2002, the Company is obligated to pay the State $60 million; provided, however, that such payment may be deferred indefinitely, at the Company's option, by continuing the variable monthly payments to the State beginning at 34 cents per barrel for 2002 and increasing one cent per barrel annually thereafter. Variable monthly payments made after January 2002 will not reduce the $60 million obligation to the State. The $60 million obligation is evidenced by a security bond, and the bond and the throughput barrel obligations are collateralized by a fourth lien on the Kenai Refinery. The Company's obligations under the agreement with the State and the mortgage are subordinated to current and future senior debt of up to $175 million plus any indebtedness incurred subsequent to the date of the agreement to improve the Kenai Refinery. Loans obtained to finance the expansion of the hydrocracker unit and install the vacuum unit, discussed in Note I of Notes to Consolidated Financial Statements in Item 8, qualify as indebtedness incurred subsequent to this agreement to improve the Kenai Refinery. STOCK REPURCHASE PROGRAM On May 7, 1997, the Company's Board of Directors authorized the repurchase of up to 3 million shares (approximately 11% of outstanding shares) of Tesoro Common Stock in a buyback program that will extend through the end of 1998. Under the program, subject to certain conditions, the Company may repurchase from time to time Tesoro Common Stock in the open market and through privately negotiated transactions. Purchases will depend on price, market conditions and other factors and will be made primarily from cash flows. The repurchased Common Stock is accounted for as treasury stock and may be used for employee benefit plan requirements and other corporate purposes. During 1997, the Company used cash flows of $3.7 million to repurchase 236,800 shares of Common Stock, of which 20,347 shares have been reissued for an employee benefit plan. For information related to restrictions under the Credit Facility, see Note I of Notes to Consolidated Financial Statements in Item 8. CAPITAL SPENDING Capital spending in 1997 totaled $147 million which was funded from available cash reserves, internally-generated cash flows from operations and external financing. Capital expenditures for the Exploration and Production segment were approximately $93 million, including $65 million for U.S. operations and $28 million for Bolivia operations. In the U.S., capital expenditures were principally for participation in the drilling of eleven development wells (nine completed), 12 exploratory wells (eight completed), the purchase of 33 Bcfe of proved reserves and 82,000 net undeveloped lease acres and seismic activity. In Bolivia, capital expenditures included the purchase of contract interests from its former joint venture participant (see Note C of Notes to Consolidated Financial Statements in Item 8), exploratory drilling, seismic activity and workovers. Capital projects for the Refining and Marketing segment in 1997 totaled $44 million, primarily for costs related to the hydrocracker expansion and the commencement of a long-term capital program to improve marketing operations. In the Marine Services segment, capital spending totaled $9 million during 1997, primarily for expansion and improvement of operations along the Gulf of Mexico. 38 41 For 1998, the Company has a total capital budget of approximately $195 million, excluding the acquisition of BHP Refining and BHP South Pacific. The Exploration and Production segment accounts for $139 million, or 71%, of the budget with $82 million planned for U.S. activities and $57 million for Bolivia. Planned U.S. expenditures include $25 million for acquisitions, $21 million for development drilling (participation in 30 wells), $17 million for leasehold, geological and geophysical, and $17 million for exploratory drilling (participation in 20 wells). In Bolivia, the drilling program is budgeted at $14 million for development drilling (three wells) and $12 million for exploratory drilling (two wells), with the remainder planned for upgrading a gas processing plant, constructing a liquid petroleum gas plant, workovers and three- dimensional seismic activity. Capital spending, other than acquisitions, for the Refining and Marketing segment is planned at $39 million, which includes $20 million towards the retail marketing expansion program in Alaska started in 1997, $8 million for environmental and $8 million for refinery improvements. The Marine Services capital budget is $9 million, primarily directed towards equipment and facility upgrades together with potential acquisitions. Capital expenditures for 1998 are expected to be financed through a combination of cash flows from operations, available cash reserves and additional borrowings under the Credit Facility. Actual capital expenditures may vary from these projections due to a number of factors, including the timing of drilling projects and the extent to which properties are acquired. CASH FLOW SUMMARY Components of the Company's cash flows are set forth below (in millions):
1997 1996 1995 ------- ------ ------ Cash Flows From (Used In): Operating Activities.......................... $ 95.6 $178.9 $ 35.4 Investing Activities.......................... (151.5) (94.2) 2.4 Financing Activities.......................... 41.5 (75.9) (37.8) ------- ------ ------ Increase (Decrease) in Cash and Cash Equivalents................................... $ (14.4) $ 8.8 $ -- ======= ====== ======
During 1997, net cash from operating activities totaled $96 million, compared with $179 million in 1996. Operating cash flows in 1997 included a $57 million decrease in receivables due in part to collections related to product and crude oil sales volumes at 1996 year-end, Bolivian production sold in prior years and retroactive severance taxes, partially offset by income tax and other payments. The 1996 operating cash flows included the impact of receipts from Tennessee Gas. Net cash used in investing activities of $151 million in 1997 included capital expenditures of $93 million for the Company's Exploration and Production activities, $44 million for Refining and Marketing activities and $9 million for Marine Services. Net cash from financing activities of $41 million in 1997 included net borrowings of $28 million under the Credit Facility and receipt of $16 million under a loan for the hydrocracker expansion, partially offset by payments of other long-term debt and repurchases of Common Stock. During 1997, gross borrowings under the Credit Facility were $150 million, with $122 million of repayments. At December 31, 1997, the Company's net working capital totaled $74 million, which included cash and cash equivalents of $8 million. During 1996, net cash from operating activities totaled $179 million, compared with $35 million in 1995. This increase in operating cash flows in 1996 was primarily due to the receipt of $120 million from Tennessee Gas for the favorable resolution of litigation in August 1996 and termination of the natural gas purchase and sales contract effective October 1, 1996. In addition, improved profitability plus noncash items, such as depreciation, depletion and amortization and deferred income taxes, contributed to higher cash flows from operations. Partially offsetting these increases were higher net working capital balances, particularly receivables which increased primarily due to higher year-end sales volumes together with higher prices. Net cash used in investing activities of $94 million in 1996 included capital expenditures of $85 million and cash consideration of nearly $8 million for the acquisition of Coastwide. Net cash used in financing activities of $76 million during 1996 was primarily due to the redemption of public debt aggregating $74 million together with payments of other long-term debt. During 1996, the Company's gross borrowings and repayments under its corporate revolving credit line amounted to $165 million. 39 42 During 1995, net cash from operating activities totaled $35 million. Although natural gas production from the Company's South Texas operations increased during 1995, lower cash receipts for sales of natural gas adversely affected the Company's cash flows from operations. Net cash from investing activities of $2 million in 1995 included proceeds of $70 million from sales of assets, primarily certain interests in the Bob West Field, partially offset by $64 million of capital expenditures and $3 million for acquisition of the Kenai Pipe Line Company ("KPL"). Net cash used in financing activities of $38 million in 1995 was primarily related to the redemption of $34.6 million of public debt and payments of other long-term debt. The Company's gross borrowings and repayments under the Facility totaled $262 million during 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 in a remedial response and has incurred cleanup expenditures associated with environmental matters at a number of sites, including certain of its own properties. At December 31, 1997, the Company's accruals for environmental expenses amounted to $8.5 million, which included a noncurrent liability of $2.7 million for remediation of KPL's properties that has been funded by the former owners of KPL through a restricted escrow deposit. Based on currently available information, including the participation of other parties or former owners in remediation actions, the Company believes these accruals are adequate. To comply with environmental laws and regulations, the Company anticipates that it will make capital improvements of approximately $7 million in 1998 and $2 million in 1999. In addition, capital expenditures for alternative secondary containment systems for existing storage tank facilities are estimated to be $2 million in 1998 and $2 million in 1999 with a remaining $5 million to be spent by 2002. Conditions that require additional expenditures may exist for various Company sites, including, but not limited to, the Kenai Refinery, retail gasoline outlets (current and closed locations) and petroleum product terminals, and for compliance with the Clean Air Act. The amount of such future expenditures cannot currently be determined by the Company. For further information on environmental contingencies, see Note L of Notes to Consolidated Financial Statements in Item 8. CRUDE OIL PURCHASE CONTRACTS The Company has a contract with the State of Alaska for the purchase of royalty crude oil, a primary feedstock for the Kenai Refinery, covering the period January 1, 1996 through December 31, 1998. This contract provides for the purchase of 30% of the State's ANS royalty crude oil produced from the Prudhoe Bay Unit at prices based on royalty values computed by the State. During 1997, the Company purchased approximately 35,700 barrels per day of ANS crude oil under this contract. The contract contains provisions that, under certain conditions, allow the Company to temporarily or permanently reduce its purchase obligations. Under this contract, the Company is required to utilize in its refinery operations volumes equal to at least 80% of the ANS crude oil purchased from the State. The Company is presently in discussions with the State in regard to extending this contract for an additional year. The Company also purchases approximately 6,000 barrels per day of ANS crude oil from a producer under a contract with a term of one year beginning January 1, 1998. During October 1997, the Company began purchasing all of the approximately 34,000 barrels per day of Cook Inlet crude oil production from various producers under contracts extending through December 1998. A contract to purchase 4,500 barrels per day, of the 34,000 barrels per day, has been extended through March 31, 2001. 40 43 YEAR 2000 COMPLIANCE The efficient operation of the Company's business is dependent on its computer hardware, operating systems and software programs (collectively, "Systems and Programs"). These Systems and Programs are used in several key areas of the Company's business, including information management services and financial reporting, as well as in various administrative functions. The Company has been evaluating its Systems and Programs to identify potential year 2000 compliance problems, as well as manual processes, external interfaces with customers and services supplied by vendors. The year 2000 problem refers to the limitations of the programming code in certain existing hardware and software programs to recognize date sensitive information for the year 2000 and beyond. Unless replaced or modified prior to the year 2000, such hardware and systems may not properly recognize such information and could generate erroneous data or cause a system to fail to operate properly. Based on current information, the Company expects to attain year 2000 compliance and institute appropriate testing of its modifications and replacements in a timely fashion and in advance of the year 2000 date change. It is anticipated that modification or replacement of the Company's Systems and Programs will be performed in-house by company personnel. The Company believes that, with hardware replacement and modifications to existing software or conversions to new software, the year 2000 problem will not pose a significant operational problem for the Company. It is possible that non-compliant third party computer systems or programs may not interface properly with the Company's computer systems. The Company has requested assurance from third parties that their computers, systems or programs be year 2000 compliant. The Company could, however, be adversely affected by the year 2000 problem if it or unrelated parties fail to successfully address this issue. Management of the Company currently anticipates that the expenses and capital expenditures associated with its year 2000 compliance project will not have a material effect on its financial position or results of operations. NEW ACCOUNTING STANDARDS In June 1997, the Financial Accounting Standards Board ("FASB") issued SFAS No. 130, "Reporting Comprehensive Income," which establishes standards for reporting and display of comprehensive income and its components in a full set of general-purpose financial statements. SFAS No. 130, which becomes effective for the Company in 1998, requires that all items that are required to be recognized under accounting standards as components of comprehensive income be reported in a financial statement that is displayed with the same prominence as other financial statements. Also, in June 1997, the FASB issued SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information," which establishes standards for reporting information about operating segments in annual financial statements and requires that selected information about operating segments be included in interim financial reports issued to shareholders. SFAS No. 131 also establishes standards for related disclosures about products and services, geographic areas and major customers. SFAS No. 131 becomes effective for the Company's 1998 year-end and need not be applied to interim financial information until 1999. In February 1998, the FASB issued SFAS No. 132, "Employers' Disclosures about Pensions and Other Postretirement Benefits," which standardizes the disclosures related to pensions and other postretirement benefits to the extent practicable, requires additional information on changes in the benefit obligations and fair values of plan assets and eliminates certain disclosures previously required. SFAS No. 132 becomes effective for the Company in 1998. All three statements contain provisions for restatement of prior period information. The Company is evaluating the effects that these new statements will have on its financial reporting and disclosures. The new statements will have no effect on the Company's results of operations, financial position or cash flows. 41 44 FORWARD-LOOKING STATEMENTS Statements in this Annual Report on Form 10-K, including those contained in the foregoing discussion and other items herein, concerning the Company which are (a) projections of revenues, earnings, earnings per share, capital expenditures or other financial items, (b) statements of plans and objectives for future operations, including acquisitions, (c) statements of future economic performance, or (d) statements of assumptions or estimates underlying or supporting the foregoing are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. The ultimate accuracy of forward-looking statements is subject to a wide range of business risks and changes in circumstances, and actual results and outcomes often differ from expectations. Any number of important factors could cause actual results to differ materially from those in the forward-looking statements herein, including the following: the timing and extent of changes in commodity prices and underlying demand and availability of crude oil and other refinery feedstocks, refined products, and natural gas; actions of customers and competitors; changes in the cost or availability of third-party vessels, pipelines and other means of transporting feedstocks and products; state and federal environmental, economic, safety and other policies and regulations, any changes therein, and any legal or regulatory delays or other factors beyond the Company's control; execution of planned capital projects; weather conditions affecting the Company's operations or the areas in which the Company's products are marketed; future well performance; the extent of Tesoro's success in acquiring oil and gas properties and in discovering, developing and producing reserves; political developments in foreign countries; the conditions of the capital markets and equity markets during the periods covered by the forward-looking statements; earthquakes or other natural disasters affecting operations; adverse rulings, judgments, or settlements in litigation or other legal matters, including unexpected environmental remediation costs in excess of any reserves; and adverse changes in the credit ratings assigned to the Company's trade credit. The Company undertakes no obligation to publicly release the result of any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events. 42 45 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEPENDENT AUDITORS' REPORT Board of Directors and Stockholders Tesoro Petroleum Corporation We have audited the accompanying consolidated balance sheets of Tesoro Petroleum Corporation and subsidiaries as of December 31, 1997 and 1996, and the related statements of consolidated operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 1997. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Tesoro Petroleum Corporation and subsidiaries at December 31, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles. DELOITTE & TOUCHE LLP San Antonio, Texas January 28, 1998 43 46 TESORO PETROLEUM CORPORATION STATEMENTS OF CONSOLIDATED OPERATIONS (IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
YEARS ENDED DECEMBER 31, ------------------------------------ 1997 1996 1995 -------- ---------- ---------- REVENUES Refining and marketing............................... $720,868 $ 745,413 $ 771,035 Exploration and production........................... 84,798 107,415 124,670 Marine services...................................... 132,251 122,533 74,467 Income from settlement of a natural gas contract..... -- 60,000 -- Gain on sale of assets and other income.............. 5,543 4,417 32,711 -------- ---------- ---------- Total Revenues............................... 943,460 1,039,778 1,002,883 -------- ---------- ---------- OPERATING COSTS AND EXPENSES Refining and marketing............................... 687,036 726,029 758,329 Exploration and production........................... 13,230 12,968 19,055 Marine services...................................... 124,725 115,314 77,803 Depreciation, depletion and amortization............. 45,729 40,627 41,776 -------- ---------- ---------- Total Operating Costs and Expenses........... 870,720 894,938 896,963 -------- ---------- ---------- OPERATING PROFIT....................................... 72,740 144,840 105,920 General and Administrative............................. (13,588) (12,733) (16,453) Interest Expense, Net of Capitalized Interest in 1997................................................. (6,699) (15,382) (20,902) Interest Income........................................ 1,597 8,423 1,845 Other Expense, Net..................................... (4,930) (10,001) (8,542) -------- ---------- ---------- EARNINGS BEFORE INCOME TAXES AND EXTRAORDINARY ITEM.... 49,120 115,147 61,868 Income Tax Provision................................... 18,435 38,347 4,379 -------- ---------- ---------- EARNINGS BEFORE EXTRAORDINARY ITEM..................... 30,685 76,800 57,489 Extraordinary Loss on Extinguishments of Debt (Net of Income Tax Benefit of $886 in 1996).................. -- (2,290) (2,857) -------- ---------- ---------- NET EARNINGS........................................... $ 30,685 $ 74,510 $ 54,632 ======== ========== ========== NET EARNINGS PER SHARE -- BASIC........................ $ 1.16 $ 2.87 $ 2.22 ======== ========== ========== NET EARNINGS PER SHARE -- DILUTED...................... $ 1.14 $ 2.81 $ 2.18 ======== ========== ========== WEIGHTED AVERAGE COMMON SHARES -- BASIC................ 26,410 25,999 24,557 ======== ========== ========== WEIGHTED AVERAGE COMMON SHARES AND POTENTIALLY DILUTIVE COMMON SHARES -- DILUTED............................. 26,868 26,499 25,107 ======== ========== ==========
The accompanying notes are an integral part of these consolidated financial statements. 44 47 TESORO PETROLEUM CORPORATION CONSOLIDATED BALANCE SHEETS (DOLLARS IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
DECEMBER 31, ---------------------- 1997 1996 -------- -------- ASSETS CURRENT ASSETS Cash and cash equivalents................................. $ 8,352 $ 22,796 Receivables, less allowance for doubtful accounts......... 76,282 128,013 Inventories............................................... 87,359 74,488 Prepayments and other..................................... 9,842 12,046 -------- -------- Total Current Assets.............................. 181,835 237,343 -------- -------- PROPERTY, PLANT AND EQUIPMENT Refining and marketing.................................... 370,174 328,522 Exploration and production, full-cost method of accounting: Properties being amortized............................. 251,604 179,433 Properties not yet evaluated........................... 31,918 12,344 Gas transportation..................................... 7,889 6,703 Marine services........................................... 43,072 33,820 Corporate................................................. 13,689 12,531 -------- -------- 718,346 573,353 Less accumulated depreciation, depletion and amortization.......................................... 304,523 256,842 -------- -------- Net Property, Plant and Equipment...................... 413,823 316,511 -------- -------- OTHER ASSETS................................................ 32,150 28,733 -------- -------- Total Assets...................................... $627,808 $582,587 ======== ======== LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES Accounts payable.......................................... $ 58,767 $ 80,747 Accrued liabilities....................................... 31,372 33,256 Current income taxes payable.............................. 354 13,822 Current maturities of long-term debt and other obligations............................................ 17,002 10,043 -------- -------- Total Current Liabilities......................... 107,495 137,868 -------- -------- DEFERRED INCOME TAXES....................................... 28,824 19,151 -------- -------- OTHER LIABILITIES........................................... 43,211 42,243 -------- -------- LONG-TERM DEBT AND OTHER OBLIGATIONS, LESS CURRENT MATURITIES................................................ 115,314 79,260 -------- -------- COMMITMENTS AND CONTINGENCIES (Note L) STOCKHOLDERS' EQUITY Preferred stock, no par value; authorized 5,000,000 shares including redeemable preferred shares; none issued or outstanding Common stock, par value $0.16 2/3; authorized 50,000,000 shares; 26,506,601 shares issued (26,414,134 in 1996).................................................. 4,418 4,402 Additional paid-in capital................................ 190,925 189,368 Retained earnings......................................... 140,980 110,295 Treasury stock, 216,453 common shares in 1997, at cost.... (3,359) -- -------- -------- Total Stockholders' Equity............................. 332,964 304,065 -------- -------- Total Liabilities and Stockholders' Equity........ $627,808 $582,587 ======== ========
The accompanying notes are an integral part of these consolidated financial statements. 45 48 TESORO PETROLEUM CORPORATION STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY (IN THOUSANDS)
RETAINED COMMON STOCK ADDITIONAL EARNINGS TREASURY STOCK --------------- PAID-IN (ACCUMULATED ---------------- SHARES AMOUNT CAPITAL DEFICIT) SHARES AMOUNT ------ ------ ---------- ------------ ------ ------- BALANCE AT DECEMBER 31, 1994............ 24,390 $4,065 $175,514 $(18,847) -- $ -- Net earnings.......................... -- -- -- 54,632 -- -- Shares issued pursuant to exercise of stock options and stock awards..... 390 65 1,085 -- -- -- ------ ------ -------- -------- ---- ------- BALANCE AT DECEMBER 31, 1995............ 24,780 4,130 176,599 35,785 -- -- Net earnings.......................... -- -- -- 74,510 -- -- Issuance of Common Stock.............. 1,308 218 11,054 -- -- -- Shares issued pursuant to exercise of stock options and stock awards..... 326 54 1,715 -- -- -- ------ ------ -------- -------- ---- ------- BALANCE AT DECEMBER 31, 1996............ 26,414 4,402 189,368 110,295 -- -- Net earnings.......................... -- -- -- 30,685 -- -- Shares repurchased.................... -- -- -- -- (236) (3,701) Shares issued pursuant to exercise of stock options and stock awards and employee benefit plans............. 45 7 440 -- 20 342 Other................................. 48 9 1,117 -- -- -- ------ ------ -------- -------- ---- ------- BALANCE AT DECEMBER 31, 1997............ 26,507 $4,418 $190,925 $140,980 (216) $(3,359) ====== ====== ======== ======== ==== =======
The accompanying notes are an integral part of these consolidated financial statements. 46 49 TESORO PETROLEUM CORPORATION STATEMENTS OF CONSOLIDATED CASH FLOWS (IN THOUSANDS)
YEARS ENDED DECEMBER 31, ------------------------------- 1997 1996 1995 --------- -------- -------- CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES Net earnings.............................................. $ 30,685 $ 74,510 $ 54,632 Adjustments to reconcile net earnings to net cash from operating activities: Depreciation, depletion and amortization............... 46,363 41,459 42,620 Loss (gain) on sales of assets......................... 523 835 (32,659) Amortization of deferred charges and other............. 951 1,601 1,556 Extraordinary loss on extinguishments of debt, net of income tax benefit................................... -- 2,290 2,857 Changes in operating assets and liabilities: Receivables.......................................... 56,785 (42,542) 9,746 Receivable from Tennessee Gas Pipeline Company....... -- 50,680 (37,456) Inventories.......................................... (11,517) 7,210 (11,599) Other assets......................................... 296 (3,521) (3,573) Accounts payable and accrued liabilities............. (37,854) 28,165 4,605 Deferred income taxes................................ 9,673 14,649 807 Obligation payments to State of Alaska............... (4,401) (4,047) (2,892) Other liabilities and obligations.................... 4,131 7,673 6,769 --------- -------- -------- Net cash from operating activities................ 95,635 178,962 35,413 --------- -------- -------- CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES Capital expenditures...................................... (147,498) (84,957) (63,930) Proceeds from sales of assets............................. 112 2,569 69,786 Other..................................................... (4,159) (11,812) (3,452) --------- -------- -------- Net cash from (used in) investing activities...... (151,545) (94,200) 2,404 --------- -------- -------- CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES Payments of long-term debt................................ (4,095) (3,838) (2,979) Net borrowings under revolving credit facilities.......... 32,728 883 -- Issuance of long-term debt................................ 16,200 -- -- Repurchase of common stock................................ (3,701) -- -- Repurchase of debentures and notes........................ -- (74,116) (34,634) Other..................................................... 334 1,164 (281) --------- -------- -------- Net cash from (used in) financing activities...... 41,466 (75,907) (37,894) --------- -------- -------- INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS............ (14,444) 8,855 (77) CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR................ 22,796 13,941 14,018 --------- -------- -------- CASH AND CASH EQUIVALENTS, END OF YEAR...................... $ 8,352 $ 22,796 $ 13,941 ========= ======== ======== SUPPLEMENTAL CASH FLOW DISCLOSURES Interest paid, net of $419 capitalized in 1997............ $ 2,127 $ 12,450 $ 18,132 ========= ======== ======== Income taxes paid......................................... $ 22,412 $ 6,285 $ 4,046 ========= ======== ========
The accompanying notes are an integral part of these consolidated financial statements. 47 50 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE A -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Principles of Consolidation The accompanying Consolidated Financial Statements include the accounts of Tesoro Petroleum Corporation and its subsidiaries (collectively, the "Company" or "Tesoro"). All significant intercompany accounts and transactions have been eliminated. Tesoro is a natural resource company engaged in petroleum refining, distributing and marketing of petroleum products, marine logistics services and the exploration and production of natural gas and oil. Use of Estimates and Presentation The preparation of the Company's Consolidated Financial Statements in conformity with generally accepted accounting principles required the use of management's best estimates and judgment that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the year. Actual results could differ from those estimates. Cash and Cash Equivalents Cash equivalents consist of highly-liquid debt instruments such as commercial paper and certificates of deposit purchased with an original maturity date of three months or less. Cash equivalents are stated at cost, which approximates market value. The Company's policy is to invest cash in conservative, highly-rated instruments and to invest in various institutions to limit the amount of credit exposure in any one institution. The Company performs ongoing evaluations of the credit standing of these financial institutions. Inventories Inventories are stated at the lower of cost or market. The last-in, first-out ("LIFO") method was used to determine the cost of the Company's refining and marketing inventories of crude oil and U.S. wholesale refined products. The cost of remaining refined product inventories, including fuel at the Company's marine service terminals, was determined principally on the first-in, first-out ("FIFO") method. Merchandise and materials and supplies are valued at average cost, not in excess of market value. See Note F. Property, Plant and Equipment Additions to property, plant and equipment and major improvements and modifications are capitalized at cost. Maintenance and repairs are charged to operations when incurred. Depletion of oil and gas producing properties is determined principally by the unit-of-production method and is based on estimated recoverable reserves. Depreciation of other property, plant and equipment is generally computed on the straight-line method based upon the estimated useful life of each asset. The weighted average lives range from 12 to 30 years for refining, marketing and pipeline assets, 11 to 16 years for service equipment and marine fleets, and five to seven years for corporate and other assets. Oil and gas properties are accounted for using the full-cost method of accounting. Under this method, all costs associated with property acquisition and exploration and development activities are capitalized into cost centers that are established on a country-by-country basis. For each cost center, the capitalized costs are subject to a limitation so as not to exceed the present value of future net revenues from estimated production of proved oil and gas reserves, net of income tax effect, plus the lower of cost or estimated fair value of unproved properties included in the cost center. Capitalized costs within a cost center, together with estimates of costs for future development, dismantlement and abandonment, are amortized on a unit-of-production method using the proved oil and gas reserves for each cost center. The Company's investment in certain oil and gas properties is excluded from the amortization base until the properties are evaluated. Gain or loss is 48 51 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) recognized only on the sale of oil and gas properties involving significant reserves. Proceeds from the sale of insignificant reserves and undeveloped properties are applied to reduce the costs in the cost centers. Income Taxes Deferred tax assets and liabilities are recognized for future income tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax bases. Measurement of deferred tax assets and liabilities is based on enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period that includes the enactment date. Environmental Expenditures Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that extend the life, increase the capacity, or mitigate or prevent environmental contamination, are capitalized. Expenditures that relate to an existing condition caused by past operations, and which do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or remedial efforts are probable and the cost can be reasonably estimated. Such amounts are based on the estimated timing and extent of remedial actions required by applicable governing agencies, experience gained from similar sites on which environmental assessments or remediation has been completed, and the amount of the Company's anticipated liability considering the proportional liability and financial abilities of other responsible parties. Generally, the timing of these accruals coincides with completion of a feasibility study or the Company's commitment to a formal plan of action. Estimated liabilities are not discounted to present value. Financial Instruments The carrying amount of financial instruments including cash and cash equivalents, accounts receivable, accounts payable and certain accrued liabilities approximates fair value because of the short maturity of these instruments. The carrying amount of the Company's long-term debt and other obligations approximated the Company's estimates of the fair value of such items. 49 52 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Earnings Per Share Earnings per share have been determined in accordance with Statement of Financial Accounting Standard ("SFAS") No. 128 which establishes standards for computing and presenting basic and diluted earnings per share calculations. Basic earnings per share is determined by dividing net earnings by the weighted average number of common shares outstanding during the period. The Company's calculation of diluted earnings per share takes into account the effect of potentially dilutive shares, principally stock options, outstanding during the period. Prior period amounts have been restated to conform with the requirements of SFAS No. 128. Earnings per share calculations for the years ended December 31, 1997, 1996 and 1995 are presented below (in thousands except per share amounts):
1997 1996 1995 ------- ------- ------- Earnings Applicable to Common Shareholders (Basic and Diluted Numerator): Earnings before extraordinary item.................. $30,685 $76,800 $57,489 Extraordinary loss on extinguishments of debt, aftertax......................................... -- (2,290) (2,857) ------- ------- ------- Net earnings..................................... $30,685 $74,510 $54,632 ======= ======= ======= Basic: Weighted average common shares (Basic denominator)..................................... 26,410 25,999 24,557 ======= ======= ======= Basic earnings per share -- Before extraordinary item........................ $ 1.16 $ 2.96 $ 2.34 Extraordinary loss, aftertax..................... -- (0.09) (0.12) ------- ------- ------- Net.............................................. $ 1.16 $ 2.87 $ 2.22 ======= ======= ======= Diluted: Weighted average common shares...................... 26,410 25,999 24,557 Incremental shares from assumed conversion of stock options and other................................ 458 500 550 ------- ------- ------- Total diluted shares (Diluted denominator).......... 26,868 26,499 25,107 ======= ======= ======= Diluted earnings per share -- Before extraordinary item........................ $ 1.14 $ 2.90 $ 2.29 Extraordinary loss, aftertax..................... -- (0.09) (0.11) ------- ------- ------- Net.............................................. $ 1.14 $ 2.81 $ 2.18 ======= ======= =======
In accordance with SFAS No. 128, restricted Common Stock awards totaling 350,000 shares and options to purchase 340,000 shares of Common Stock under the Company's special incentive compensation strategy (see Note K) were not included in the computations of earnings per share in 1997 and 1996. No shares were issuable under this strategy since the attainment of a specified market price of the Company's Common Stock had not been reached during the periods presented. These awards and options remained outstanding at December 31, 1997. Stock-Based Compensation The Company accounts for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board ("APB") No. 25, "Accounting for Stock Issued to Employees," and related interpretations. Accordingly, compensation cost for stock options is measured as the excess, if any, of the quoted market price of the Company's Common Stock at the date of grant over the amount an employee must pay to acquire the stock. The Company has adopted the disclosure requirements of SFAS No. 123, "Accounting for Stock-Based Compensation," as included in Note K. 50 53 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) New Accounting Standards In June 1997, the Financial Accounting Standards Board ("FASB") issued SFAS No. 130, "Reporting Comprehensive Income," which establishes standards for reporting and display of comprehensive income and its components in a full set of general-purpose financial statements. SFAS No. 130, which becomes effective for the Company in 1998, requires that all items that are required to be recognized under accounting standards as components of comprehensive income be reported in a financial statement that is displayed with the same prominence as other financial statements. Also, in June 1997, the FASB issued SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information," which establishes standards for reporting information about operating segments in annual financial statements and requires that selected information about operating segments be included in interim financial reports issued to shareholders. SFAS No. 131 also establishes standards for related disclosures about products and services, geographic areas and major customers. SFAS No. 131 becomes effective for the Company's 1998 year-end and need not be applied to interim financial information until 1999. In February 1998, the FASB issued SFAS No. 132, "Employers' Disclosures about Pensions and Other Postretirement Benefits," which standardizes the disclosures related to pensions and other postretirement benefits to the extent practicable, requires additional information on changes in the benefit obligations and fair values of plan assets and eliminates certain disclosures previously required. SFAS No. 132 becomes effective for the Company in 1998. All three statements contain provisions for restatement of prior period information. The Company is evaluating the effects that these new statements will have on its financial reporting and disclosures. The new statements will have no effect on the Company's results of operations, financial position or cash flows. NOTE B -- BUSINESS SEGMENTS The Company's revenues are derived from three business segments: Refining and Marketing, Exploration and Production, and Marine Services. Refining and Marketing operates a petroleum refinery at Kenai, Alaska, which manufactures gasoline, jet fuel, diesel fuel, heavy oils and residual products. These products, together with products purchased from third parties, are sold at wholesale through terminal facilities and other locations in Alaska and the Pacific Northwest. In addition, Refining and Marketing markets gasoline, other petroleum products and convenience store items at retail through 35 Company-operated stations in Alaska. Refining and Marketing also markets petroleum products through 129 branded and 28 unbranded stations located in Alaska and the Pacific Northwest. Revenues from export sales, primarily to Far East markets, amounted to $16.1 million, $22.0 million and $18.5 million in 1997, 1996 and 1995, respectively. The Company at times resells previously purchased crude oil, sales of which amounted to $44.4 million, $93.8 million and $75.8 million in 1997, 1996 and 1995, respectively. The Exploration and Production segment is engaged in the exploration, production and development of natural gas and oil onshore in Texas, Louisiana and Bolivia. This segment also includes the transportation of natural gas, including the Company's production, to common carrier pipelines in South Texas. In Bolivia, the Company operates under four contracts with the Bolivian government to explore for and produce hydrocarbons. The Company's Bolivian natural gas production is sold under contract to the Bolivian government for export to Argentina. The majority of the Company's Bolivian natural gas and oil reserves are shut-in awaiting access to gas-consuming markets. Major developments in South America indicate that new markets may open for the Company's production in the near future. Construction of a new 1,900-mile pipeline that will link Bolivia's gas reserves with markets in Brazil commenced in 1997 and is expected to be operational in early 1999. Marine Services markets and distributes petroleum products and provides logistics services, primarily to the marine and offshore exploration and production industries operating in the Gulf of Mexico. This segment 51 54 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) currently operates through 20 terminals along the Texas and Louisiana Gulf Coast and three terminals on the U.S. West Coast. Segment operating profit is gross operating revenues, gains and losses on asset sales and other income less applicable segment costs of sales, operating expenses, depreciation, depletion and other items. Income taxes, interest expense, interest income and corporate general and administrative expenses are not included in determining operating profit. In the Exploration and Production segment, operating profit in 1997 included income of $1.8 million for severance tax refunds and $2.2 million related to the collection of a receivable for prior years Bolivian production. Operating profit in the Exploration and Production segment in 1996 included $60 million of income from termination of a natural gas contract and $5 million for retroactive severance tax refunds, and 1995 included a gain of $33 million from the sale of certain interests in the Bob West Field. In 1996 and 1995, the Exploration and Production segment's operating profit included $24.6 million and $47.1 million, respectively, from the excess of natural gas contract prices over spot market prices (see Note D). Identifiable assets are those assets utilized by the segment. Corporate assets are principally cash, investments and other assets that cannot be directly associated with the operations of a business segment. Segment information for the years ended December 31, 1997, 1996 and 1995 is as follows (in millions):
1997 1996 1995 ------ -------- -------- REVENUES Gross operating revenues: Refining and Marketing -- Refined products.................................. $643.7 $ 620.8 $ 664.5 Other, primarily crude oil resales and merchandise.................................... 77.2 124.6 106.5 Exploration and Production -- U.S., including gas transportation................ 73.6 93.8 113.0 Bolivia........................................... 11.2 13.7 11.7 Marine Services..................................... 132.2 122.5 74.5 ------ -------- -------- Total Gross Operating Revenues.................... 937.9 975.4 970.2 Income from settlement of a natural gas contract and other............................................... 5.5 64.4 32.7 ------ -------- -------- Total Revenues................................. $943.4 $1,039.8 $1,002.9 ====== ======== ======== OPERATING PROFIT (LOSS) Refining and Marketing................................. $ 20.5 $ 6.0 $ 0.7 Exploration and Production -- U.S., including gas transportation.................. 37.3 123.9 102.0 Bolivia............................................. 8.6 8.8 7.6 Marine Services........................................ 6.3 6.1 (4.4) ------ -------- -------- Total Operating Profit......................... 72.7 144.8 105.9 Corporate and Unallocated Costs........................ (23.6) (29.7) (44.0) ------ -------- -------- Earnings Before Income Taxes and Extraordinary Item.... $ 49.1 $ 115.1 $ 61.9 ====== ======== ========
52 55 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
1997 1996 1995 ------ -------- -------- IDENTIFIABLE ASSETS Refining and Marketing................................. $337.4 $ 317.0 $ 313.3 Exploration and Production -- U.S., including gas transportation.................. 158.2 143.6 136.7 Bolivia............................................. 50.8 27.0 17.8 Marine Services........................................ 59.3 56.0 18.0 Corporate.............................................. 22.1 39.0 33.4 ------ -------- -------- Total Assets................................... $627.8 $ 582.6 $ 519.2 ====== ======== ======== DEPRECIATION, DEPLETION AND AMORTIZATION Refining and Marketing................................. $ 12.7 $ 12.5 $ 11.9 Exploration and Production -- U.S., including gas transportation.................. 29.8 25.6 29.3 Bolivia............................................. 1.5 1.3 0.3 Marine Services........................................ 1.7 1.2 0.3 Corporate.............................................. 0.7 0.9 0.8 ------ -------- -------- Total Depreciation, Depletion and Amortization................................. $ 46.4 $ 41.5 $ 42.6 ====== ======== ======== CAPITAL EXPENDITURES Refining and Marketing................................. $ 43.9 $ 11.1 $ 9.3 Exploration and Production -- U.S., including gas transportation.................. 65.4 59.7 49.6 Bolivia............................................. 27.5 6.9 3.8 Marine Services........................................ 9.4 6.9 0.4 Corporate.............................................. 1.3 0.4 0.8 ------ -------- -------- Total Capital Expenditures..................... $147.5 $ 85.0 $ 63.9 ====== ======== ========
NOTE C -- ACQUISITIONS, EXPANSIONS AND DIVESTITURES Refining and Marketing In October 1997, the Company completed an expansion of its refinery hydrocracker unit which enables the Company to increase its jet fuel production. The expansion, together with the addition of a new, high-yield jet fuel hydrocracker catalyst, was completed at a cost of approximately $19 million. For information on financing of this expansion, see Note I. In December 1997, the Refining and Marketing segment purchased the Union 76 marketing assets in Southeast Alaska, consisting of one terminal, two retail stations and the rights to use the Union 76 trademark within Alaska. The Company also expanded its Alaskan retail operations throughout the year with construction of two new facilities and remodeling of three existing stations. Two uneconomic outlets in Alaska were closed in 1997. Exploration and Production In July 1997, the Company purchased the interests held by its former joint venture participant in the then existing two contract blocks in southern Bolivia, consisting of a 25% interest in Block 18 and a 27.4% interest in Block 20. The purchase price was approximately $20 million, which included $11.9 million for proved reserves and $3.4 million for undeveloped acreage with the remainder for working capital and assumption of certain liabilities. 53 56 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) In the U.S., the Exploration and Production segment purchased proved and unproved properties totaling $22 million during 1997. These purchases included the acquisition of interests in the Kent Bayou Field in Terrebonne Parish in southern Louisiana for $5 million and interests in the La Blanca, San Salvador and San Carlos Fields in the Frio/Vicksburg Trend of Hildago County in South Texas for $3.1 million during November 1997. Also included was the acquisition of interests in three natural gas fields in East Texas, including the Carthage Field in Panola County, the Woodlawn Field in Harrison County and the Oak Hill Field in Rusk County, for $5.1 million in December 1997. During 1996, the Company's Exploration and Production segment recorded acquisitions of proved and unproved properties totaling $25.7 million. The most significant of these was the purchase in December 1996 of interests in the Los Indios and La Reforma Fields, located in Hidalgo and Starr counties of South Texas, for $15 million. These two fields are in the Frio/Vicksburg Trend, which lies immediately adjacent to the Wilcox Trend. Other acquisitions in 1996 included the purchase of interests in the Berry R. Cox and the West Goliad Fields, both located in the Wilcox Trend, for $5.4 million and the purchase of acreage in East Texas for $5.3 million. In September 1995, the Company sold, effective April 1, 1995, certain interests in its producing and non-producing oil and gas properties located in the Bob West Field in South Texas. The interests sold included the Company's approximate 55% net revenue interest and 70% working interest in Units C, D and E and a convertible override in Unit F of the Bob West Field. Excluded from the sale were the Company's interests in the State Park and Sanchez-O'Brien leases and the Ramirez USA E-6 well within the Bob West Field. In total, the sale included interests in 14 gross producing wells amounting to 77 Bcf, or 40%, of the Company's total net proved domestic reserves at the time of the sale (see Note N). For 1995, natural gas production from the interests sold had contributed approximately $11.7 million to revenues and $4 million to operating profit in the Company's Exploration and Production segment. Consideration for the sale was $74 million, which was adjusted for production, capital expenditures and certain other items after the effective date to approximately $68 million in cash received at closing, resulting in a gain of approximately $33 million in the 1995 third quarter. The consideration received by the Company was used to redeem $34.6 million of the Company's outstanding 12 3/4% Subordinated Debentures in 1995, reduce borrowings under the Company's revolving credit facility and improve corporate liquidity (see Note I). For further information related to exploration and production activities, see Note N. Marine Services In February 1996, the Company purchased 100% of the capital stock of Coastwide Energy Services, Inc. ("Coastwide"). The consideration included approximately 1.4 million shares of Tesoro's Common Stock and $7.7 million in cash. The market price of Tesoro's Common Stock was $9.00 per share at closing of this transaction. In addition, Tesoro repaid approximately $4.5 million of Coastwide's outstanding debt. Coastwide was primarily a provider of logistical support services and a distributor of petroleum products to the offshore oil and gas industry in the Gulf of Mexico. The Company combined the Coastwide operation with its marine petroleum distribution operations, forming a Marine Services segment. The acquisition was accounted for as a purchase whereby the purchase price was allocated to the assets acquired and liabilities assumed based upon their estimated fair values. NOTE D -- GAS PURCHASE AND SALES CONTRACT Resolution of Litigation in 1996 On August 16, 1996, the Supreme Court of Texas issued a mandate that denied a motion for rehearing by Tennessee Gas Pipeline Company ("Tennessee Gas") and upheld all aspects of a Gas Purchase and Sales Agreement ("Tennessee Gas Contract") which had been the subject of litigation since 1990. As provided for 54 57 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) in the Tennessee Gas Contract, the Company was selling a portion of the gas produced from the Bob West Field to Tennessee Gas at a maximum price as calculated in accordance with Section 102(b)(2) ("Contract Price") of the Natural Gas Policy Act of 1978. Subsequent to the mandate, the Company received cash of $67.7 million from Tennessee Gas, which included collection of a $59.6 million bonded receivable for underpayment for natural gas sold in prior periods. The remaining $8.1 million received was for interest and reimbursement of legal fees and court costs, which resulted in income during the 1996 third quarter. Tennessee Gas resumed paying the Contract Price to the Company for gas taken beginning with May 1996 volumes up until termination of the Tennessee Gas Contract discussed below. Settlement and Termination of Contract in 1996 On December 24, 1996, the Company settled all other claims and disputes with Tennessee Gas, including litigation in Zapata County, Texas filed by Tennessee Gas, and agreed to terminate the Tennessee Gas Contract effective October 1, 1996. The Tennessee Gas Contract would have extended through January 1999. Under the settlement, the Company received $51.8 million and the right to recover severance taxes paid by Tennessee Gas of approximately $8.2 million, which resulted in income of $60 million to the Company during the 1996 fourth quarter. The severance taxes were subsequently collected in 1997. NOTE E -- RECEIVABLES Concentrations of credit risk with respect to accounts receivable are limited, due to the large number of customers comprising the Company's customer base and their dispersion across the Company's industry segments and geographic areas of operations. The Company performs ongoing credit evaluations of its customers' financial condition and in certain circumstances requires letters of credit or other collateral arrangements. The Company's allowance for doubtful accounts is reflected as a reduction of receivables in the Consolidated Balance Sheets. The following table reconciles the change in the Company's allowance for doubtful accounts for the years ended December 31, 1997, 1996 and 1995 (in thousands):
1997 1996 1995 ------ ------ ------ Balance at Beginning of Year............................. $1,515 $1,842 $1,816 Charged to Costs and Expenses............................ 23 589 300 Recoveries of Amounts Previously Written Off and Other... 189 (44) 122 Write-off of Doubtful Accounts........................... (354) (872) (396) ------ ------ ------ Balance at End of Year................................. $1,373 $1,515 $1,842 ====== ====== ======
NOTE F -- INVENTORIES Components of inventories at December 31, 1997 and 1996 were as follows (in thousands):
1997 1996 ------- ------- Crude Oil and Wholesale Refined Products, at LIFO........... $68,227 $55,858 Merchandise and Other Refined Products...................... 13,377 13,539 Materials and Supplies...................................... 5,755 5,091 ------- ------- Total Inventories......................................... $87,359 $74,488 ======= =======
At December 31, 1997 and 1996, inventories valued using LIFO were lower than replacement cost by approximately $4.4 million and $17.7 million, respectively. 55 58 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) NOTE G -- ACCRUED LIABILITIES The Company's current accrued liabilities and noncurrent other liabilities as shown in the Consolidated Balance Sheets at December 31, 1997 and 1996 included the following (in thousands):
1997 1996 ------- ------- Accrued Liabilities -- Current: Accrued environmental costs............................... $ 5,817 $ 5,367 Accrued employee costs.................................... 12,406 7,759 Accrued taxes other than income taxes..................... 4,137 5,988 Accrued interest.......................................... 1,349 1,155 Other..................................................... 7,663 12,987 ------- ------- Total Accrued Liabilities -- Current................... $31,372 $33,256 ======= ======= Other Liabilities -- Noncurrent: Accrued postretirement benefits........................... $32,206 $30,508 Accrued environmental costs............................... 2,659 3,496 Other..................................................... 8,346 8,239 ------- ------- Total Other Liabilities -- Noncurrent.................. $43,211 $42,243 ======= =======
NOTE H -- INCOME TAXES The income tax provision for the years ended December 31, 1997, 1996 and 1995 included the following (in thousands):
1997 1996 1995 ------- ------- ------ Federal -- Current..................................... $ 3,413 $16,206 $ 708 Federal -- Deferred.................................... 9,421 17,405 -- Foreign................................................ 4,920 3,654 3,183 State.................................................. 681 1,082 488 ------- ------- ------ Income Tax Provision................................. $18,435 $38,347 $4,379 ======= ======= ======
Deferred income taxes and benefits are provided for differences between financial statement carrying amounts of assets and liabilities and their respective tax bases. Temporary differences and the resulting deferred tax assets and liabilities at December 31, 1997 and 1996 are summarized as follows (in thousands):
1997 1996 -------- -------- Deferred Federal Tax Assets: Investment tax and other credits.......................... $ 9,639 $ 11,962 Accrued postretirement benefits........................... 10,480 9,941 Settlement with Department of Energy...................... 3,233 3,694 Environmental reserve..................................... 3,048 3,335 Other..................................................... 5,265 1,523 -------- -------- Total Deferred Federal Tax Assets...................... 31,665 30,455 Deferred Federal Tax Liabilities: Accelerated depreciation and property-related items....... (57,778) (47,147) -------- -------- Net Deferred Federal Liability.............................. (26,113) (16,692) State Income and Other Taxes................................ (2,711) (2,459) -------- -------- Net Deferred Tax Liability................................ $(28,824) $(19,151) ======== ========
56 59 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following tables set forth the components of the Company's results of operations (in thousands) and a reconciliation of the normal statutory federal income tax rate with the Company's effective tax rate:
1997 1996 1995 ------- -------- ------- Earnings Before Income Taxes and Extraordinary Item: U.S................................................ $40,200 $106,675 $55,221 Foreign............................................ 8,920 8,472 6,647 ------- -------- ------- Total Earnings Before Income Taxes and Extraordinary Item............................ $49,120 $115,147 $61,868 ======= ======== ======= Statutory U.S. Corporate Tax Rate.................... 35% 35% 35% Effect of: Foreign income taxes, net of tax benefit........... 5 2 5 State income taxes, net of tax benefit............. 1 1 1 Accounting recognition of operating loss tax benefits........................................ -- (4) (33) Other.............................................. (4) (1) (1) ------- -------- ------- Effective Income Tax Rate............................ 37% 33% 7% ======= ======== =======
At December 31, 1997, the Company had approximately $6.9 million of investment tax credits and employee stock ownership credits available for carryover to subsequent years, which, if not used, will expire in the years 1999 through 2006. Additionally, at December 31, 1997, the Company had approximately $2.7 million of alternative minimum tax credit carryforwards, with no expiration dates, to offset future regular tax liabilities. NOTE I -- LONG-TERM DEBT AND OTHER OBLIGATIONS Long-term debt and other obligations at December 31, 1997 and 1996 consisted of the following (in thousands):
1997 1996 -------- ------- Liability to State of Alaska................................ $ 62,016 $62,079 Corporate Revolving Credit Facility......................... 28,000 -- Marine Services Loan Facility............................... 5,611 883 Hydrocracker Loan........................................... 16,200 -- Vacuum Unit Loan............................................ 9,107 11,250 Liability to Department of Energy........................... 9,235 10,555 Other....................................................... 2,147 4,536 -------- ------- 132,316 89,303 Less Current Maturities..................................... 17,002 10,043 -------- ------- $115,314 $79,260 ======== =======
Aggregate maturities of long-term debt and obligations for each of the five years following December 31, 1997 are as follows: 1998 -- $17.0 million; 1999 -- $11.9 million; 2000 -- $40.1 million; 2001 -- $13.6 million; and 2002 -- $5.6 million. In addition, in the year 2002, a $60 million payment is due to the State of Alaska, but may be deferred indefinitely, at the Company's option, by continuing a variable per barrel throughput charge described below. 57 60 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) State of Alaska In 1993, the Company entered into an agreement ("Agreement") with the State of Alaska ("State") that settled a contractual dispute with the State. Under the Agreement, the Company is obligated to make variable monthly payments to the State through December 2001 based on a per barrel charge on the volume of feedstock processed through the Company's refinery crude unit. In 1997 and 1996, based on a per barrel throughput charge of 24 cents, the Company's variable payments to the State totaled $4.4 million and $4.0 million, respectively. In 1995, based on a per barrel throughput charge of 16 cents, the Company's variable payments to the State totaled $2.9 million. The per barrel charge increases to 30 cents in 1998 with one cent annual incremental increases thereafter through 2001. In January 2002, the Company is obligated to pay the State $60 million; provided, however, that such payment may be deferred indefinitely, at the Company's option, by continuing the variable monthly payments to the State beginning at 34 cents per barrel for 2002 and increasing one cent per barrel annually thereafter. Variable monthly payments made after January 2002 will not reduce the $60 million obligation to the State. The imputed rate of interest used by the Company on the $60 million obligation was 13%. The $60 million obligation is evidenced by a security bond, and the bond and the throughput barrel obligations are collateralized by a fourth lien on the Company's refinery. The Company's obligations under the Agreement and the mortgage are subordinated to current and future senior debt of up to $175 million plus any indebtedness incurred subsequent to the date of the Agreement to improve the Company's refinery. Loans obtained to finance the expansion of the hydrocracker unit and install the vacuum unit, both discussed below, qualify as indebtedness incurred subsequent to the Agreement to improve the Company's refinery. Corporate Revolving Credit Facility The Company's amended and restated corporate revolving credit agreement ("Credit Facility"), which expires in April 2000, provides total commitments of $150 million from a consortium of nine banks. The Company, at its option, has currently activated $100 million of these commitments. The Credit Facility provides for the issuance of letters of credit, and for cash borrowings up to $100 million, with the aggregate subject to a borrowing base (which amount exceeded total commitments at December 31, 1997). Outstanding obligations under the Credit Facility are collateralized by first liens on substantially all of the Company's trade receivables, product inventories and South Texas natural gas reserves and by a third lien on the Company's refinery. At December 31, 1997, the Company had outstanding cash borrowings of $28 million under the Credit Facility. During 1997, gross borrowings under the Credit Facility were $150 million, with $122 million of repayments. During 1996 and 1995, the Company's gross borrowings equaled repayments under the Credit Facility and totaled $165 million and $262 million, respectively. These cash borrowings are generally used on a short-term basis to finance working capital requirements and capital expenditures. Under the Credit Facility, at December 31, 1997, the Company had outstanding letters of credit of $34 million, primarily for royalty crude oil purchases from the State of Alaska. Unused availability, including unactivated commitments, under the Credit Facility at December 31, 1997 for additional borrowings and letters of credit totaled $88 million. The Company is also permitted to utilize unsecured letters of credit outside of the Credit Facility up to $40 million (none outstanding at December 31, 1997). Cash borrowings under the Credit Facility bear interest at (i) the London Interbank Offered Rate ("LIBOR") plus 1.0% per annum or (ii) the prime rate per annum, at the Company's option. Fees on outstanding letters of credit under the Credit Facility are 1.0% per annum. The Credit Facility, which has been amended from time to time, requires the Company to maintain specified levels of consolidated working capital, tangible net worth, cash flow and interest coverage and contains other covenants customary in credit arrangements of this kind. Among other matters, the terms of the Credit Facility allow for general open market stock repurchases and the payment of cash dividends subject to a 58 61 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) cumulative amount available for restricted payments (defined as the difference of (i) the sum since December 31, 1995, of (a) $5 million and (b) 50% of consolidated net earnings of the Company in any calendar year and (ii) any restricted payments made since June 1996). At December 31, 1997, the cumulative amount available for restricted payments was approximately $58 million. In addition to the cumulative restriction, the Credit Facility further limits these general open market stock repurchases and cash dividends to a maximum of $5 million annually. The Credit Facility also permits the Company to repurchase a limited amount of Common Stock, up to $10 million annually, specifically for oddlot buyback programs and employee benefit or compensation plans. Marine Services Loan Facility In January 1998, the Company terminated a $10 million loan facility which had provided a three-year line of credit to the Marine Services segment at the bank's prime rate. The outstanding balance of $5.6 million at December 31, 1997 was repaid subsequent to year-end. Hydrocracker Loan In October 1997, the National Bank of Alaska ("NBA") and the Alaska Industrial Development and Export Authority ("AIDEA"), under a loan agreement ("Hydrocracker Loan") entered into between the Company and NBA, provided a $16.2 million loan to the Company towards the cost of its refinery hydrocracker expansion (see Note C). One-half of the loan was funded by NBA and the other half was funded by AIDEA. The Hydrocracker Loan matures on or before April 1, 2005 and requires 28 equal quarterly principal payments beginning April 1998 together with interest at the unsecured 90-day commercial paper rate (5.55% at December 31, 1997) adjusted quarterly plus (i) 2.6% per annum on 50% of the amount borrowed and (ii) 2.35% per annum on the other 50% borrowed. The Hydrocracker Loan is collateralized by a second lien on the refinery. Under the terms of the Hydrocracker Loan, the Company is required to maintain specified levels of working capital and tangible net worth. Vacuum Unit Loan In 1994, the NBA and the AIDEA provided a $15 million loan to the Company towards the cost of the Company's refinery vacuum unit ("Vacuum Unit Loan"). The Vacuum Unit Loan matures January 1, 2002, requires equal quarterly payments of approximately $536,000 and bears interest at the unsecured 90-day commercial paper rate, adjusted quarterly, plus 2.6% per annum (8.11% at December 31, 1997) for two-thirds of the amount borrowed and at the National Bank of Alaska floating prime rate plus one-fourth of 1% per annum (8.75% at December 31, 1997) for the remainder. The Vacuum Unit Loan is collateralized by a first lien on the Company's refinery. Under the terms of the Vacuum Unit Loan, as amended, the Company is required to maintain specified levels of working capital and tangible net worth. Department of Energy A Consent Order entered into by the Company with the Department of Energy ("DOE") in 1989 settled all issues relating to the Company's compliance with federal petroleum price and allocation regulations from 1973 through decontrol in 1981. At December 31, 1997, the Company's remaining obligation is to pay the DOE $9.2 million, exclusive of interest at 6%, over the next five years. Repurchase of Debentures and Notes In November 1996, the Company fully redeemed its two public debt issues, totaling approximately $74 million, at a price equal to 100% of the principal amount, plus accrued interest to the redemption date. The redemption of debt was comprised of $44.1 million of outstanding 13% Exchange Notes and $30 million of outstanding 12 3/4% Subordinated Debentures ("Subordinated Debentures"). The redemption was 59 62 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) accounted for as an early extinguishment of debt in the 1996 third quarter, resulting in a pretax charge of $3.2 million ($2.3 million aftertax) which represented a write-off of unamortized bond discount and issue costs. The extraordinary loss on debt extinguishments of $2.9 million in 1995 related to the redemption of $34.6 million principal amount of Subordinated Debentures in December 1995. NOTE J -- BENEFIT PLANS Retirement Plan For all eligible employees, the Company provides a qualified noncontributory retirement plan. Plan benefits are based on years of service and compensation. The Company's funding policy is to make contributions at a minimum in accordance with the requirements of applicable laws and regulations, but no more than the amount deductible for income tax purposes. The components of net pension expense for the Company's retirement plan for the years ended December 31, 1997, 1996 and 1995 are presented below (in thousands):
1997 1996 1995 ------- ------- ------- Service Costs......................................... $ 1,502 $ 1,306 $ 1,147 Interest Cost......................................... 3,696 3,536 3,549 Actual Return on Plan Assets.......................... (8,817) (6,212) (8,299) Net Amortization and Deferral......................... 4,105 1,687 4,288 ------- ------- ------- Net Pension Expense................................. $ 486 $ 317 $ 685 ======= ======= =======
The funded status of the Company's retirement plan and amounts included in the Company's Consolidated Balance Sheets at December 31, 1997 and 1996 are set forth in the following table (in thousands):
1997 1996 ------- ------- Actuarial Present Value of Benefit Obligation: Vested benefit obligation................................. $41,601 $40,539 ======= ======= Accumulated benefit obligation............................ $44,877 $43,404 ======= ======= Plan Assets at Fair Value................................... $50,982 $46,356 Projected Benefit Obligation................................ 52,685 50,163 ------- ------- Plan Assets Less Than Projected Benefit Obligation.......... (1,703) (3,807) Unrecognized Net Loss....................................... 2,003 5,903 Unrecognized Prior Service Costs............................ (267) (341) Unrecognized Net Transition Asset........................... (1,940) (3,176) ------- ------- Accrued Pension Liability................................. $(1,907) $(1,421) ======= =======
Retirement plan assets are primarily comprised of common stock and bond funds. Actuarial assumptions used to measure the projected benefit obligations included a discount rate of 7 1/2% and a compensation increase rate of 5% for December 31, 1997, 1996 and 1995. The expected long-term rate of return on assets was 8 1/2% for 1997, 1996 and 1995. 60 63 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Executive Security Plan The Company's executive security plan ("ESP") provides executive officers and other key personnel with supplemental death or retirement benefits in addition to those benefits available under the Company's group life insurance and retirement plans. These supplemental retirement benefits are provided by a nonqualified, noncontributory plan and are based on years of service and compensation. Contributions are made by the Company based upon the estimated requirements of the plan. The components of net pension expense for the ESP for the years ended December 31, 1997, 1996 and 1995 are presented below (in thousands):
1997 1996 1995 ------ ----- ----- Service Costs............................................. $ 521 $ 354 $ 364 Interest Cost............................................. 363 204 205 Actual Return on Plan Assets.............................. (596) (439) (325) Net Amortization and Deferral............................. 1,196 751 471 ------ ----- ----- Net Pension Expense..................................... $1,484 $ 870 $ 715 ====== ===== =====
During 1997, 1996 and 1995, the Company incurred additional ESP expense of $1.2 million, $0.9 million and $1.5 million, respectively, for settlements, curtailments and other benefits resulting from employee terminations. The funded status of the ESP and amounts included in the Company's Consolidated Balance Sheets at December 31, 1997 and 1996 are set forth in the following table (in thousands):
1997 1996 ------ ------ Actuarial Present Value of Benefit Obligation: Vested benefit obligation................................. $4,885 $3,300 ====== ====== Accumulated benefit obligation............................ $5,585 $4,434 ====== ====== Plan Assets at Fair Value................................... $7,732 $7,139 Projected Benefit Obligation................................ 8,683 6,467 ------ ------ Plan Assets in Excess of (Less Than) Projected Benefit Obligation................................................ (951) 672 Unrecognized Net Loss....................................... 6,442 4,532 Unrecognized Prior Service Costs............................ 895 537 Unrecognized Net Transition Obligation...................... 314 417 ------ ------ Prepaid Pension Asset..................................... $6,700 $6,158 ====== ======
Assets of the ESP consist of a group annuity contract. Actuarial assumptions used to measure the projected benefit obligation at December 31, 1997, 1996 and 1995 included a discount rate of 7 1/2% and a compensation increase rate of 5%. The expected long-term rate of return on assets was 7% for 1997 and 8% for 1996 and 1995. Retiree Health Care and Life Insurance Benefits The Company provides health care and life insurance benefits to retirees who were participating in the Company's group insurance program at retirement. Health care is also provided to qualified dependents of participating retirees. These benefits are provided through unfunded, defined benefit plans. The health care plans are contributory, with retiree contributions adjusted periodically, and contain other cost-sharing features such as deductibles and coinsurance. The life insurance plan is noncontributory. The Company funds its share of the cost of postretirement health care and life insurance benefits on a pay-as-you-go basis. The components 61 64 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) of net periodic postretirement benefits expense, other than pensions, for the years ended December 31, 1997, 1996 and 1995 included the following (in thousands):
1997 1996 1995 ------ ------ ------ Health Care: Service costs.......................................... $ 676 $ 558 $ 447 Interest costs......................................... 1,304 1,294 1,399 ------ ------ ------ Net Periodic Postretirement Expense................. $1,980 $1,852 $1,846 ====== ====== ====== Life Insurance: Service costs.......................................... $ 190 $ 158 $ 174 Interest costs......................................... 580 548 584 ------ ------ ------ Net Periodic Postretirement Expense................. $ 770 $ 706 $ 758 ====== ====== ======
The following tables show the status of the plans reconciled with the amounts in the Company's Consolidated Balance Sheets at December 31, 1997 and 1996 (in thousands):
1997 1996 ------- ------- Health Care: Accumulated Postretirement Benefit Obligation -- Retirees.................................................. $12,591 $12,549 Active participants eligible to retire.................... 1,638 1,203 Other active participants................................. 4,584 4,181 ------- ------- 18,813 17,933 Unrecognized Net Gain....................................... 3,211 2,621 ------- ------- Accrued Postretirement Benefit Liability............... $22,024 $20,554 ======= ======= Life Insurance: Accumulated Postretirement Benefit Obligation -- Retirees.................................................. $ 6,393 $ 6,274 Active participants eligible to retire.................... 608 484 Other active participants................................. 1,299 1,205 ------- ------- 8,300 7,963 Unrecognized Net Loss....................................... (380) (115) ------- ------- Accrued Postretirement Benefit Liability............... $ 7,920 $ 7,848 ======= =======
The weighted average annual rate of increase in the per capita cost of covered health care benefits is assumed to be 8% for 1998, decreasing gradually to 6% by the year 2005 and remaining at that level thereafter. This health care cost trend rate assumption has a significant effect on the amount of the obligation and periodic cost reported. For example, an increase in the assumed health care cost trend rates by one percentage point in each year would increase the accumulated postretirement obligation at December 31, 1997 by $3.8 million and the aggregate of service cost and interest cost components of net periodic postretirement benefits for the year then ended by $0.5 million. Actuarial assumptions used to measure the accumulated postretirement benefit obligation at December 31, 1997, 1996 and 1995 included a discount rate of 7 1/2% and a compensation rate increase of 5%. Thrift Plan The Company sponsors an employee thrift plan which provides for contributions by eligible employees into designated investment funds with a matching contribution by the Company. Employees may contribute 62 65 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) up to 10% of their compensation, subject to certain limitations, and may elect tax deferred treatment in accordance with the provisions of Section 401(k) of the Internal Revenue Code. Effective October 1, 1996, the thrift plan was amended to change the Company's matching contribution from 50% (of up to 6% of the employee's eligible contribution) to 100% (of up to 4% of the employee's eligible contributions), with at least 50% of the Company's match invested in Common Stock of the Company. The Company's contributions amounted to $1.2 million, $0.8 million and $0.4 million during 1997, 1996 and 1995, respectively. Non-Employee Director Retirement Plan and Phantom Stock Plan The Company had previously established an unfunded Non-Employee Director Retirement Plan ("Director Retirement Plan"), which provided that any eligible non-employee director who had served on the Company's Board of Directors for at least three full years would be entitled to a retirement payment in cash beginning the later of the director's sixty-fifth birthday or such later date that the individual's service as a director ended. However, to more closely align director compensation with shareholders' interests, in March 1997, the Board of Directors amended the Director Retirement Plan to freeze the plan and convert all of the accrued benefits of the current directors under the plan to a lump-sum present value which was transferred to and became the initial account balance of the directors in the Tesoro Petroleum Corporation Board of Directors Deferred Phantom Stock Plan ("Phantom Stock Plan"). After the amendment and transfer, only those retired directors or beneficiaries who had begun receiving benefits remained participants in the Director Retirement Plan. At December 31, 1997 and 1996, the projected benefit obligation and present value of the vested and accumulated benefit obligations, discounted at 7 1/2%, of the Director Retirement Plan were estimated to be $0.4 million and $0.8 million, respectively. The Company's Consolidated Balance Sheets at December 31, 1997 and 1996 included $0.4 million and $0.7 million, respectively, in other liabilities related to the Director Retirement Plan. Upon establishment of the Phantom Stock Plan, the lump-sum accrued benefit of each of the current non-employee directors was transferred from the Director Retirement Plan into an account ("Account") in the Phantom Stock Plan. Under the Phantom Stock Plan, a yearly credit of $7,250 (prorated to $6,042 for 1997) is made to the Account of each director in units, based upon the closing market price of the Company's Common Stock on the date of credit. In addition, a director may elect to have the value of his cash retainer fee deposited quarterly into the Account in units. The value of each Account balance, which is a function of the amount, if any, by which the market value of the Company's Common Stock changes, is payable in cash at retirement, death, disability or termination, if vested. In 1997, the Company incurred expenses of approximately $127,000 related to the Phantom Stock Plan due to the increase in the market price of the Company's Common Stock. NOTE K -- STOCKHOLDERS' EQUITY Stock Repurchase Program On May 7, 1997, the Company's Board of Directors authorized the repurchase of up to 3 million shares (approximately 11% of current outstanding shares) of Tesoro Common Stock in a buyback program that will extend through the end of 1998. Under the program, subject to certain conditions, the Company may repurchase from time to time Tesoro Common Stock in the open market and through privately negotiated transactions. Purchases will depend on price, market conditions and other factors and will be made primarily from cash flows. The repurchased Common Stock is accounted for as treasury stock and may be used for employee benefit plan requirements and other corporate purposes. During 1997, the Company used cash flows of $3.7 million to repurchase 236,800 shares of Common Stock, of which 20,347 shares have been reissued for an employee benefit plan. For information related to restrictions under the Credit Facility, see Note I. 63 66 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Stock Plans and Incentive Compensation Strategy The Company has two employee incentive stock plans, the Amended and Restated Executive Long-Term Incentive Plan ("1993 Plan") and Amended Incentive Stock Plan of 1982 ("1982 Plan"), and the 1995 Non-Employee Director Stock Option Plan ("1995 Plan") (collectively, the "Plans"). Shares of unissued Common Stock reserved for the Plans were 2,717,611 at December 31, 1997. The 1993 Plan provides for the grant of up to 2,650,000 shares of the Company's Common Stock in a variety of forms, including restricted stock, incentive stock options, nonqualified stock options, stock appreciation rights and performance share and performance unit awards. Stock options may be granted at exercise prices not less than the fair market value on the date the options are granted. The options granted generally become exercisable after one year in 20%, 25% or 33% increments per year and expire ten years from date of grant. The 1993 Plan will expire, unless earlier terminated, as to the issuance of awards in the year 2003. At December 31, 1997, the Company had 66,420 shares available for future grants under the 1993 Plan. In 1997, the Compensation Committee of the Board of Directors granted 175,000 phantom stock options to an executive officer of the Company. These phantom stock options, which were granted at 100% of the fair market value of the Company's Common Stock on the grant date, vest in 15% increments in each of the first three years and the remaining 55% increment vests in the fourth year. Upon exercise, the executive officer would be entitled to receive in cash the difference between the fair market value of the Common Stock on the date of the phantom stock option grant and the fair market value of Common Stock on the date of exercise. At the discretion of the Compensation Committee, these phantom stock options may be converted to traditional stock options upon sufficient shares becoming available under the 1993 Plan. The 1982 Plan expired in 1994 as to issuance of stock appreciation rights, stock options and stock awards; however, grants made before the expiration date that have not been fully exercised remain outstanding pursuant to their terms. The 1995 Plan provides for the grant of up to an aggregate of 150,000 nonqualified stock options to eligible non-employee directors of the Company. The option price per share is equal to the fair market value per share of the Company's Common Stock on the date of grant. The term of each option is ten years, and an option first becomes exercisable six months after the date of grant. Under the 1995 Plan, each person serving as a non-employee director on February 23, 1995 or elected thereafter, initially received an option to purchase 5,000 shares of Common Stock. Thereafter, each non-employee director, while the 1995 Plan is in effect and shares are available to grant, will be granted an option to purchase 1,000 shares of Common Stock on the next day after each annual meeting of the Company's stockholders but not later than June 1, if no annual meeting is held. At December 31, 1997, the Company had 68,000 options outstanding and 77,000 shares available for future grants under the 1995 Plan. In June 1996, the Company's Board of Directors unanimously approved a special incentive compensation strategy in order to encourage a longer-term focus for all employees to perform at an outstanding level. The strategy provides eligible employees with incentives to achieve a significant increase in the market price of the Company's Common Stock. Under the strategy, awards would be earned only if the market price of the Company's Common Stock reaches an average price per share of $20 or higher over any 20 consecutive trading days after June 30, 1997 and before December 31, 1998 (the "Performance Target"). In connection with this strategy, non-executive employees will be able to earn cash bonuses equal to 25% of their individual payroll amounts for the previous twelve complete months and certain executives have been granted, from the 1993 Plan, a total of 340,000 stock options at an exercise price of $11.375 per share, the fair market value (as defined in the 1993 Plan) of a share of the Company's Common Stock on the date of grant, and 350,000 shares of restricted Common Stock, all of which vest only upon achieving the Performance Target. 64 67 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) A summary of stock option activity in the Plans is set forth below:
NUMBER OF OPTIONS WEIGHTED-AVERAGE OUTSTANDING EXERCISE PRICE ----------- ---------------- Outstanding December 31, 1994............................ 1,496,293 $ 6.37 Granted................................................ 450,000 8.34 Exercised.............................................. (507,467) 4.85 Forfeited and expired.................................. (266,745) 9.10 --------- Outstanding December 31, 1995............................ 1,172,081 7.16 Granted................................................ 1,095,500 13.45 Exercised.............................................. (315,664) 5.67 Forfeited and expired.................................. (95,171) 8.50 --------- Outstanding December 31, 1996............................ 1,856,746 11.05 Granted................................................ 431,000 16.73 Exercised.............................................. (43,800) 8.45 Forfeited and expired.................................. (36,013) 8.40 --------- Outstanding December 31, 1997............................ 2,207,933 12.26 =========
At December 31, 1997, 1996 and 1995, exercisable stock options totaled 0.7 million, 0.4 million and 0.4 million, respectively. The following table summarizes information about stock options outstanding under the Plans at December 31, 1997:
OPTIONS OUTSTANDING ------------------------------------------------- OPTIONS EXERCISABLE WEIGHTED-AVERAGE ------------------------------ RANGE OF NUMBER REMAINING WEIGHTED-AVERAGE NUMBER WEIGHTED-AVERAGE EXERCISE PRICES OUTSTANDING CONTRACTUAL LIFE EXERCISE PRICE EXERCISABLE EXERCISE PRICE --------------- ----------- ---------------- ---------------- ----------- ---------------- $ 3.92 to $ 7.19 179,740 5.2 years $ 4.52 159,272 $ 4.42 $ 7.20 to $10.45 551,100 7.5 years 8.65 279,300 8.84 $10.46 to $13.72 398,593 8.4 years 11.41 31,593 11.68 $13.73 to $16.98 1,078,500 9.2 years 15.72 210,173 14.94 --------- --------- $ 3.92 to $16.98 2,207,933 8.3 years 12.26 680,338 9.82 ========= =========
The Company applies APB No. 25 and related interpretations in accounting for its stock plans. Accordingly, no compensation expense has been recognized for stock option transactions or the incentive compensation strategy discussed above. Had compensation cost for the Plans been determined based on the fair value at the grant dates for awards (granted after January 1, 1995) in accordance with SFAS No. 123, "Accounting for Stock-Based Compensation," the Company's pro forma net earnings in 1997, 1996 and 1995 would have been approximately $28.5 million ($1.08 per basic share, $1.06 per diluted share), $72.6 million ($2.79 per basic share, $2.74 per diluted share), and $53.8 million ($2.19 per basic share, $2.15 per diluted share), respectively. The fair value of each option grant was estimated on the date of grant using the Black- Scholes option-pricing model with the following weighted-average assumptions: expected volatility of 32%, 30% and 45%; risk free interest rates of 6.7%, 6.6% and 6.1%; expected lives of seven years; and no dividend yields for 1997, 1996 and 1995, respectively. The estimated fair value per share of options granted during 1997, 1996 and 1995 were $5.96, $4.26 and $3.65, respectively, and the fair value per share of restricted stock awards in 1996 was $0.95 per share. 65 68 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) NOTE L -- COMMITMENTS AND CONTINGENCIES Operating Leases The Company has various noncancellable operating leases related to buildings, equipment, property and other facilities. These long-term leases have remaining primary terms generally up to ten years, with terms of certain rights-of-way extending up to 34 years, and generally contain multiple renewal options. Future minimum annual lease payments as of December 31, 1997, for operating leases having initial or remaining noncancelable lease terms in excess of one year, excluding marine charters, were as follows (in thousands): 1998........................................................ $ 6,135 1999........................................................ 3,378 2000........................................................ 2,907 2001........................................................ 2,514 2002........................................................ 2,272 Remainder................................................... 13,962 ------- Total Minimum Lease Payments.............................. $31,168 =======
In addition to the long-term lease commitments above, the Company has leases for two vessels that are primarily used to transport crude oil and refined products to and from the Company's refinery. At December 31, 1997, future minimum annual lease payments remaining for these two vessels, which include operating costs, are approximately $28 million for each of the years 1998 and 1999 and $16 million for the year 2000. Operating costs related to these vessels, which may vary from year to year, comprised approximately 30% of the total minimum payments during 1997. The Company also enters into various month-to-month and other short-term rentals, including a charter of a vessel primarily used to transport refined products from the Company's refinery to the Far East. Total rental expense for short-term and long-term leases, excluding marine charters, amounted to approximately $11 million, $12 million and $10 million for 1997, 1996 and 1995, respectively. In addition, expenses related to charters of marine vessels were approximately $34 million, $30 million and $26 million for 1997, 1996 and 1995, respectively. Environmental The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, which change frequently, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites or install additional controls or other modifications or changes in use for certain emission sources. The Company is currently involved with a waste disposal site near Abbeville, Louisiana, at which it has been named a potentially responsible party under the Federal Superfund law. Although this law might impose joint and several liability upon each party at the site, the extent of the Company's allocated financial contributions to the cleanup of the site is expected to be limited based upon the number of companies, volumes of waste involved, and an estimated total cost of approximately $500,000 among all of the parties to close the site. The Company is currently involved in settlement discussions with the Environmental Protection Agency ("EPA") and other potentially responsible parties at the Abbeville, Louisiana site. The Company expects, based on these discussions, that its liability will not exceed $25,000. The Company is also involved in remedial responses and has incurred cleanup expenditures associated with environmental matters at a number of sites, including certain of its own properties. At December 31, 1997, the Company's accruals for environmental expenses amounted to $8.5 million, which included a noncurrent liability of $2.7 million for remediation of the Kenai Pipe Line Company's 66 69 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) ("KPL") properties that has been funded by the former owners of KPL through a restricted escrow deposit. Based on currently available information, including the participation of other parties or former owners in remediation actions, the Company believes these accruals are adequate. To comply with environmental laws and regulations, the Company anticipates that it will make capital improvements of approximately $7 million in 1998 and $2 million in 1999. In addition, capital expenditures for alternative secondary containment systems for existing storage tank facilities are estimated to be $2 million in 1998 and $2 million in 1999 with a remaining $5 million to be spent by 2002. Conditions that require additional expenditures may exist for various Company sites, including, but not limited to, the Company's refinery, retail gasoline stations (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 Contracts The Company has a contract with the State of Alaska for the purchase of royalty crude oil covering the period January 1, 1996 through December 31, 1998. The contract provides for the purchase of 30% of the State's ANS royalty crude oil produced from the Prudhoe Bay Unit at prices based on royalty values computed by the State. During 1997, the Company purchased approximately 35,700 barrels per day of ANS crude oil under this contract. The contract contains provisions that, under certain conditions, allow the Company to temporarily or permanently reduce its purchase obligations. Under this contract, the Company is required to utilize in its refinery operations volumes equal to at least 80% of the ANS crude oil purchased from the State. The Company is presently in discussions with the State in regard to extending this contract for an additional year. The Company also purchases approximately 6,000 barrels per day of ANS crude oil from a producer under a contract with a term of one year beginning January 1, 1998. During October 1997, the Company began purchasing all of the approximately 34,000 barrels per day of Cook Inlet crude oil production from various producers under contracts extending through December 1998. A contract to purchase 4,500 barrels per day, of the 34,000 barrels per day, has been extended through March 31, 2001. 67 70 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) NOTE M -- QUARTERLY FINANCIAL DATA (UNAUDITED)
QUARTERS --------------------------------- TOTAL FIRST SECOND THIRD FOURTH YEAR ------ ------ ------ ------ -------- (IN MILLIONS EXCEPT PER SHARE AMOUNTS) 1997 Revenues: Gross operating revenues........................ $233.3 $210.7 $251.0 $242.9 $ 937.9 Other income.................................... 1.6 2.6 0.4 0.9 5.5 ------ ------ ------ ------ -------- Total Revenues............................. $234.9 $213.3 $251.4 $243.8 $ 943.4 ====== ====== ====== ====== ======== Operating Profit................................... $ 15.0 $ 19.9 $ 19.4 $ 18.4 $ 72.7 ====== ====== ====== ====== ======== Net Earnings....................................... $ 6.1 $ 9.7 $ 8.0 $ 6.9 $ 30.7 ====== ====== ====== ====== ======== Net Earnings Per Share -- Basic.................... $ 0.23 $ 0.36 $ 0.30 $ 0.26 $ 1.16 Net Earnings Per Share -- Diluted.................. $ 0.23 $ 0.36 $ 0.30 $ 0.26 $ 1.14 1996 Revenues: Gross operating revenues........................ $238.6 $233.8 $262.8 $240.2 $ 975.4 Income from settlement of natural gas contract...................................... -- -- -- 60.0 60.0 Other income.................................... 5.0 0.1 (0.7) -- 4.4 ------ ------ ------ ------ -------- Total Revenues............................. $243.6 $233.9 $262.1 $300.2 $1,039.8 ====== ====== ====== ====== ======== Operating Profit................................... $ 20.7 $ 27.6 $ 25.2 $ 71.3 $ 144.8 ====== ====== ====== ====== ======== Earnings Before Extraordinary Item................. $ 6.0 $ 12.0 $ 16.2 $ 42.6 $ 76.8 Extraordinary Loss on Debt Extinguishments, Net.... -- -- (2.3) -- (2.3) ------ ------ ------ ------ -------- Net Earnings............................... $ 6.0 $ 12.0 $ 13.9 $ 42.6 $ 74.5 ====== ====== ====== ====== ======== Net Earnings Per Share -- Basic.................... $ 0.24 $ 0.46 $ 0.53 $ 1.62 $ 2.87 Net Earnings Per Share -- Diluted.................. $ 0.23 $ 0.45 $ 0.52 $ 1.59 $ 2.81
Pretax other income related to severance tax refunds of $1.6 million and $0.2 million were recorded in the 1997 first and second quarters, respectively. Pretax other income of $2.2 million related to the collection of a Bolivian receivable for prior years production was recorded in the 1997 second quarter. The 1996 first quarter included pretax other income of $5 million related to retroactive severance tax refunds. The 1996 third quarter included pretax income of $8 million for interest and reimbursement of costs from Tennessee Gas (see Note D) and an aftertax extraordinary loss of $2.3 million for the early extinguishment of debt (see Note I). The contract with Tennessee Gas was terminated during the 1996 fourth quarter resulting in pretax income of $60 million (see Note D). Operating profit included approximately $8 million pretax in each of the first, second and third quarters of 1996 from the excess of natural gas contract prices over spot market prices. 68 71 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) NOTE N -- OIL AND GAS PRODUCING ACTIVITIES The information presented below represents the oil and gas producing activities of the Company's Exploration and Production segment, excluding amounts related to its U.S. natural gas transportation operations. Other information pertinent to the Exploration and Production segment is contained in Notes B, C and D. Capitalized Costs Relating to Oil and Gas Producing Activities
DECEMBER 31, -------------------------------- 1997 1996 1995 -------- -------- -------- (IN THOUSANDS) Capitalized Costs: Proved properties................................ $251,604 $179,433 $119,836 Unproved properties not being amortized.......... 31,918 12,344 5,118 -------- -------- -------- 283,522 191,777 124,954 Accumulated depreciation, depletion and amortization.................................. 112,562 78,222 51,549 -------- -------- -------- Net Capitalized Costs......................... $170,960 $113,555 $ 73,405 ======== ======== ========
The Company's investment in oil and gas properties included $31.9 million in unevaluated properties, primarily undeveloped leasehold costs and seismic costs, which have been excluded from the amortization base at December 31, 1997. Of this amount, $26.3 million and $5.6 million of such costs were incurred in 1997 and 1996, respectively. The Company anticipates that the majority of these costs will be included in the amortization base during the next two years. Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
U.S. BOLIVIA TOTAL ------- ------- ------- (IN THOUSANDS) 1997 Property acquisitions -- Proved........................................... $14,723 $11,892 $26,615 Unproved......................................... 7,127 3,370 10,497 Exploration......................................... 24,584 10,972 35,556 Development......................................... 17,798 1,279 19,077 ------- ------- ------- $64,232 $27,513 $91,745 ======= ======= ======= 1996 Property acquisitions -- Proved........................................... $20,454 $ -- $20,454 Unproved......................................... 5,216 -- 5,216 Exploration......................................... 11,830 6,704 18,534 Development......................................... 22,228 149 22,377 ------- ------- ------- $59,728 $ 6,853 $66,581 ======= ======= ======= 1995 Property acquisition, unproved...................... $ 1,432 $ -- $ 1,432 Exploration......................................... 10,011 2,994 13,005 Development......................................... 38,003 792 38,795 ------- ------- ------- $49,446 $ 3,786 $53,232 ======= ======= =======
69 72 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Results of Operations from Oil and Gas Producing Activities The following table sets forth the results of operations for oil and gas producing activities, in the aggregate by geographic area, with income tax expense computed using the statutory tax rate for the period adjusted for permanent differences, tax credits and allowances.
U.S. BOLIVIA TOTAL ---- -------- ----- (IN THOUSANDS EXCEPT AS INDICATED) 1997 Gross revenues -- sales to unaffiliates(a)........ $ 68,843 $11,189 $ 80,032 Production costs.................................. 7,424 932 8,356 Administrative support and other.................. 2,217 2,321 4,538 Depreciation, depletion and amortization.......... 29,350 1,538 30,888 Other income(b)................................... 3,238 2,184 5,422 -------- ------- -------- Pretax results of operations...................... 33,090 8,582 41,672 Income tax expense................................ 11,582 4,915 16,497 -------- ------- -------- Results of operations from producing activities(c).................................. $ 21,508 $ 3,667 $ 25,175 ======== ======= ======== Depletion per net equivalent thousand cubic feet ("Mcfe")....................................... $ 0.93 $ 0.19 ======== ======= 1996 Gross revenues -- sales to unaffiliates(a)........ $ 88,358 $13,701 $102,059 Production costs.................................. 5,326 837 6,163 Administrative support and other.................. 3,649 2,830 6,479 Depreciation, depletion and amortization.......... 25,235 1,279 26,514 Income from settlement of a natural gas contract(d).................................... 60,000 -- 60,000 Income from severance tax refunds................. 5,000 -- 5,000 -------- ------- -------- Pretax results of operations...................... 119,148 8,755 127,903 Income tax expense................................ 41,702 5,439 47,141 -------- ------- -------- Results of operations from producing activities(c).................................. $ 77,446 $ 3,316 $ 80,762 ======== ======= ======== Depletion per Mcfe................................ $ 0.79 $ 0.15 ======== ======= 1995 Gross revenues -- sales to unaffiliates(a)........ $107,276 $11,707 $118,983 Production costs.................................. 12,005 600 12,605 Administrative support and other.................. 2,842 3,289 6,131 Gain on sales of assets(e)........................ 33,532 -- 33,532 Depreciation, depletion and amortization.......... 29,004 250 29,254 -------- ------- -------- Pretax results of operations...................... 96,957 7,568 104,525 Income tax expense................................ 33,935 4,718 38,653 -------- ------- -------- Results of operations from producing activities(c).................................. $ 63,022 $ 2,850 $ 65,872 ======== ======= ======== Depletion per Mcfe................................ $ 0.69 $ 0.03 ======== =======
- --------------- (a) Revenues included the effects of natural gas commodity price agreements which amounted to losses of $1.6 million ($0.05 per thousand cubic feet ("Mcf")) and $3.1 million ($0.11 per Mcf) in 1997 and 1996, respectively, and to a gain of $0.3 million ($0.01 per Mcf) in 1995. The Company had entered into these agreements to reduce risks caused by fluctuations in the prices of natural gas in the spot market. During 1997, 1996 and 1995, the Company used such agreements to set the price of 9%, 30% and 38%, 70 73 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) respectively, of the natural gas that it sold in the spot market. The Company has no remaining natural gas price agreements outstanding at December 31, 1997. (b) Primarily represents income from retroactive severance tax refunds in the U.S. operations and income related to a collection of a receivable in Bolivian operations. (c) Excludes corporate general and administrative expenses and financing costs. (d) See Note D. (e) Represents gain on sale of certain interests in the Bob West Field (see Note C). Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves (Unaudited) The following table sets forth the computation of the standardized measure of discounted future net cash flows relating to proved reserves and the changes in such cash flows in accordance with SFAS No. 69. The standardized measure is the estimated excess future cash inflows from proved reserves less estimated future production and development costs, estimated future income taxes and a discount factor. Future cash inflows represent expected revenues from production of year-end quantities of proved reserves based on year-end prices and any fixed and determinable future escalation provided by contractual arrangements in existence at year-end. Escalation based on inflation, federal regulatory changes and supply and demand are not considered. Estimated future production costs related to year-end reserves are based on year-end costs. Such costs include, but are not limited to, production taxes and direct operating costs. Inflation and other anticipatory costs are not considered until the actual cost change takes effect. Estimated future income tax expenses are computed using the appropriate year-end statutory tax rates. Consideration is given for the effects of permanent differences, tax credits and allowances. A discount rate of 10% is applied to the annual future net cash flows. The methodology and assumptions used in calculating the standardized measure are those required by SFAS No. 69. The standardized measure is not intended to be representative of the fair market value of the Company's proved reserves. The calculations of revenues and costs do not necessarily represent the amounts to be received or expended by the Company.
U.S. BOLIVIA TOTAL -------- -------- -------- (IN THOUSANDS) DECEMBER 31, 1997 Future cash inflows.............................. $347,904 $490,337 $838,241 Future production costs.......................... 81,011 86,546 167,557 Future development costs......................... 29,362 48,860 78,222 -------- -------- -------- Future net cash flows before income tax expense....................................... 237,531 354,931 592,462 10% annual discount factor....................... 70,036 148,461 218,497 -------- -------- -------- Discounted future net cash flows before income taxes......................................... 167,495 206,470 373,965 Discounted future income tax expense(a).......... 32,284 107,318 139,602 -------- -------- -------- Standardized measure of discounted future net cash flows(b)................................. $135,211 $ 99,152 $234,363 ======== ======== ========
71 74 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
U.S. BOLIVIA TOTAL -------- -------- -------- (IN THOUSANDS) DECEMBER 31, 1996 Future cash inflows.............................. $376,103 $368,119 $744,222 Future production costs.......................... 66,524 72,766 139,290 Future development costs......................... 13,156 30,632 43,788 -------- -------- -------- Future net cash flows before income tax expense....................................... 296,423 264,721 561,144 10% annual discount factor....................... 73,687 130,915 204,602 -------- -------- -------- Discounted future net cash flows before income taxes......................................... 222,736 133,806 356,542 Discounted future income tax expense (a)......... 70,251 80,102 150,353 -------- -------- -------- Standardized measure of discounted future net cash flows.................................... $152,485 $ 53,704 $206,189 ======== ======== ======== DECEMBER 31, 1995 Future cash inflows.............................. $265,379 $120,510 $385,889 Future production costs.......................... 53,095 32,005 85,100 Future development costs......................... 8,625 7,548 16,173 -------- -------- -------- Future net cash flows before income tax expense....................................... 203,659 80,957 284,616 10% annual discount factor....................... 34,920 32,231 67,151 -------- -------- -------- Discounted future net cash flows before income taxes......................................... 168,739 48,726 217,465 Discounted future income tax expense(a).......... 45,939 25,897 71,836 -------- -------- -------- Standardized measure of discounted future net cash flows.................................... $122,800 $ 22,829 $145,629 ======== ======== ========
- --------------- (a) For Bolivia, the discounted future income tax expense includes Bolivian taxes of $105.0 million, $69.4 million and $21.6 million as of December 31, 1997, 1996 and 1995, respectively, and U.S. income taxes of $2.3 million, $10.7 million and $4.3 million at December 31, 1997, 1996 and 1995, respectively. (b) Gross rates for the Company's Bolivian production were increased from 40 million cubic feet ("MMcf") per day to 120 MMcf per day in the year 2000 due to the anticipated completion of the Bolivia-Brazil pipeline during early 1999 as discussed in Note B. This increase accounted for approximately $57 million of the standardized measure of discounted future net cash flows for Bolivia at December 31, 1997. Changes in Standardized Measure of Discounted Future Net Cash Flows (Unaudited)
1997 1996 1995 -------- -------- --------- (IN THOUSANDS) Sales of oil and gas produced, net of production costs............................................. $(69,567) $(93,275) $(106,378) Net changes in prices and production costs.......... (88,473) 39,409 (32,931) Extensions, discoveries and improved recovery....... 42,191 81,201 83,045 Changes in future development costs................. (7,495) (17,704) 19,221 Revisions of previous quantity estimates............ 15,819 (7,244) 60,800 Purchases (sales) of minerals in-place.............. 79,024 55,484 (48,698) Changes in timing of Bolivian production............ 10,271 -- -- Extension of Bolivian contract terms................ -- 26,564 -- Other changes in Bolivian Hydrocarbons Law.......... -- 32,894 -- Accretion of discount............................... 20,619 14,563 14,878 Net changes in income taxes......................... 25,785 (71,332) 6,917 -------- -------- --------- Net increase (decrease)............................. 28,174 60,560 (3,146) Beginning of period................................. 206,189 145,629 148,775 -------- -------- --------- End of period....................................... $234,363 $206,189 $ 145,629 ======== ======== =========
72 75 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Reserve Information (Unaudited) The following estimates of the Company's net proved oil and gas reserves are based on evaluations prepared by Netherland, Sewell & Associates, Inc., except for U.S. net reserves at December 31, 1997 which were prepared by in-house engineers and audited by Netherland, Sewell & Associates, Inc. Reserves were estimated in accordance with guidelines established by the Securities and Exchange Commission and Financial Accounting Standards Board, which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations except by contractual arrangements.
U.S. BOLIVIA TOTAL ------- ------- ------- NET PROVED GAS RESERVES (millions of cubic feet)(a) December 31, 1994......................................... 129,099 95,756 224,855 Revisions of previous estimates........................ 46,239 (553) 45,686 Extensions, discoveries and other additions............ 50,201 -- 50,201 Production............................................. (41,789) (6,807) (48,596) Sales of minerals in-place............................. (77,373) -- (77,373) ------- ------- ------- December 31, 1995......................................... 106,377 88,396 194,773 Extension of Bolivian contract terms(b)................ -- 32,998 32,998 Other changes in Bolivian Hydrocarbons Law(b).......... -- 56,704 56,704 Revisions of previous estimates........................ (4,792) (149) (4,941) Extensions, discoveries and other additions............ 22,977 59,964 82,941 Production............................................. (32,081) (7,412) (39,493) Purchases of minerals in-place......................... 24,309 -- 24,309 ------- ------- ------- December 31, 1996......................................... 116,790 230,501 347,291 Revisions of previous estimates........................ (3,063) 30,567 27,504 Extensions and discoveries............................. 33,648 -- 33,648 Production............................................. (31,409) (7,131) (38,540) Purchases of minerals in-place......................... 30,527 81,229 111,756 ------- ------- ------- December 31, 1997 (c)..................................... 146,493 335,166 481,659 ======= ======= ======= NET PROVED DEVELOPED GAS RESERVES (millions of cubic feet) December 31, 1994......................................... 110,071 81,558 191,629 December 31, 1995......................................... 95,930 72,500 168,430 December 31, 1996......................................... 107,509 123,154 230,663 December 31, 1997 (c)..................................... 112,385 181,402 293,787
73 76 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
U.S. BOLIVIA TOTAL ------- ------- ------- NET PROVED OIL RESERVES (thousands of barrels)(a) December 31, 1994......................................... -- 1,793 1,793 Revisions of previous estimates........................ 1 10 11 Extensions, discoveries and other additions............ 8 -- 8 Production............................................. (1) (207) (208) ------- ------- ------- December 31, 1995......................................... 8 1,596 1,604 Extension of Bolivian contract terms(b)................ -- 459 459 Other changes in Bolivian Hydrocarbons Law(b).......... -- 913 913 Revisions of previous estimates........................ (4) 150 146 Extensions, discoveries and other additions............ -- 840 840 Production............................................. (10) (214) (224) Purchases of minerals in-place......................... 188 -- 188 ------- ------- ------- December 31, 1996......................................... 182 3,744 3,926 Revisions of previous estimates........................ (5) 349 344 Extensions and discoveries............................. 87 -- 87 Production............................................. (43) (189) (232) Purchases of minerals in-place......................... 430 1,301 1,731 ------- ------- ------- December 31, 1997 (c)..................................... 651 5,205 5,856 ======= ======= ======= NET PROVED DEVELOPED OIL RESERVES (thousands of barrels) December 31, 1994......................................... -- 1,627 1,627 December 31, 1995......................................... 4 1,407 1,411 December 31, 1996......................................... 126 2,291 2,417 December 31, 1997 (c)..................................... 296 3,137 3,433
- --------------- (a) The Company is required to file annual estimates of its proved reserves with the Department of Energy. Such filings have been consistent with the information presented herein. (b) Under a new Hydrocarbons Law passed by the Bolivian government in 1996, the Company converted its Contracts of Operation for Block 18 and Block 20 into four Shared Risk Contracts, which, among other matters, extend the Company's term of operation, provide more favorable acreage relinquishment terms and provide for a more favorable royalty and tax structure. (c) No major discovery or adverse event has occurred since December 31, 1997 that would cause a significant change in net proved reserve volumes. NOTE O -- SUBSEQUENT EVENT (UNAUDITED) On March 18, 1998, the Company entered into a stock sale agreement with BHP Hawaii Inc. and BHP Petroleum Pacific Islands Inc., subsidiaries of The Broken Hill Proprietary Company Limited ("BHP"), whereby Tesoro will purchase all of the outstanding stock of BHP Petroleum Americas Refining Inc. ("BHP Refining") and BHP Petroleum South Pacific Inc. ("BHP South Pacific"). The primary assets of BHP Refining and BHP South Pacific include a 95,000-barrel per day refinery and 32 retail gasoline stations located in Hawaii. In addition, Tesoro and a BHP affiliate will enter into a two-year crude supply agreement pursuant to which the BHP affiliate will assist Tesoro in acquiring crude oil feedstock sourced outside of North America and arrange for the transportation of such crude oil to the Hawaiian refinery. The acquisition is expected to close by the end of May 1998, subject to regulatory review and other customary conditions. Under the terms of the stock sale agreement, the Company has deposited $5 million into an escrow account for this acquisition. The purchase price to be paid at closing includes $275 million in cash, less the amount of the escrow deposit. After closing, the cash purchase price will be increased by an amount that net working capital acquired 74 77 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) exceeds $100 million or reduced by an amount that the net working capital acquired is less than $100 million. In addition, Tesoro will issue an unsecured, non-interest bearing, promissory note for the purchase in the amount of $50 million, payable in five equal annual installments of $10 million each, beginning in 2009. The note will provide for early payment to the extent of one-half of the amount by which earnings from the acquired assets, before interest expense, income taxes and depreciation, depletion and amortization, as specified in the note, exceed $50 million in any calendar year. Upon acceleration due to an event of default, the amount outstanding to be paid under the note will be reduced to present value using a discount rate of 9%. The acquisition, which significantly increases the scope of the Company's refining and marketing operations, will be accounted for as a purchase whereby the purchase price will be allocated to the assets acquired and liabilities assumed based on their estimated fair values at the date of acquisition. The Company is currently in discussions with its investment bankers to arrange for financing of the acquisition and associated working capital and letter of credit requirements. 75 78 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Information required under this Item will be contained in the Company's 1998 Proxy Statement, incorporated herein by reference. See also Executive Officers of the Registrant under Business in Item 1 hereof. ITEM 11. EXECUTIVE COMPENSATION Information required under this Item will be contained in the Company's 1998 Proxy Statement, incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Information required under this Item will be contained in the Company's 1998 Proxy Statement, incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Information required under this Item will be contained in the Company's 1998 Proxy Statement, incorporated herein by reference. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (A) 1. FINANCIAL STATEMENTS The following Consolidated Financial Statements of Tesoro Petroleum Corporation and its subsidiaries are included in Part II, Item 8 of this Form 10-K:
PAGE ---- Independent Auditors' Report................................ 43 Statements of Consolidated Operations -- Years Ended December 31, 1997, 1996 and 1995.......................... 44 Consolidated Balance Sheets -- December 31, 1997 and 1996... 45 Statements of Consolidated Stockholders' Equity -- Years Ended December 31, 1997, 1996 and 1995.................... 46 Statements of Consolidated Cash Flows -- Years Ended December 31, 1997, 1996 and 1995.......................... 47 Notes to Consolidated Financial Statements.................. 48
2. FINANCIAL STATEMENT SCHEDULES No financial statement schedules are submitted because of the absence of the conditions under which they are required or because the required information is included in the Consolidated Financial Statements or notes thereto. 76 79 3. EXHIBITS
EXHIBIT NUMBER DESCRIPTION OF EXHIBIT ------- ---------------------- 2.1 -- Agreement and Plan of Merger dated as of November 20, 1995, between the Company, Coastwide Energy Services, Inc. and CNRG Acquisition Corp. (incorporated by reference herein to Registration Statement No. 333-00229). 2.2 -- First Amendment to Agreement and Plan of Merger dated effective February 19, 1996 between the Company, Coastwide Energy Services, Inc. and CNRG Acquisition Corp. (incorporated by reference herein to Exhibit 2(b) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1995, File No. 1-3473). 3.1 -- Restated Certificate of Incorporation of the Company (incorporated by reference herein to Exhibit 3 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1993, File No. 1-3473). 3.2 -- By-Laws of the Company, as amended through June 6, 1996 (incorporated by reference herein to Exhibit 3.2 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1996, File No. 1-3473). 3.3 -- Amendment to Restated Certificate of Incorporation of the Company adding a new Article IX limiting Directors' Liability (incorporated by reference herein to Exhibit 3(b) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1993, File No. 1-3473). 3.4 -- Certificate of Designation Establishing a Series of $2.20 Cumulative Convertible Preferred Stock, dated as of January 26, 1983 (incorporated by reference herein to Exhibit 3(c) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1993, File No. 1-3473). 3.5 -- Certificate of Designation Establishing a Series A Participating Preferred Stock, dated as of December 16, 1985 (incorporated by reference herein to Exhibit 3(d) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1993, File No. 1-3473). 3.6 -- Certificate of Amendment, dated as of February 9, 1994, to Restated Certificate of Incorporation of the Company amending Article IV, Article V, Article VII and Article VIII (incorporated by reference herein to Exhibit 3(e) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1993, File No. 1-3473). 4.1 -- Amended and Restated Credit Agreement ("Credit Facility") dated as of June 7, 1996 among the Company and Banque Paribas, individually, as an Issuing Bank and as Administrative Agent, and The Bank of Nova Scotia, individually and as Documentation Agent, and certain other financial institutions named therein (incorporated by reference herein to Exhibit 4.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, File No. 1-3473). 4.2 -- First Amendment to Credit Facility among the Company, Banque Paribas, Bank of Nova Scotia and other financial institution parties thereto, effective as of March 21, 1997 (incorporated by reference herein to Exhibit 4.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1997, File No. 1-3473). 4.3 -- Second Amendment to Credit Facility among the Company, Banque Paribas, Bank of Nova Scotia and other financial institution parties thereto, effective as of March 31, 1997 (incorporated by reference herein to Exhibit 4.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1997, File No. 1-3473).
77 80
EXHIBIT NUMBER DESCRIPTION OF EXHIBIT ------- ---------------------- 4.4 -- Third Amendment of Credit Facility among the Company, Banque Paribas, Bank of Nova Scotia and other financial institution parties thereto, effective as of September 15, 1997 (incorporated by reference herein to Exhibit 4.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1997, File No. 1-3473). 4.5 -- Second Amended and Restated Guaranty Agreement dated as of January 28, 1997 among various subsidiaries of the Company and Banque Paribas, individually, as Administrative Agent and as an Issuing Bank, and certain other financial institutions named therein, entered into in connection with the Credit Facility (incorporated by reference herein to Exhibit 4.2 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1996, File No. 1-3473). 4.6 -- Amended and Restated Security Agreement (Accounts and Inventory) dated as of June 7, 1996 between the Company and Banque Paribas, entered into in connection with the Credit Facility (incorporated by reference herein to Exhibit 4.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, File No. 1-3473). 4.7 -- Amended and Restated Security Agreement (Accounts and Inventory) dated as of June 7, 1996 between Tesoro Alaska Petroleum Company and Banque Paribas, entered into in connection with the Credit Facility (incorporated by reference herein to Exhibit 4.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, File No. 1-3473). 4.8 -- Amended and Restated Security Agreement (Accounts and Inventory) dated as of June 7, 1996 between Tesoro Refining, Marketing & Supply Company and Banque Paribas, entered into in connection with the Credit Facility (incorporated by reference herein to Exhibit 4.5 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, File No. 1-3473). 4.9 -- Security Agreement (Accounts and Inventory) dated as of June 7, 1996 between Kenai Pipe Line Company and Banque Paribas, entered into in connection with the Credit Facility (incorporated by reference herein to Exhibit 4.6 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, File No. 1-3473). 4.10 -- Security Agreement (Accounts and Inventory) dated as of June 7, 1996 between Tesoro Coastwide Services Company and Banque Paribas, entered into in connection with the Credit Facility (incorporated by reference herein to Exhibit 4.7 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, File No. 1-3473). 4.11 -- Security Agreement (Accounts and Inventory) dated as of June 7, 1996 between Coastwide Marine Services, Inc. and Banque Paribas, entered into in connection with the Credit Facility (incorporated by reference herein to Exhibit 4.8 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, File No. 1-3473). 4.12 -- Security Agreement (Accounts) dated as of June 7, 1996 between Tesoro Vostok Company and Banque Paribas, entered into in connection with the Credit Facility (incorporated by reference herein to Exhibit 4.9 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, File No. 1-3473).
78 81
EXHIBIT NUMBER DESCRIPTION OF EXHIBIT ------- ---------------------- 4.13 -- Amended and Restated Security Agreement (Pledge) dated as of June 7, 1996 by the Company in favor of Banque Paribas, entered into in connection with the Credit Facility (incorporated by reference herein to Exhibit 4.10 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, File No. 1-3473). 4.14 -- First Amendment to Amended and Restated Security Agreement (Pledge) dated as of September 12, 1996 between the Company and Banque Paribas, entered into in connection with the Credit Facility (incorporated by reference herein to Exhibit 4.11 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1996, File No. 1-3473). 4.15 -- First Amendment to Deed of Trust, Security Agreement and Financing Statement dated as of June 7, 1996 among Tesoro Alaska Petroleum Company, TransAlaska Title Insurance Agency, Inc., as Trustee, and Banque Paribas, as Administrative Agent, entered into in connection with the Credit Facility (incorporated by reference herein to Exhibit 4.11 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, File No. 1-3473). 4.16 -- First Amendment to Mortgage, Deed of Trust, Assignment of Production, Security Agreement and Financing Statement dated as of June 7, 1996 from Tesoro E&P Company, L.P., entered into in connection with the Credit Facility (incorporated by reference herein to Exhibit 4.12 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, File No. 1-3473). 4.17 -- Mortgage, Deed of Trust, Assignment of Production, Security Agreement and Financing Statement dated as of June 7, 1996 from Tesoro E&P Company, L.P., entered into in connection with the Credit Facility (incorporated by reference herein to Exhibit 4.13 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, File No. 1-3473). 4.18 -- Form of Coastwide Energy Services Inc. 8% Convertible Subordinated Debenture (incorporated by reference herein to Exhibit 4.3 to Post-Effective Amendment No. 1 to Registration No. 333-00229). 4.19 -- Debenture Assumption and Conversion Agreement dated as of February 20, 1996, between the Company, Coastwide Energy Services, Inc. and CNRG Acquisition Corp. (incorporated by reference herein to Exhibit 4.4 to Post-Effective Amendment No. 1 to Registration No. 333-00229). 4.20 -- Form of Stock Option Agreement for option grant under the Coastwide Energy Services, Inc. 1993 Long-Term Incentive Plan (incorporated by reference herein to Exhibit 4.5 to Post-Effective Amendment No. 1 to Registration No. 333-00229). 4.21 -- Form of Cancellation/Substitution Agreement by and between the Company, Coastwide Energy Services, Inc. and Optionee (incorporated by reference herein to Exhibit 4.6 to Post-Effective Amendment No. 1 to Registration No. 333-00229). +10.1 -- The Company's Amended Executive Security Plan, as amended through November 13, 1989, and Funded Executive Security Plan, as amended through February 28, 1990, for executive officers and key personnel (incorporated by reference herein to Exhibit 10(f) to the Company's Annual Report on Form 10-K for the fiscal year ended September 30, 1990, File No. 1-3473).
79 82
EXHIBIT NUMBER DESCRIPTION OF EXHIBIT ------- ---------------------- +10.2 -- Sixth Amendment to the Company's Amended Executive Security Plan and Seventh Amendment to the Company's Funded Executive Security Plan, both dated effective March 6, 1991 (incorporated by reference herein to Exhibit 10(g) to the Company's Annual Report on Form 10-K for the fiscal year ended September 30, 1991, File No. 1-3473). +10.3 -- Seventh Amendment to the Company's Amended Executive Security Plan and Eighth Amendment to the Company's Funded Executive Security Plan, both dated effective December 8, 1994 (incorporated by reference herein to Exhibit 10(f) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473). *+10.4 -- Amended and Restated Employment Agreement between the Company and Bruce A. Smith dated November 1, 1997. +10.5 -- Amendment and Restated Employment Agreement between the Company and William T. Van Kleef dated as of December 12, 1996 (incorporated by reference herein to Exhibit 10.6 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1996, File No. 1-3473). +10.6 -- Amendment and Restated Employment Agreement between the Company and James C. Reed, Jr. dated as of December 12, 1996 (incorporated by reference herein to Exhibit 10.5 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1996, File No. 1-3473). *+10.7 -- Management Stability Agreement between the Company and Donald A. Nyberg dated December 12, 1996. *+10.8 -- Management Stability Agreement between the Company and Robert W. Oliver dated September 27, 1995. *+10.9 -- Management Stability Agreement between the Company and Steve Wormington dated September 27, 1995. +10.10 -- Management Stability Agreement between the Company and Don E. Beere dated December 14, 1994 (incorporated by reference herein to Exhibit 10(o) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473). +10.11 -- Management Stability Agreement between the Company and Thomas E. Reardon dated December 14, 1994 (incorporated by reference herein to Exhibit 10(w) to Registration Statement No. 333-00229). +10.12 -- Management Stability Agreement between the Company and Gregory A. Wright dated February 23, 1995 (incorporated by reference herein to Exhibit 10(p) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473). +10.13 -- The Company's Amended Incentive Stock Plan of 1982, as amended through February 24, 1988 (incorporated by reference herein to Exhibit 10(t) to the Company's Annual Report on Form 10-K for the fiscal year ended September 30, 1988, File No. 1-3473). +10.14 -- Resolution approved by the Company's stockholders on April 30, 1992 extending the term of the Company's Amended Incentive Stock Plan of 1982 to February 24, 1994 (incorporated by reference herein to Exhibit 10(o) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1992, File No. 1-3473).
80 83
EXHIBIT NUMBER DESCRIPTION OF EXHIBIT ------- ---------------------- +10.15 -- Copy of the Company's Amended and Restated Executive Long-Term Incentive Plan, as amended through June 6, 1996 (incorporated by reference herein to Exhibit 10.12 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1996, File No. 1-3473). +10.16 -- Copy of the Company's Non-Employee Director Retirement Plan dated December 8, 1994 (incorporated by reference herein to Exhibit 10(t) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473). +10.17 -- Copy of the Company's Board of Directors Deferred Compensation Plan dated February 23, 1995 (incorporated by reference herein to Exhibit 10(u) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473). +10.18 -- Copy of the Company's Board of Directors Deferred Compensation Trust dated February 23, 1995 (incorporated by reference herein to Exhibit 10(v) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473). +10.19 -- Copy of the Company's Board of Directors Deferred Phantom Stock Plan (incorporated by reference herein to Exhibit 10 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1997, File No. 1-3473). *+10.20 -- Phantom Stock Option Agreement between the Company and Bruce A. Smith dated effective October 29, 1997. 10.21 -- 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 (incorporated by reference herein to Exhibit 10 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1995, File No. 1-3473). 10.22 -- Copy of Settlement Agreement dated effective January 19, 1993, between Tesoro Petroleum Corporation, Tesoro Alaska Petroleum Company and the State of Alaska (incorporated by reference herein to Exhibit 10(q) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1992, File No. 1-3473). 10.23 -- Form of Indemnification Agreement between the Company and its officers and directors (incorporated by reference herein to Exhibit B to the Company's Proxy Statement for the Annual Meeting of Stockholders held on February 25, 1987, File No. 1-3473). 10.24 -- Settlement and Standstill Agreement, dated as of April 4, 1996, among Kevin S. Flannery, Alan Kaufman, Robert S. Washburn, James H. Stone, George F. Baker, Douglas Thompson, Gales E. Galloway, Whelan Management Corp., Ardsley Advisory Partners and Tesoro Petroleum Corporation (incorporated by reference herein to Exhibit 99 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1996, File No. 1-3473). 10.25 -- Settlement Agreement and Release, entered into and effective as of October 1, 1996, by and between Tesoro E&P Company, L.P., acting through its General Partner, Tesoro Exploration and Production Company, Coastal Oil & Gas Corporation and Coastal Oil & Gas USA, L.P., and Tennessee Gas Pipeline Company (incorporated by reference herein to Exhibit 10.20 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1996, File No. 1-3473).
81 84
EXHIBIT NUMBER DESCRIPTION OF EXHIBIT ------- ---------------------- 10.26 -- Termination Agreement, entered into and effective as of October 1, 1996, by and between Tesoro E&P Company, L.P., acting through its General Partner, Tesoro Exploration and Production Company, Coastal Oil & Gas Corporation and Coastal Oil & Gas USA, L.P., and Tennessee Gas Pipeline Company (incorporated by reference herein to Exhibit 10.21 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1996, File No. 1-3473). *21 -- Subsidiaries of the Company *23.1 -- Consent of Deloitte & Touche LLP *23.2 -- Consent of Netherland, Sewell & Associates, Inc. **27.1 -- Financial Data Schedule **27.2 -- Restated Financial Data Schedule 1996 **27.3 -- Restated Financial Data Schedule 1995
- --------------- * Filed herewith. + Identifies management contracts or compensatory plans or arrangements required to be filed as an exhibit hereto pursuant to Item 14(c) of Form 10-K. ** The Financial Data Schedule and Restated Financial Data Schedules shall not be deemed "filed" for purposes of Section 11 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934, and are included as exhibits only to the electronic filing of this Form 10-K in accordance with Item 601(c) of Regulation S-K and Section 401 of Regulation S-T. Copies of exhibits filed as part of this Form 10-K may be obtained by stockholders of record at a charge of $0.15 per page, minimum $5.00 each request. Direct inquiries to the Corporate Secretary, Tesoro Petroleum Corporation, 8700 Tesoro Drive, San Antonio, Texas, 78217-6218. (B) REPORTS ON FORM 8-K No reports on Form 8-K were filed by the Company during the quarter ended December 31, 1997. 82 85 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) 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 March 30, 1998 By: /s/ BRUCE A. SMITH ------------------------------------------------ Bruce A. Smith Chairman of the Board of Directors, President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE --------- ----- ---- /s/ BRUCE A. SMITH Chairman of the Board of March 30, 1998 - ----------------------------------------------------- Directors and Director, (Bruce A. Smith) President and Chief Executive Officer (Principal Executive Officer) /s/ JAMES C. REED, JR. Executive Vice President, March 30, 1998 - ----------------------------------------------------- General Counsel and (James C. Reed, Jr.) Secretary (Principal Financial Officer) /s/ DON E. BEERE Vice President, Controller March 30, 1998 - ----------------------------------------------------- (Principal Accounting (Don E. Beere) Officer) /s/ STEVEN H. GRAPSTEIN Vice Chairman of the Board of March 30, 1998 - ----------------------------------------------------- Directors and Director (Steven H. Grapstein) /s/ WILLIAM J. JOHNSON Director March 30, 1998 - ----------------------------------------------------- (William J. Johnson) /s/ ALAN J. KAUFMAN Director March 30, 1998 - ----------------------------------------------------- (Alan J. Kaufman) /s/ RAYMOND K. MASON, SR. Director March 30, 1998 - ----------------------------------------------------- (Raymond K. Mason, Sr.) /s/ PATRICK J. WARD Director March 30, 1998 - ----------------------------------------------------- (Patrick J. Ward) /s/ MURRAY L. WEIDENBAUM Director March 30, 1998 - ----------------------------------------------------- (Murray L. Weidenbaum)
83 86 INDEX TO EXHIBITS
EXHIBIT NUMBER DESCRIPTION OF EXHIBIT ------- ---------------------- 2.1 -- Agreement and Plan of Merger dated as of November 20, 1995, between the Company, Coastwide Energy Services, Inc. and CNRG Acquisition Corp. (incorporated by reference herein to Registration Statement No. 333-00229). 2.2 -- First Amendment to Agreement and Plan of Merger dated effective February 19, 1996 between the Company, Coastwide Energy Services, Inc. and CNRG Acquisition Corp. (incorporated by reference herein to Exhibit 2(b) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1995, File No. 1-3473). 3.1 -- Restated Certificate of Incorporation of the Company (incorporated by reference herein to Exhibit 3 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1993, File No. 1-3473). 3.2 -- By-Laws of the Company, as amended through June 6, 1996 (incorporated by reference herein to Exhibit 3.2 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1996, File No. 1-3473). 3.3 -- Amendment to Restated Certificate of Incorporation of the Company adding a new Article IX limiting Directors' Liability (incorporated by reference herein to Exhibit 3(b) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1993, File No. 1-3473). 3.4 -- Certificate of Designation Establishing a Series of $2.20 Cumulative Convertible Preferred Stock, dated as of January 26, 1983 (incorporated by reference herein to Exhibit 3(c) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1993, File No. 1-3473). 3.5 -- Certificate of Designation Establishing a Series A Participating Preferred Stock, dated as of December 16, 1985 (incorporated by reference herein to Exhibit 3(d) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1993, File No. 1-3473). 3.6 -- Certificate of Amendment, dated as of February 9, 1994, to Restated Certificate of Incorporation of the Company amending Article IV, Article V, Article VII and Article VIII (incorporated by reference herein to Exhibit 3(e) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1993, File No. 1-3473). 4.1 -- Amended and Restated Credit Agreement ("Credit Facility") dated as of June 7, 1996 among the Company and Banque Paribas, individually, as an Issuing Bank and as Administrative Agent, and The Bank of Nova Scotia, individually and as Documentation Agent, and certain other financial institutions named therein (incorporated by reference herein to Exhibit 4.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, File No. 1-3473). 4.2 -- First Amendment to Credit Facility among the Company, Banque Paribas, Bank of Nova Scotia and other financial institution parties thereto, effective as of March 21, 1997 (incorporated by reference herein to Exhibit 4.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1997, File No. 1-3473). 4.3 -- Second Amendment to Credit Facility among the Company, Banque Paribas, Bank of Nova Scotia and other financial institution parties thereto, effective as of March 31, 1997 (incorporated by reference herein to Exhibit 4.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1997, File No. 1-3473).
87
EXHIBIT NUMBER DESCRIPTION OF EXHIBIT ------- ---------------------- 4.4 -- Third Amendment of Credit Facility among the Company, Banque Paribas, Bank of Nova Scotia and other financial institution parties thereto, effective as of September 15, 1997 (incorporated by reference herein to Exhibit 4.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1997, File No. 1-3473). 4.5 -- Second Amended and Restated Guaranty Agreement dated as of January 28, 1997 among various subsidiaries of the Company and Banque Paribas, individually, as Administrative Agent and as an Issuing Bank, and certain other financial institutions named therein, entered into in connection with the Credit Facility (incorporated by reference herein to Exhibit 4.2 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1996, File No. 1-3473). 4.6 -- Amended and Restated Security Agreement (Accounts and Inventory) dated as of June 7, 1996 between the Company and Banque Paribas, entered into in connection with the Credit Facility (incorporated by reference herein to Exhibit 4.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, File No. 1-3473). 4.7 -- Amended and Restated Security Agreement (Accounts and Inventory) dated as of June 7, 1996 between Tesoro Alaska Petroleum Company and Banque Paribas, entered into in connection with the Credit Facility (incorporated by reference herein to Exhibit 4.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, File No. 1-3473). 4.8 -- Amended and Restated Security Agreement (Accounts and Inventory) dated as of June 7, 1996 between Tesoro Refining, Marketing & Supply Company and Banque Paribas, entered into in connection with the Credit Facility (incorporated by reference herein to Exhibit 4.5 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, File No. 1-3473). 4.9 -- Security Agreement (Accounts and Inventory) dated as of June 7, 1996 between Kenai Pipe Line Company and Banque Paribas, entered into in connection with the Credit Facility (incorporated by reference herein to Exhibit 4.6 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, File No. 1-3473). 4.10 -- Security Agreement (Accounts and Inventory) dated as of June 7, 1996 between Tesoro Coastwide Services Company and Banque Paribas, entered into in connection with the Credit Facility (incorporated by reference herein to Exhibit 4.7 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, File No. 1-3473). 4.11 -- Security Agreement (Accounts and Inventory) dated as of June 7, 1996 between Coastwide Marine Services, Inc. and Banque Paribas, entered into in connection with the Credit Facility (incorporated by reference herein to Exhibit 4.8 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, File No. 1-3473). 4.12 -- Security Agreement (Accounts) dated as of June 7, 1996 between Tesoro Vostok Company and Banque Paribas, entered into in connection with the Credit Facility (incorporated by reference herein to Exhibit 4.9 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, File No. 1-3473).
88
EXHIBIT NUMBER DESCRIPTION OF EXHIBIT ------- ---------------------- 4.13 -- Amended and Restated Security Agreement (Pledge) dated as of June 7, 1996 by the Company in favor of Banque Paribas, entered into in connection with the Credit Facility (incorporated by reference herein to Exhibit 4.10 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, File No. 1-3473). 4.14 -- First Amendment to Amended and Restated Security Agreement (Pledge) dated as of September 12, 1996 between the Company and Banque Paribas, entered into in connection with the Credit Facility (incorporated by reference herein to Exhibit 4.11 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1996, File No. 1-3473). 4.15 -- First Amendment to Deed of Trust, Security Agreement and Financing Statement dated as of June 7, 1996 among Tesoro Alaska Petroleum Company, TransAlaska Title Insurance Agency, Inc., as Trustee, and Banque Paribas, as Administrative Agent, entered into in connection with the Credit Facility (incorporated by reference herein to Exhibit 4.11 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, File No. 1-3473). 4.16 -- First Amendment to Mortgage, Deed of Trust, Assignment of Production, Security Agreement and Financing Statement dated as of June 7, 1996 from Tesoro E&P Company, L.P., entered into in connection with the Credit Facility (incorporated by reference herein to Exhibit 4.12 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, File No. 1-3473). 4.17 -- Mortgage, Deed of Trust, Assignment of Production, Security Agreement and Financing Statement dated as of June 7, 1996 from Tesoro E&P Company, L.P., entered into in connection with the Credit Facility (incorporated by reference herein to Exhibit 4.13 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, File No. 1-3473). 4.18 -- Form of Coastwide Energy Services Inc. 8% Convertible Subordinated Debenture (incorporated by reference herein to Exhibit 4.3 to Post-Effective Amendment No. 1 to Registration No. 333-00229). 4.19 -- Debenture Assumption and Conversion Agreement dated as of February 20, 1996, between the Company, Coastwide Energy Services, Inc. and CNRG Acquisition Corp. (incorporated by reference herein to Exhibit 4.4 to Post-Effective Amendment No. 1 to Registration No. 333-00229). 4.20 -- Form of Stock Option Agreement for option grant under the Coastwide Energy Services, Inc. 1993 Long-Term Incentive Plan (incorporated by reference herein to Exhibit 4.5 to Post-Effective Amendment No. 1 to Registration No. 333-00229). 4.21 -- Form of Cancellation/Substitution Agreement by and between the Company, Coastwide Energy Services, Inc. and Optionee (incorporated by reference herein to Exhibit 4.6 to Post-Effective Amendment No. 1 to Registration No. 333-00229). +10.1 -- The Company's Amended Executive Security Plan, as amended through November 13, 1989, and Funded Executive Security Plan, as amended through February 28, 1990, for executive officers and key personnel (incorporated by reference herein to Exhibit 10(f) to the Company's Annual Report on Form 10-K for the fiscal year ended September 30, 1990, File No. 1-3473).
89
EXHIBIT NUMBER DESCRIPTION OF EXHIBIT ------- ---------------------- +10.2 -- Sixth Amendment to the Company's Amended Executive Security Plan and Seventh Amendment to the Company's Funded Executive Security Plan, both dated effective March 6, 1991 (incorporated by reference herein to Exhibit 10(g) to the Company's Annual Report on Form 10-K for the fiscal year ended September 30, 1991, File No. 1-3473). +10.3 -- Seventh Amendment to the Company's Amended Executive Security Plan and Eighth Amendment to the Company's Funded Executive Security Plan, both dated effective December 8, 1994 (incorporated by reference herein to Exhibit 10(f) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473). *+10.4 -- Amended and Restated Employment Agreement between the Company and Bruce A. Smith dated November 1, 1997. +10.5 -- Amendment and Restated Employment Agreement between the Company and William T. Van Kleef dated as of December 12, 1996 (incorporated by reference herein to Exhibit 10.6 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1996, File No. 1-3473). +10.6 -- Amendment and Restated Employment Agreement between the Company and James C. Reed, Jr. dated as of December 12, 1996 (incorporated by reference herein to Exhibit 10.5 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1996, File No. 1-3473). *+10.7 -- Management Stability Agreement between the Company and Donald A. Nyberg dated December 12, 1996. *+10.8 -- Management Stability Agreement between the Company and Robert W. Oliver dated September 27, 1995. *+10.9 -- Management Stability Agreement between the Company and Steve Wormington dated September 27, 1995. +10.10 -- Management Stability Agreement between the Company and Don E. Beere dated December 14, 1994 (incorporated by reference herein to Exhibit 10(o) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473). +10.11 -- Management Stability Agreement between the Company and Thomas E. Reardon dated December 14, 1994 (incorporated by reference herein to Exhibit 10(w) to Registration Statement No. 333-00229). +10.12 -- Management Stability Agreement between the Company and Gregory A. Wright dated February 23, 1995 (incorporated by reference herein to Exhibit 10(p) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473). +10.13 -- The Company's Amended Incentive Stock Plan of 1982, as amended through February 24, 1988 (incorporated by reference herein to Exhibit 10(t) to the Company's Annual Report on Form 10-K for the fiscal year ended September 30, 1988, File No. 1-3473). +10.14 -- Resolution approved by the Company's stockholders on April 30, 1992 extending the term of the Company's Amended Incentive Stock Plan of 1982 to February 24, 1994 (incorporated by reference herein to Exhibit 10(o) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1992, File No. 1-3473).
90
EXHIBIT NUMBER DESCRIPTION OF EXHIBIT ------- ---------------------- +10.15 -- Copy of the Company's Amended and Restated Executive Long-Term Incentive Plan, as amended through June 6, 1996 (incorporated by reference herein to Exhibit 10.12 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1996, File No. 1-3473). +10.16 -- Copy of the Company's Non-Employee Director Retirement Plan dated December 8, 1994 (incorporated by reference herein to Exhibit 10(t) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473). +10.17 -- Copy of the Company's Board of Directors Deferred Compensation Plan dated February 23, 1995 (incorporated by reference herein to Exhibit 10(u) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473). +10.18 -- Copy of the Company's Board of Directors Deferred Compensation Trust dated February 23, 1995 (incorporated by reference herein to Exhibit 10(v) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473). +10.19 -- Copy of the Company's Board of Directors Deferred Phantom Stock Plan (incorporated by reference herein to Exhibit 10 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1997, File No. 1-3473). *+10.20 -- Phantom Stock Option Agreement between the Company and Bruce A. Smith dated effective October 29, 1997. 10.21 -- 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 (incorporated by reference herein to Exhibit 10 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1995, File No. 1-3473). 10.22 -- Copy of Settlement Agreement dated effective January 19, 1993, between Tesoro Petroleum Corporation, Tesoro Alaska Petroleum Company and the State of Alaska (incorporated by reference herein to Exhibit 10(q) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1992, File No. 1-3473). 10.23 -- Form of Indemnification Agreement between the Company and its officers and directors (incorporated by reference herein to Exhibit B to the Company's Proxy Statement for the Annual Meeting of Stockholders held on February 25, 1987, File No. 1-3473). 10.24 -- Settlement and Standstill Agreement, dated as of April 4, 1996, among Kevin S. Flannery, Alan Kaufman, Robert S. Washburn, James H. Stone, George F. Baker, Douglas Thompson, Gales E. Galloway, Whelan Management Corp., Ardsley Advisory Partners and Tesoro Petroleum Corporation (incorporated by reference herein to Exhibit 99 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1996, File No. 1-3473). 10.25 -- Settlement Agreement and Release, entered into and effective as of October 1, 1996, by and between Tesoro E&P Company, L.P., acting through its General Partner, Tesoro Exploration and Production Company, Coastal Oil & Gas Corporation and Coastal Oil & Gas USA, L.P., and Tennessee Gas Pipeline Company (incorporated by reference herein to Exhibit 10.20 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1996, File No. 1-3473).
91
EXHIBIT NUMBER DESCRIPTION OF EXHIBIT ------- ---------------------- 10.26 -- Termination Agreement, entered into and effective as of October 1, 1996, by and between Tesoro E&P Company, L.P., acting through its General Partner, Tesoro Exploration and Production Company, Coastal Oil & Gas Corporation and Coastal Oil & Gas USA, L.P., and Tennessee Gas Pipeline Company (incorporated by reference herein to Exhibit 10.21 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1996, File No. 1-3473). *21 -- Subsidiaries of the Company *23.1 -- Consent of Deloitte & Touche LLP *23.2 -- Consent of Netherland, Sewell & Associates, Inc. **27.1 -- Financial Data Schedule **27.2 -- Restated Financial Data Schedule 1996 **27.3 -- Restated Financial Data Schedule 1995
- --------------- * Filed herewith. + Identifies management contracts or compensatory plans or arrangements required to be filed as an exhibit hereto pursuant to Item 14(c) of Form 10-K. ** The Financial Data Schedule and Restated Financial Data Schedules shall not be deemed "filed" for purposes of Section 11 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934, and are included as exhibits only to the electronic filing of this Form 10-K in accordance with Item 601(c) of Regulation S-K and Section 401 of Regulation S-T. EX-10.4 2 AMENDED/RESTATED EMPLOYMENT AGRMT-BRUCE A. SMITH 1 ITEM 14(a)3, EXHIBIT 10.4 AMENDED AND RESTATED EMPLOYMENT AGREEMENT This Amended and Restated Employment Agreement (the "Agreement") is entered into as of November 1, 1997, by and between Bruce A. Smith ("Employee") and Tesoro Petroleum Corporation, a Delaware corporation (the "Company"). RECITALS: A. The Company and Employee are parties to an Employment Agreement dated September 14, 1992, including all amendments thereto and restatements prior to the date hereof (the "Prior Agreement"). B. The Company wishes to continue the engagement of Employee as its President and Chief Executive Officer; as such, Employee shall have certain responsibilities and shall receive certain compensation and benefits. C. Employee and the Company wish to formalize the continuation of this employment relationship by amending and restating the Prior Agreement, including extending its term, and by setting forth certain additional agreements between Employee and the Company. THE PARTIES AGREE AS FOLLOWS: 1. Employment and Duties. During the term of this Agreement, the Company agrees to employ Employee as the Company's President and Chief Executive Officer, and Employee agrees to serve the Company in such capacity on the terms and subject to the conditions set forth in this Agreement. Employee shall devote substantially all of his business time, energy and skill to the affairs of the Company as the Company, acting through its Board of Directors, shall reasonably deem necessary to discharge Employee's duties in such capacity. Employee may participate in social, civic, charitable, religious, business, educational or professional associations, so long as such participation would not materially detract from Employee's ability to perform his duties under this Agreement. Employee shall not engage in any other business activity during the term of this Agreement without the prior written consent of the Company, other than the passive management of Employee's personal investments or activities which would not materially detract from Employee's ability to perform his duties under this Agreement. 2. Compensation. (a) Salary; Withholding. During the term of this Agreement, the Company shall pay Employee a base salary of $600,000 per year, payable in arrears in equal bi-weekly installments ("Base Salary"). The parties shall comply with all applicable withholding requirements in connection with all compensation payable to Employee. The Company's Board of Directors may, in its sole discretion, review and adjust upward Employee's Base Salary from time to time, but no downward adjustment in Employee's Base Salary may be made during the term of this Agreement. 1 2 (b) Annual Incentive Plan. The Company shall maintain an Annual Incentive Compensation Plan for executive officers in which the Employee shall be entitled to participate in a manner consistent with his position with the Company and the evaluations of his performance by the Board of Directors or any appropriate Committee thereof. (c) Stock Options and Other Incentive Grants. The Employee shall be entitled to receive stock options and restricted stock, and other long-term incentive plan grants under the Company's plans in effect from time to time, if any, commensurate with his position with the Company and the evaluations of his performance by the Board of Directors or any appropriate committee thereof. (d) Flexible Perquisites Arrangement. The Employee shall receive annually a stipulated amount of $30,000 which will be expended by the Company on behalf of the Employee or paid to the Employee, at the Employee's election, to cover various business-related expenses such as monthly dues for country, luncheon or social clubs, automobile expenses and financial and tax planning expenses. The Employee may elect at any time by written notice to the Company to receive any of such stipulated amount which has not been paid to or on behalf of the Employee. In addition, the Company will pay initiation fees and reimburse the Employee for related tax expenses to the extent the Board of Directors or a duly authorized committee thereof determines such fees are reasonable and in the best interest of the Company. (e) Other Benefits. Employee shall be eligible to participate in and have the benefits under the terms of all life, accident, disability and health insurance plans, pension, profit sharing, incentive compensation and savings plans and all other similar plans and benefits which the Company from time to time makes available to its management executives, including, without limitation, those listed on Exhibit A, in the same manner and at least at the same participation level as other senior management executives, as soon as Employee meets the period of employment and other eligibility requirements of general applicability of the various plans and benefits made available by the Company. 3. Business Expenses. The Company shall promptly reimburse Employee for all appropriately documented, reasonable business expenses incurred by Employee in accordance with Company policies. 4. Term. This Agreement shall commence effective as of November 1, 1997, and, if not terminated earlier as herein provided, shall terminate on the third anniversary date hereof, provided that, if the Company has not given a notice of termination of employment in accordance with the following sentence, the term of the Employee's employment hereunder shall automatically be extended for an additional year on each anniversary date of this Agreement. Notwithstanding the foregoing, the Company, at any time, may give the Employee a notice of termination of the Employee's employment under this Agreement by delivering to the Employee a written notice to such effect. The termination of employment of the Employee shall be effective 30 days after such notice by the Company. If a notice of termination of employment is given in accordance herewith, the Employee shall be deemed to have been involuntarily terminated by the Company other than 2 3 for cause for purposes hereof and the Employee shall be entitled to the benefits provided in Section 5 (or Section 9 as applicable) of this Agreement. 5. Termination by the Company Without Cause and Termination by Employee for "Good Reason". The Company may, by delivering 30 days prior written notice to Employee, terminate Employee's employment at any time without cause, and the Employee may, by delivering 30 days prior written notice to the Company, terminate Employee's employment for "Good Reason," as defined below. If such termination without cause or for Good Reason occurs, Employee shall be entitled to receive a lump-sum payment equal to the sum of (a) three times the sum of (i) his Base Salary at the then current rate and (ii) the sum of the target bonuses under all of the Company's incentive bonus plans applicable to Employee for the year in which the termination occurs and (b) if termination occurs in the fourth quarter of a calendar year, the sum of the target bonuses under all of the Company's incentive bonus plans applicable to Employee for the year in which the termination occurs prorated daily based on the number of days from the beginning of the calendar year in which the termination occurs to and including the date of termination. Employee shall also receive all earned but unpaid bonuses for the year prior to the year in which the termination occurs and shall receive (i) for a period of three years following termination of employment, continuing coverage and benefits comparable to all life, health and disability insurance plans which the Company from time to time makes available to its management executives and their families, (ii) a lump-sum payment equal to three times the stipulated flexible perquisites amount pursuant to Section 2(d), and (iii) three years additional service credit under the current non-qualified supplemental pension plans, or successors thereto, of the Company applicable to the Employee on the date of termination. All unvested stock options held by Employee on the date of the termination shall become immediately vested and all restrictions on restricted stock then held by the Employee shall terminate. For purposes of this Section 5, "Good Reason" shall mean the occurrence of any of the following events: (a) Removal, without the consent of Employee in writing, from one or more of the offices Employee holds on the date of this Agreement or a material reduction in Employee's authority or responsibility but not termination of Employee for "cause," as defined below; or (b) The Company otherwise commits a material breach of this Agreement. The Company shall pay any attorney fees incurred by Employee in reasonably seeking to enforce the terms of this Section 5. 6. Termination upon Death or Disability. If the Employee's employment is terminated because of death or on account of becoming permanently disabled (as defined below), the Employee, or his estate, if applicable, shall be entitled to receive the Employee's Base Salary earned pro rata to the date of his termination of employment, plus all earned but unpaid bonuses for the year prior to the year in which the termination occurs. All unvested stock options held by the Employee on the 3 4 date of termination shall become immediately vested and all restrictions on restricted stock held by the Employee shall terminate. For purposes of this Agreement, Employee shall be deemed to be "permanently disabled" if Employee shall be considered to be permanently and totally disabled in accordance with the Company's Long-Term Disability Income Plan. If there should be a dispute between the Company and Employee as to Employee's physical or mental disability for purposes of this Agreement, the question shall be settled by the opinion of an impartial reputable physician or psychiatrist agreed upon by the parties or their representatives, or if the parties cannot agree within ten calendar days after a request for designation of such party, then a physician or psychiatrist shall be designated by the San Antonio, Texas Medical Association. The parties agree to be bound by the final decision of such physician or psychiatrist. 7. Termination by the Company for Cause. The Company may terminate this Agreement at any time if such termination is for "cause," as defined below, by delivering to Employee written notice describing the cause of termination 30 days before the effective date of such termination and by granting Employee at least 30 days to cure the cause. In the event the employment of Employee is terminated for "cause", Employee shall be entitled only to his Base Salary earned pro rata to his date of termination, with no entitlement to any base salary continuation payments or benefit continuation (except as specifically provided by the terms of an employee benefit plan of the Company). Except as otherwise provided in this Agreement, the determination of whether Employee is terminated for "cause" shall be made by the Board of Directors of the Company, in the reasonable exercise of its business judgment, and shall be limited to the occurrence of the following events: (a) Conviction of or a plea of nolo contendere to the charge of a felony (which, through lapse of time or otherwise, is not subject to appeal); (b) Willful refusal without proper legal cause to perform, or gross negligence in performing, Employee's duties and responsibilities; (c) Material breach of fiduciary duty to the Company through the misappropriation of Company funds or property; or (d) The unauthorized absence of Employee from work (other than for sick leave or disability) for a period of 30 working days or more during a period of 45 working days. 8. Voluntary Termination by Employee. Employee may terminate this Agreement at any time upon delivering 30 days written notice to the Company. In the event of such voluntary termination other than for "good reason", as defined above, Employee shall be entitled to his Base Salary earned pro rata to the date of his resignation, plus unpaid bonuses for the year prior to the year in which the termination occurs, but no base salary continuation payments or benefits continuation (except as specifically provided by the terms of an employee benefit plan of the 4 5 Company). On or after the date the Company receives notice of Employee's resignation, the Company may, at its option, pay Employee his Base Salary through the effective date of his resignation and terminate his employment immediately. 9. Termination Following Change of Control. Notwithstanding anything to the contrary contained herein, should Employee at any time within two years of a change of control cease to be an employee of the Company (or its successor), by reason of (i) involuntary termination by the Company (or its successor) other than for "cause" (following a change of control, "cause" shall be limited to the conviction of or a plea of nolo contendere to the charge of a felony (which, through lapse of time or otherwise, is not subject to appeal), or a material breach of fiduciary duty to the Company through the misappropriation of Company funds or property) or (ii) voluntary termination by Employee for "good reason upon change of control," (as defined below), the Company (or its successor) shall pay to Employee within ten days of such termination the following severance payments and benefits: (a) A lump-sum payment equal to three times the Base Salary at the then current rate; (b) A lump-sum payment equal to the sum of (i) three times the sum of the target bonuses under all of the Company's incentive bonus plans applicable to the Employee for the year in which the termination occurs or the year in which the change of control occurred, whichever is greater, and (ii) if termination occurs in the fourth quarter of a calendar year, the sum of the target bonuses under all of the Company's incentive bonus plans applicable to Employee for the year in which the termination occurs prorated daily based on the number of days from the beginning of the calendar year in which the termination occurs to and including the date of termination; and (c) A lump-sum payment equal to the amount of any earned but unpaid bonuses to which Employee is entitled under any incentive bonus plan. The Company (or its successor) shall also provide (i) for a period of three years following termination of employment continuing coverage and benefits comparable to all life, health and disability plans of the Company in effect at the time a change of control is deemed to have occurred; (ii) a lump-sum payment equal to three times the stipulated flexible perquisites amount pursuant to Section 2(d); and (iii) three years additional service credit under the current non-qualified supplemental pension plans, or successors thereto, of the Company applicable to the Employee on the date of termination. The Company agrees that if remuneration or benefits of any form paid to Employee by the Company or any trust funded by the Company during or after his employment with the Company are excess parachute payments as defined in Section 280G of the Internal Revenue Code of 1986, as amended ("Code"), and are subject to the 20 percent excise tax imposed by Section 4999 of the Code, the Company shall pay Employee a bonus no later than seven days prior to the due date for the excise tax return in an amount equal to the excise tax payable as a result of the excess parachute payment and any additional federal income taxes (including any additional excise taxes) payable by 5 6 him as a result of the bonus, assuming that he will be subject to federal income taxes at the highest individual margin rate. It is the intention of the parties that the bonus be "grossed up" so that the bonus contains sufficient funds to pay the excise and all additional federal income taxes due as a result of the bonus payment so that Employee will suffer no detriment from the excise tax payable as a result of the excess parachute payments. For purposes of this Agreement, a "change of control" shall be deemed to have occurred if (i) there shall be consummated (A) any consolidation or merger of the Company in which the Company is not the continuing or surviving corporation or pursuant to which shares of the Company's Common Stock would be converted into cash, securities or other property, other than a merger of the Company where a majority of the Board of Directors of the surviving corporation are, and for a two-year period after the merger continue to be, persons who were directors of the Company immediately prior to the merger or were elected as directors, or nominated for election as director, by a vote of at least two- thirds of the directors then still in office who were directors of the Company immediately prior to the merger, or (B) any sale, lease, exchange or transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of the Company, or (ii) the shareholders of the Company shall approve any plan or proposal for the liquidation or dissolution of the Company or (iii)(A) any "person" (as such term is used in Sections 13(d) and 14(d)(2) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), other than the Company or a subsidiary thereof or any employee benefit plan sponsored by the Company or a subsidiary thereof, shall become the beneficial owner (within the meaning of Rule 13d-3 under the Exchange Act) of securities of the Company representing 20 percent or more of the combined voting power of the Company's then outstanding securities ordinarily (and apart from rights accruing in special circumstances) having the right to vote in the election of directors, as a result of a tender or exchange offer, open market purchases, privately negotiated purchases or otherwise, and (B) at any time during a period of two years thereafter, individuals who immediately prior to the beginning of such period constituted the Board of Directors of the Company shall cease for any reason to constitute at least a majority thereof, unless the election or the nomination by the Board of Directors for election by the Company's shareholders of each new director during such period was approved by a vote of at least two-thirds of the directors then still in office who were directors at the beginning of such period. For purposes of this Section 9, "good reason upon change of control" shall exist if any of the following occurs: (i) without Employee's express written consent, the assignment to Employee of any duties inconsistent with the employment of Employee to the positions set forth in Section 1, or a significant diminution of Employee's positions, duties, responsibilities or status with the Company from those immediately prior to a change of control or a diminution in Employee's titles or offices as in effect immediately prior to a change of control, or any removal of Employee from, or any failure to reelect Employee to, any of such positions; (ii) a reduction by the Company in Employee's Base Salary in effect immediately prior to a change of control; 6 7 (iii) the failure by the Company to continue in effect any thrift, stock ownership, pension, life insurance, health, dental and accident or disability plan in which Employee is participating or is eligible to participate at the time of the change of control (or plans providing Employee with substantially similar benefits), except as otherwise required by the terms of such plans as in effect at the time of any change of control or the taking of any action by the Company which would adversely affect Employee's participation in or materially reduce Employee's benefits under any of such plans or deprive Employee of any material fringe benefits enjoyed by Employee at the time of the change of control or the failure by the Company to provide the Employee with the number of paid vacation days to which Employee is entitled in accordance with the vacation policies of the Company in effect at the time of a change of control; (iv) the failure by the Company to continue in effect any incentive plan or arrangement (including without limitation, the Company's Incentive Compensation Plan and similar incentive compensation benefits) in which Employee is participating at the time of a change of control (or to substitute and continue other plans or arrangements providing the Employee with substantially similar benefits), except as otherwise required by the terms of such plans as in effect at the time of any change of control; (v) the failure by the Company to continue in effect any plan or arrangement with respect to securities of the Company (including, without limitation, any plan or arrangement to receive and exercise stock options, stock appreciation rights, restricted stock or grants thereof or to acquire stock or other securities of the Company) in which Employee is participating at the time of a change of control (or to substitute and continue plans or arrangements providing the Employee with substantially similar benefits), except as otherwise required by the terms of such plans as in effect at the time of any change of control or the taking of any action by the Company which would adversely affect Employee's participation in or materially reduce Employee's benefits under any such plan; (vi) the relocation of the Company's principal executive offices to a location outside the San Antonio, Texas, area, or the Company's requiring Employee to be based anywhere other than at the location of the Company's principal executive offices, except for required travel on the Company's business to an extent substantially consistent with Employee's present business travel obligations, or, in the event Employee consents to any such relocation of the Company's principal executive or divisional offices, the failure by the Company to pay (or reimburse Employee for) all reasonable moving expenses incurred by Employee relating to a change of Employee's principal residence in connection with such relocation and to indemnify Employee against any loss (defined as the difference between the actual sale price of such residence and the fair market value thereof as determined by the highest of three appraisals from Member Appraisal Institute-approved real estate appraisers reasonably satisfactory to both Employee and the Company at the time Employee's principal residence is offered for sale in connection with any such change of residence); (vii) any material breach by the Company of any provision of this Agreement; 7 8 (viii) any failure by the Company to obtain the assumption of this Agreement by any successor or assign of the Company; or (ix) any purported termination of Employee's employment by the Company other than termination for cause fully in compliance with this Agreement and for purposes of this Agreement, no such purported termination shall be effective. In the event of a change of control as "change of control" is defined in any stock option plan or stock option agreement pursuant to which the Employee holds options to purchase Common Stock of the Company, Employee shall retain the rights to all accelerated vesting and other benefits under the terms of such plans and agreements. The Company shall pay any attorney's fees incurred by Employee in reasonably seeking to enforce the terms of this paragraph 9. 10. Exclusivity of Termination Provisions. The termination provisions of this Agreement regarding the parties' respective obligations in the event Employee's employment is terminated, are intended to be exclusive and in lieu of any other rights or remedies to which Employee or the Company may otherwise be entitled at law, in equity, or otherwise. It is also agreed that, although the personnel policies and fringe benefit programs of the Company may be unilaterally modified from time to time, the termination provisions of this Agreement are not subject to modification, whether orally, impliedly or in writing, unless any such modification is mutually agreed upon and signed by the parties. 11. Vacation. Employee shall be entitled to four weeks vacation annually in accordance with Company policy as in effect from time to time. In the event Employee does not use his entire vacation time in any year, Employee shall be entitled to carry over unused vacation into the following year until his accrued vacation reaches six weeks or such greater period as may be permitted under the Company's vacation policy for management executives. 12. Nondisclosure. During the term of this Agreement and thereafter, Employee shall not, without the prior written consent of the Board of Directors, disclose or use for any purpose (except in the course of his employment under this Agreement and in furtherance of the business of the Company) confidential information or proprietary data of the Company (or any of its subsidiaries), except as required by applicable law or legal process; provided, however, that confidential information shall not include any information known generally to the public or ascertainable from public or published information (other than as a result of unauthorized disclosure by Employee) or any information of a type not otherwise considered confidential by persons engaged in the same business or a business similar to that conducted by the Company (or any of its subsidiaries). 13. Noncompetition. The Company and Employee agree that the services rendered by Employee hereunder are unique and irreplaceable. Employee hereby agrees that, during the term of this Agreement and for a period of one year thereafter, he shall not (except in the course of his 8 9 employment under this Agreement and in furtherance of the business of the Company (or any of its subsidiaries)) (i) engage in as principal, consultant or employee in any segment of a business of a company, partnership or firm ("Business Segment") that is directly competitive with any significant business of the Company in one of its major commercial or geographic markets or (ii) hold an interest (except as a holder of a less than 5 percent interest in a publicly traded firm or mutual fund, or as a minority stockholder or unitholder in a firm not publicly traded) in a company, partnership, or firm with a Business Segment that is directly competitive with the Company, without prior written consent of the Company. 14. Remedies. Employee acknowledges that irreparable damage would result to the Company if the provisions of paragraph 12 or 13 above are not specifically enforced and agrees that the Company shall be entitled to any appropriate legal, equitable or other remedy, including injunctive relief, in respect of any failure to comply with such provisions. 15. Miscellaneous. (a) Complete Agreement. This Agreement constitutes the entire agreement between the parties and cancels and supersedes all other agreements between the parties which may have related to the subject matter contained in this Agreement, including without limitation the Prior Agreement. (b) Modification; Amendment; Waiver. No modification, amendment or waiver of any provisions of this Agreement shall be effective unless approved in writing by both parties. The failure at any time to enforce any of the provisions of this Agreement shall in no way be construed as a waiver of such provisions and shall not affect the right of either party thereafter to enforce each and every provision hereof in accordance with its terms. (c) Governing Law; Jurisdiction. This Agreement and performance under it, and all proceedings that may ensue from its breach, shall be construed in accordance with and under the laws of the State of Texas. (d) No Breach of Other Obligations. Employee represents and warrants to the Company that he has not and shall not bring to the Company, or use in the performance of his responsibilities to the Company, any materials, documents or information of a former employer (or other person to whom Employee may hold a duty of confidentiality) which are not generally available to the public unless Employee delivers to Company prior written authorization to use such materials, documents or information. (e) Employee's Representations. Employee represents and warrants that he is free to enter into this Agreement and to perform each of the terms and covenants of it. Employee represents and warrants that he is not restricted or prohibited, contractually or otherwise, from entering into and performing this Agreement, and that his execution and performance of this Agreement is not a violation or breach of any other agreement between Employee and any other person or entity. 9 10 (f) Company's Representations. Company represents and warrants that it is free to enter into this Agreement and to perform each of the terms and covenants of it. Company represents and warrants that it is not restricted or prohibited, contractually or otherwise, from entering into and performing this Agreement, and that its execution and performance of this Agreement is not a violation or breach of any other agreement between Company and any other person or entity. The Company represents and warrants that this Agreement is a legal, valid and binding agreement of the Company, enforceable in accordance with its terms. The Company further represents and warrants that sufficient shares are available and will remain available under the Plan to fund stock option awards under the Prior Agreement and under the Stock Option Agreement entered into in connection therewith. With respect to such stock options, the Company warrants that the Plan meets all of the requirements of Rule 16b-3 promulgated under the Securities Exchange Act of 1934, as amended. The Company shall be in continuous compliance with all applicable registration requirements with respect to the Company's common stock issued under such Stock Option Agreement. Upon exercise of such stock options, all shares subject thereto will be fully paid and non-assessable. (g) Severability. Whenever possible, each provision of this Agreement shall be interpreted in such manner as to be effective and valid under applicable law, but if any provision of this Agreement shall be held to be prohibited by or invalid under applicable law, such provision shall be ineffective only to the extent of such prohibition or invalidity, without invalidating the remainder of such provision or the remaining provisions of this Agreement. (h) Assignment. The rights and obligations of the parties under this Agreement shall be binding upon and inure to the benefit of their respective successors, assigns, executors, administrators and heirs, provided, however, that neither the Company nor Employee may assign any duties under this Agreement without the prior written consent of the other. (i) Limitation. This Agreement shall not confer any right or impose any obligation on the Company to continue the employment of Employee in any capacity, or limit the right of the Company or Employee to terminate Employee's employment. (j) Notices. All notices and other communications under this Agreement shall be in writing and shall be given in person or by telegraph, telefax or first class mail, certified or registered with return receipt requested, and shall be deemed to have been duly given when delivered personally or three days after mailing or one day after transmission of a telegram or telefax, as the case may be, to the respective persons named below: If to the Company: Corporate Secretary Tesoro Petroleum Corporation 8700 Tesoro Drive San Antonio, Texas 78217 10 11 If to the Employee: Bruce A. Smith 400 Elizabeth San Antonio, Texas 78209 IN WITNESS WHEREOF, the parties have executed this Agreement as of the day and year first above written. COMPANY: TESORO PETROLEUM CORPORATION /s/ JAMES C. REED, JR. ---------------------------------- James C. Reed, Jr. Executive Vice President, General Counsel and Secretary EMPLOYEE: /s/ BRUCE A. SMITH ---------------------------------- Bruce A. Smith 11 12 EXHIBIT A Benefits Listing 1. Group Health Plan 2. Group Life and Accidental Death & Dismemberment Plan 3. Short Term Disability Income Plan 4. Long Term Disability Income Plan 5. Business Travel Accident Insurance Plan 6. Tesoro Petroleum Corporation Thrift/401K Plan 7. Tesoro Petroleum Corporation Retirement Plan 8. Tesoro Petroleum Corporation Amended Executive Security Plan 9. Tesoro Petroleum Corporation Funded Executive Security Plan 10. Tax Preparation and Financial Planning EX-10.7 3 MANAGEMENT STABILITY AGREEMENT-DONALD A. NYBERG 1 ITEM 14(a)3, EXHIBIT 10.7 MANAGEMENT STABILITY AGREEMENT This Management Stability Agreement is dated December 12, 1996, between Tesoro Petroleum Corporation, a Delaware corporation (the "Company"), and Donald A. Nyberg ("Employee"). Recitals: WHEREAS, the Board of Directors of the Company has determined that it is in the best interest of the Company to reduce uncertainty to certain key employees of the Company in the event of certain fundamental events involving the control or existence of the Company; WHEREAS, the Board of Directors of the Company has determined that an agreement protecting certain interests of key employees of the Company in the event of certain fundamental events involving the control or existence of the Company is in the best interest of the Company because it will assist the Company in attracting and retaining key employees such as this Employee; and WHEREAS, the Employee is relying on this Agreement and the obligations of the Company hereunder in continuing to work for the Company. NOW, THEREFORE, THE PARTIES AGREE AS FOLLOWS: 1. Termination Following Change of Control. Should Employee at any time within two years of a change of control cease to be an employee of the Company (or its successor), by reason of (i) involuntary termination by the Company (or its successor) other than for "cause" (following a change of control), "cause" shall be limited to the conviction of or a plea of nolo contendere to the charge of a felony (which, through lapse of time or otherwise, is not subject to appeal), a material breach of fiduciary duty to the Company through the misappropriation of Company funds or property) or (ii) voluntary termination by Employee for "good reason upon change of control" (as defined below), the Company (or its successor) shall pay to Employee within ten days of such termination the following severance payments and benefits: (a) A lump-sum payment equal to two times the base salary of the Employee at the then current rate; and (b) A lump-sum payment equal to (i) two times the sum of the target bonuses under all of the Company's incentive bonus plans applicable to the Employee for the year in which the termination occurs or the year in which the change of control occurred, 2 whichever is greater, and (ii) if termination occurs in the fourth quarter of a calendar year, the sum of the target bonuses under all of the Company's incentive bonus plans applicable to Employee for the year in which the termination occurs prorated daily based on the number of days from the beginning of the calendar year in which the termination occurs to and including the date of termination. The Company (or its successor) shall also provide continuing coverage and benefits comparable to all life, health and disability plans of the Company for a period of 24 months from the date of termination and shall receive two years additional service credit under the current non-qualified supplemental pension plans, or successors thereto, of the Company applicable to the Employee on the date of termination. For purposes of this Agreement, a "change of control" shall be deemed to have occurred if (i) there shall be consummated (A) any consolidation or merger of the Company in which the Company is not the continuing or surviving corporation or pursuant to which shares of the Company's Common Stock would be converted into cash, securities or other property, other than a merger of the Company where a majority of the Board of Directors of the surviving corporation are, and for a two year period after the merger continue to be, persons who were directors of the Company immediately prior to the merger or were elected as directors, or nominated for election as directors, by a vote of at least two-thirds of the directors then still in office who were directors of the Company immediately prior to the merger, or (B) any sale, lease, exchange or transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of the Company, or (ii) the shareholders of the Company shall approve any plan or proposal for the liquidation or dissolution of the Company, or (iii) (A) any "person" (as such term is used in Sections 13(d) and 14(d)(2) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), other than the Company or a subsidiary thereof or any employee benefit plan sponsored by the Company or a subsidiary thereof, shall become the beneficial owner (within the meaning of Rule 13d-3 under the Exchange Act) of securities of the Company representing 20 percent or more of the combined voting power of the Company's then outstanding securities ordinarily (and apart from rights accruing in special circumstances) having the right to vote in the election of 2 3 directors, as a result of a tender or exchange offer, open market purchases, privately negotiated purchases or otherwise, and (B) at any time during a period of one year thereafter, individuals who immediately prior to the beginning of such period constituted the Board of Directors of the Company shall cease for any reason to constitute at least a majority thereof, unless the election or the nomination by the Board of Directors for election by the Company's shareholders of each new director during such period was approved by a vote of at least two-thirds of the directors then still in office who were directors at the beginning of such period, or (iv) there shall be (A) a direct or indirect sale of all or substantially all of the assets of the Company's marine services business, or (B) the sale of stock of a subsidiary (or affiliate) of the Company that conducts all or substantially all of the Company's marine services business, or (C) a merger, joint venture or other business combination involving the Company's marine services business, and as a result of such sale of assets, sale of stock, merger, joint venture or other business combination, the Company shall cease to have the power to elect a majority of the Board of Directors (or the other equivalent governing or managing body) of the entity which acquires, or otherwise controls or conducts, the Company's marine services business. For purposes of this Section 1, "good reason upon change of control" shall exist if any of the following occurs: (i) without Employee's express written consent, the assignment to Employee of any duties inconsistent with the employment of Employee immediately prior to the change of control, or a significant diminution of Employee's positions, duties, responsibilities and status with the Company from those immediately prior to a change of control or a diminution in Employee's titles or offices as in effect immediately prior to a change of control, or any removal of Employee from, or any failure to reelect Employee to, any of such positions; (ii) a reduction by the Company in Employee's base salary in effect immediately prior to a change of control; 3 4 (iii) the failure by the Company to continue in effect any thrift, stock ownership, pension, life insurance, health, dental and accident or disability plan in which Employee is participating or is eligible to participate at the time of the change of control (or plans providing Employee with substantially similar benefits), except as otherwise required by the terms of such plans as in effect at the time of any change of control or the taking of any action by the Company which would adversely affect Employee's participation in or materially reduce Employee's benefits under any of such plans or deprive Employee of any material fringe benefits enjoyed by Employee at the time of the change of control or the failure by the Company to provide the Employee with the number of paid vacation days to which Employee is entitled in accordance with the vacation policies of the Company in effect at the time of a change of control; (iv) the failure by the Company to continue in effect any incentive plan or arrangement (including without limitation, the Company's Incentive Compensation Plan and similar incentive compensation benefits) in which Employee is participating at the time of a change of control (or to substitute and continue other plans or arrangements providing the Employee with substantially similar benefits), except as otherwise required by the terms of such plans as in effect at the time of any change of control; (v) the failure by the Company to continue in effect any plan or arrangement with respect to securities of the Company (including, without limitation, any plan or arrangement to receive and exercise stock options, stock appreciation rights, restricted stock or grants thereof or to acquire stock or other securities of the Company) in which Employee is participating at the time of a change of control (or to substitute and continue plans or arrangements providing the Employee with substantially similar benefits), except as otherwise required by the terms of such plans as in effect at the time of any change of control or the taking of any action by the Company which would adversely affect Employee's participation in or materially reduce Employee's benefits under any such plan; 4 5 (vi) the relocation of the Company's offices where Employee is presently based to a location outside that office area, or the Company's requiring Employee to be based anywhere other than at the location of the Company's offices where Employee is presently based, except for required travel on the Company's business to an extent substantially consistent with Employee's present business travel obligations, or, in the event Employee consents to any such relocation of the Company's offices where Employee is presently based, the failure by the Company to pay (or reimburse Employee for) all reasonable moving expenses incurred by Employee relating to a change of Employee's principal residence in connection with such relocation and to indemnify Employee against any loss (defined as the difference between the actual sale price of such residence and the higher of (a) Employee's aggregate investment in such residence or (b) the fair market value thereof as determined by a real estate appraiser reasonably satisfactory to both Employee and the Company at the time the Employee's principal residence is offered for sale in connection with any such change of residence; (vii) any failure by the Company to obtain the assumption of this Agreement by any successor or assign of the Company; In the event of a change of control as "change of control" is defined in any stock option plan or stock option agreement pursuant to which the Employee holds options to purchase common stock of the Company, Employee shall retain the rights to all accelerated vesting and other benefits under the terms thereof. The Company shall pay any attorney fees incurred by Employee in reasonably seeking to enforce the terms of this Paragraph 1. 2. Complete Agreement. This Agreement constitutes the entire agreement between the parties and cancels and supersedes all other agreements between the parties which may have related to the subject matter contained in this Agreement. 3. Modification; Amendment; Waiver. No modification, amendment or waiver of any provisions of this Agreement shall be effective unless approved in writing by both parties. The failure at any time to 5 6 enforce any of the provisions of this Agreement shall in no way be construed as a waiver of such provisions and shall not affect the right of either party thereafter to enforce each and every provision hereof in accordance with its terms. 4. Governing Law; Jurisdiction. This Agreement and performance under it, and all proceedings that may ensue from its breach, shall be construed in accordance with and under the laws of the State of Texas. 5. Severability. Whenever possible, each provision of this Agreement shall be interpreted in such manner as to be effective and valid under applicable law, but if any provision of this Agreement shall be held to be prohibited by or invalid under applicable law, such provision shall be ineffective only to the extent of such prohibition or invalidity, without invalidating the remainder of such provision or the remaining provisions of this Agreement. 6. Assignment. The rights and obligations of the parties under this Agreement shall be binding upon and inure to the benefit of their respective successors, assigns, executors, administrators and heirs, provided, however, that the Company may not assign any duties under this Agreement without the prior written consent of the Employee. 7. Limitation. This Agreement shall not confer any right or impose any obligation on the Company to continue the employment of Employee in any capacity, or limit the right of the Company or Employee to terminate Employee's employment. 8. Notices. All notices and other communications under this Agreement shall be in writing and shall be given in person or by telegraph, facsimile or first class mail, certified or registered with return receipt requested, and shall be deemed to have been duly given when delivered personally or three days after mailing or one day after transmission of a telegram or facsimile, as the case may be, to the representative persons named below: 6 7 If to the Company: Corporate Secretary Tesoro Petroleum Corporation 8700 Tesoro Drive San Antonio, Texas 78217 If to the Employee: Donald A. Nyberg 9426 Telephone Road Houston, Texas 77075 IN WITNESS WHEREOF, the parties have executed this Agreement as of the day and year first above written. COMPANY: TESORO PETROLEUM CORPORATION By /s/ BRUCE A. SMITH ---------------------------------- Bruce A. Smith Chairman of the Board of Directors, President and Chief Executive Officer EMPLOYEE: /s/ DONALD A. NYBERG -------------------------------------- Donald A. Nyberg 7 EX-10.8 4 MANAGEMENT STABILITY AGREEMENT-ROBERT W. OLIVER 1 ITEM 14(a)3, EXHIBIT 10.8 MANAGEMENT STABILITY AGREEMENT This Management Stability Agreement is dated September 27, 1995, between Tesoro Petroleum Corporation, a Delaware corporation (the "Company"), and Robert W. Oliver ("Employee"). Recitals: WHEREAS, the Board of Directors of the Company has determined that it is in the best interest of the Company to reduce uncertainty to certain key employees of the Company in the event of certain fundamental events involving the control or existence of the Company; WHEREAS, the Board of Directors of the Company has determined that an agreement protecting certain interests of key employees of the Company in the event of certain fundamental events involving the control or existence of the Company is in the best interest of the Company because it will assist the Company in attracting and retaining key employees such as this Employee; and WHEREAS, the Employee is relying on this Agreement and the obligations of the Company hereunder in continuing to work for the Company. NOW, THEREFORE, THE PARTIES AGREE AS FOLLOWS: 1. Termination Following Change of Control. Should Employee at any time within two years of a change of control cease to be an employee of the Company (or its successor), by reason of (i) involuntary termination by the Company (or its successor) other than for "cause" (following a change of control), "cause" shall be limited to the conviction of or a plea of nolo contendere to the charge of a felony (which, through lapse of time or otherwise, is not subject to appeal), a material breach of fiduciary duty to the Company through the misappropriation of Company funds or property) or (ii) voluntary termination by Employee for "good reason upon change of control" (as defined below), the Company (or its successor) shall pay to Employee within ten days of such termination the following severance payments and benefits: (a) A lump-sum payment equal to two times the base salary of the Employee at the then current rate; and (b) A lump-sum payment equal to (i) two times the sum of the target bonuses under all of the Company's incentive bonus plans applicable to the Employee for the year in which the termination occurs or the year in which the change of control occurred, 2 whichever is greater, and (ii) if termination occurs in the fourth quarter of a calendar year, the sum of the target bonuses under all of the Company's incentive bonus plans applicable to Employee for the year in which the termination occurs prorated daily based on the number of days from the beginning of the calendar year in which the termination occurs to and including the date of termination. The Company (or its successor) shall also provide continuing coverage and benefits comparable to all life, health and disability plans of the Company for a period of 24 months from the date of termination and shall receive two years additional service credit under the current non-qualified supplemental pension plans, or successors thereto, of the Company applicable to the Employee on the date of termination. For purposes of this Agreement, a "change of control" shall be deemed to have occurred if (i) there shall be consummated (A) any consolidation or merger of the Company in which the Company is not the continuing or surviving corporation or pursuant to which shares of the Company's Common Stock would be converted into cash, securities or other property, other than a merger of the Company where a majority of the Board of Directors of the surviving corporation are, and for a two year period after the merger continue to be, persons who were directors of the Company immediately prior to the merger or were elected as directors, or nominated for election as directors, by a vote of at least two-thirds of the directors then still in office who were directors of the Company immediately prior to the merger, or (B) any sale, lease, exchange or transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of the Company, or (ii) the shareholders of the Company shall approve any plan or proposal for the liquidation or dissolution of the Company, or (iii) (A) any "person" (as such term is used in Sections 13(d) and 14(d)(2) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), other than the Company or a subsidiary thereof or any employee benefit plan sponsored by the Company or a subsidiary thereof, shall become the beneficial owner (within the meaning of Rule 13d-3 under the Exchange Act) of securities of the Company representing 20 percent or more of the combined voting power of the Company's then outstanding securities ordinarily (and apart from rights accruing in special circumstances) having the right to vote in the election of 2 3 directors, as a result of a tender or exchange offer, open market purchases, privately negotiated purchases or otherwise, and (B) at any time during a period of one year thereafter, individuals who immediately prior to the beginning of such period constituted the Board of Directors of the Company shall cease for any reason to constitute at least a majority thereof, unless the election or the nomination by the Board of Directors for election by the Company's shareholders of each new director during such period was approved by a vote of at least two-thirds of the directors then still in office who were directors at the beginning of such period. For purposes of this Section 1, "good reason upon change of control" shall exist if any of the following occurs: (i) without Employee's express written consent, the assignment to Employee of any duties inconsistent with the employment of Employee immediately prior to the change of control, or a significant diminution of Employee's positions, duties, responsibilities and status with the Company from those immediately prior to a change of control or a diminution in Employee's titles or offices as in effect immediately prior to a change of control, or any removal of Employee from, or any failure to reelect Employee to, any of such positions; (ii) a reduction by the Company in Employee's base salary in effect immediately prior to a change of control; (iii) the failure by the Company to continue in effect any thrift, stock ownership, pension, life insurance, health, dental and accident or disability plan in which Employee is participating or is eligible to participate at the time of the change of control (or plans providing Employee with substantially similar benefits), except as otherwise required by the terms of such plans as in effect at the time of any change of control or the taking of any action by the Company which would adversely affect Employee's participation in or materially reduce Employee's benefits under any of such plans or deprive Employee of any material fringe benefits enjoyed by Employee at the time of the change of control or the failure by the Company to provide the Employee with the number of paid vacation 3 4 days to which Employee is entitled in accordance with the vacation policies of the Company in effect at the time of a change of control; (iv) the failure by the Company to continue in effect any incentive plan or arrangement (including without limitation, the Company's Incentive Compensation Plan and similar incentive compensation benefits) in which Employee is participating at the time of a change of control (or to substitute and continue other plans or arrangements providing the Employee with substantially similar benefits), except as otherwise required by the terms of such plans as in effect at the time of any change of control; (v) the failure by the Company to continue in effect any plan or arrangement with respect to securities of the Company (including, without limitation, any plan or arrangement to receive and exercise stock options, stock appreciation rights, restricted stock or grants thereof or to acquire stock or other securities of the Company) in which Employee is participating at the time of a change of control (or to substitute and continue plans or arrangements providing the Employee with substantially similar benefits), except as otherwise required by the terms of such plans as in effect at the time of any change of control or the taking of any action by the Company which would adversely affect Employee's participation in or materially reduce Employee's benefits under any such plan; (vi) the relocation of the Company's principal executive offices to a location outside the San Antonio, Texas, area, or the Company's requiring Employee to be based anywhere other than at the location of the Company's principal executive offices, except for required travel on the Company's business to an extent substantially consistent with Employee's present business travel obligations, or, in the event Employee consents to any such relocation of the Company's principal executive or divisional offices, the failure by the Company to pay (or reimburse Employee for) all reasonable moving expenses incurred by Employee relating to a change of Employee's principal residence in connection with such relocation and to indemnify Employee against any loss (defined as the difference between the actual sale price of such residence and the higher of 4 5 (a) Employee's aggregate investment in such residence or (b) the fair market value thereof as determined by a real estate appraiser reasonably satisfactory to both Employee and the Company at the time the Employee's principal residence is offered for sale in connection with any such change of residence; (vii) any failure by the Company to obtain the assumption of this Agreement by any successor or assign of the Company; In the event of a change of control as "change of control" is defined in any stock option plan or stock option agreement pursuant to which the Employee holds options to purchase common stock of the Company, Employee shall retain the rights to all accelerated vesting and other benefits under the terms thereof. The Company shall pay any attorney fees incurred by Employee in reasonably seeking to enforce the terms of this Paragraph 1. 2. Complete Agreement. This Agreement constitutes the entire agreement between the parties and cancels and supersedes all other agreements between the parties which may have related to the subject matter contained in this Agreement. 3. Modification; Amendment; Waiver. No modification, amendment or waiver of any provisions of this Agreement shall be effective unless approved in writing by both parties. The failure at any time to enforce any of the provisions of this Agreement shall in no way be construed as a waiver of such provisions and shall not affect the right of either party thereafter to enforce each and every provision hereof in accordance with its terms. 4. Governing Law; Jurisdiction. This Agreement and performance under it, and all proceedings that may ensue from its breach, shall be construed in accordance with and under the laws of the State of Texas. 5. Severability. Whenever possible, each provision of this Agreement shall be interpreted in such manner as to be effective and valid under applicable law, but if any provision of this Agreement shall be held to be prohibited by or invalid under applicable law, such 5 6 provision shall be ineffective only to the extent of such prohibition or invalidity, without invalidating the remainder of such provision or the remaining provisions of this Agreement. 6. Assignment. The rights and obligations of the parties under this Agreement shall be binding upon and inure to the benefit of their respective successors, assigns, executors, administrators and heirs, provided, however, that the Company may not assign any duties under this Agreement without the prior written consent of the Employee. 7. Limitation. This Agreement shall not confer any right or impose any obligation on the Company to continue the employment of Employee in any capacity, or limit the right of the Company or Employee to terminate Employee's employment. 8. Notices. All notices and other communications under this Agreement shall be in writing and shall be given in person or by telegraph, facsimile or first class mail, certified or registered with return receipt requested, and shall be deemed to have been duly given when delivered personally or three days after mailing or one day after transmission of a telegram or facsimile, as the case may be, to the representative persons named below: If to the Company: Corporate Secretary Tesoro Petroleum Corporation 8700 Tesoro Drive San Antonio, Texas 78217 If to the Employee: Robert W. Oliver 8700 Tesoro Drive San Antonio, Texas 78217 6 7 IN WITNESS WHEREOF, the parties have executed this Agreement as of the day and year first above written. COMPANY: TESORO PETROLEUM CORPORATION By /s/ BRUCE A. SMITH ------------------------ Bruce A. Smith Chief Operating Officer EMPLOYEE: /s/ ROBERT W.OLIVER ----------------------------- Robert W. Oliver 7 EX-10.9 5 MANAGEMENT STABILITY AGREEMENT-STEVE WORMINGTON 1 ITEM 14(a)3, EXHIBIT 10.9 MANAGEMENT STABILITY AGREEMENT This Management Stability Agreement is dated September 27, 1995, between Tesoro Petroleum Corporation, a Delaware corporation (the "Company"), and Steve Wormington ("Employee"). Recitals: WHEREAS, the Board of Directors of the Company has determined that it is in the best interest of the Company to reduce uncertainty to certain key employees of the Company in the event of certain fundamental events involving the control or existence of the Company; WHEREAS, the Board of Directors of the Company has determined that an agreement protecting certain interests of key employees of the Company in the event of certain fundamental events involving the control or existence of the Company is in the best interest of the Company because it will assist the Company in attracting and retaining key employees such as this Employee; and WHEREAS, the Employee is relying on this Agreement and the obligations of the Company hereunder in continuing to work for the Company. NOW, THEREFORE, THE PARTIES AGREE AS FOLLOWS: 1. Termination Following Change of Control. Should Employee at any time within two years of a change of control cease to be an employee of the Company (or its successor), by reason of (i) involuntary termination by the Company (or its successor) other than for "cause" (following a change of control), "cause" shall be limited to the conviction of or a plea of nolo contendere to the charge of a felony (which, through lapse of time or otherwise, is not subject to appeal), a material breach of fiduciary duty to the Company through the misappropriation of Company funds or property) or (ii) voluntary termination by Employee for "good reason upon change of control" (as defined below), the Company (or its successor) shall pay to Employee within ten days of such termination the following severance payments and benefits: (a) A lump-sum payment equal to two times the base salary of the Employee at the then current rate; and (b) A lump-sum payment equal to (i) two times the sum of the target bonuses under all of the Company's incentive bonus plans applicable to the Employee for the year in which the termination occurs or the year in which the change of control occurred, 2 whichever is greater, and (ii) if termination occurs in the fourth quarter of a calendar year, the sum of the target bonuses under all of the Company's incentive bonus plans applicable to Employee for the year in which the termination occurs prorated daily based on the number of days from the beginning of the calendar year in which the termination occurs to and including the date of termination. The Company (or its successor) shall also provide continuing coverage and benefits comparable to all life, health and disability plans of the Company for a period of 24 months from the date of termination and shall receive two years additional service credit under the current non-qualified supplemental pension plans, or successors thereto, of the Company applicable to the Employee on the date of termination. For purposes of this Agreement, a "change of control" shall be deemed to have occurred if (i) there shall be consummated (A) any consolidation or merger of the Company in which the Company is not the continuing or surviving corporation or pursuant to which shares of the Company's Common Stock would be converted into cash, securities or other property, other than a merger of the Company where a majority of the Board of Directors of the surviving corporation are, and for a two year period after the merger continue to be, persons who were directors of the Company immediately prior to the merger or were elected as directors, or nominated for election as directors, by a vote of at least two-thirds of the directors then still in office who were directors of the Company immediately prior to the merger, or (B) any sale, lease, exchange or transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of the Company, or (ii) the shareholders of the Company shall approve any plan or proposal for the liquidation or dissolution of the Company, or (iii) (A) any "person" (as such term is used in Sections 13(d) and 14(d)(2) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), other than the Company or a subsidiary thereof or any employee benefit plan sponsored by the Company or a subsidiary thereof, shall become the beneficial owner (within the meaning of Rule 13d-3 under the Exchange Act) of securities of the Company representing 20 percent or more of the combined voting power of the Company's then outstanding securities ordinarily (and apart from rights accruing in special circumstances) having the right to vote in the election of 2 3 directors, as a result of a tender or exchange offer, open market purchases, privately negotiated purchases or otherwise, and (B) at any time during a period of one year thereafter, individuals who immediately prior to the beginning of such period constituted the Board of Directors of the Company shall cease for any reason to constitute at least a majority thereof, unless the election or the nomination by the Board of Directors for election by the Company's shareholders of each new director during such period was approved by a vote of at least two-thirds of the directors then still in office who were directors at the beginning of such period. For purposes of this Section 1, "good reason upon change of control" shall exist if any of the following occurs: (i) without Employee's express written consent, the assignment to Employee of any duties inconsistent with the employment of Employee immediately prior to the change of control, or a significant diminution of Employee's positions, duties, responsibilities and status with the Company from those immediately prior to a change of control or a diminution in Employee's titles or offices as in effect immediately prior to a change of control, or any removal of Employee from, or any failure to reelect Employee to, any of such positions; (ii) a reduction by the Company in Employee's base salary in effect immediately prior to a change of control; (iii) the failure by the Company to continue in effect any thrift, stock ownership, pension, life insurance, health, dental and accident or disability plan in which Employee is participating or is eligible to participate at the time of the change of control (or plans providing Employee with substantially similar benefits), except as otherwise required by the terms of such plans as in effect at the time of any change of control or the taking of any action by the Company which would adversely affect Employee's participation in or materially reduce Employee's benefits under any of such plans or deprive Employee of any material fringe benefits enjoyed by Employee at the time of the change of control or the failure by the Company to provide the Employee with the number of paid vacation 3 4 days to which Employee is entitled in accordance with the vacation policies of the Company in effect at the time of a change of control; (iv) the failure by the Company to continue in effect any incentive plan or arrangement (including without limitation, the Company's Incentive Compensation Plan and similar incentive compensation benefits) in which Employee is participating at the time of a change of control (or to substitute and continue other plans or arrangements providing the Employee with substantially similar benefits), except as otherwise required by the terms of such plans as in effect at the time of any change of control; (v) the failure by the Company to continue in effect any plan or arrangement with respect to securities of the Company (including, without limitation, any plan or arrangement to receive and exercise stock options, stock appreciation rights, restricted stock or grants thereof or to acquire stock or other securities of the Company) in which Employee is participating at the time of a change of control (or to substitute and continue plans or arrangements providing the Employee with substantially similar benefits), except as otherwise required by the terms of such plans as in effect at the time of any change of control or the taking of any action by the Company which would adversely affect Employee's participation in or materially reduce Employee's benefits under any such plan; (vi) the relocation of the Company's offices where Employee is presently based to a location outside that office area, or the Company's requiring Employee to be based anywhere other than at the location of the Company's offices where Employee is presently based, except for required travel on the Company's business to an extent substantially consistent with Employee's present business travel obligations, or, in the event Employee consents to any such relocation of the Company's offices where Employee is presently based, the failure by the Company to pay (or reimburse Employee for) all reasonable moving expenses incurred by Employee relating to a change of Employee's principal residence in connection with such relocation and to indemnify Employee against any loss (defined as the difference between the actual sale price of 4 5 such residence and the higher of (a) Employee's aggregate investment in such residence or (b) the fair market value thereof as determined by a real estate appraiser reasonably satisfactory to both Employee and the Company at the time the Employee's principal residence is offered for sale in connection with any such change of residence; (vii) any failure by the Company to obtain the assumption of this Agreement by any successor or assign of the Company; In the event of a change of control as "change of control" is defined in any stock option plan or stock option agreement pursuant to which the Employee holds options to purchase common stock of the Company, Employee shall retain the rights to all accelerated vesting and other benefits under the terms thereof. The Company shall pay any attorney fees incurred by Employee in reasonably seeking to enforce the terms of this Paragraph 1. 2. Complete Agreement. This Agreement constitutes the entire agreement between the parties and cancels and supersedes all other agreements between the parties which may have related to the subject matter contained in this Agreement. 3. Modification; Amendment; Waiver. No modification, amendment or waiver of any provisions of this Agreement shall be effective unless approved in writing by both parties. The failure at any time to enforce any of the provisions of this Agreement shall in no way be construed as a waiver of such provisions and shall not affect the right of either party thereafter to enforce each and every provision hereof in accordance with its terms. 4. Governing Law; Jurisdiction. This Agreement and performance under it, and all proceedings that may ensue from its breach, shall be construed in accordance with and under the laws of the State of Texas. 5. Severability. Whenever possible, each provision of this Agreement shall be interpreted in such manner as to be effective and valid under applicable law, but if any provision of this Agreement shall be held to be prohibited by or invalid under applicable law, such 5 6 provision shall be ineffective only to the extent of such prohibition or invalidity, without invalidating the remainder of such provision or the remaining provisions of this Agreement. 6. Assignment. The rights and obligations of the parties under this Agreement shall be binding upon and inure to the benefit of their respective successors, assigns, executors, administrators and heirs, provided, however, that the Company may not assign any duties under this Agreement without the prior written consent of the Employee. 7. Limitation. This Agreement shall not confer any right or impose any obligation on the Company to continue the employment of Employee in any capacity, or limit the right of the Company or Employee to terminate Employee's employment. 8. Notices. All notices and other communications under this Agreement shall be in writing and shall be given in person or by telegraph, facsimile or first class mail, certified or registered with return receipt requested, and shall be deemed to have been duly given when delivered personally or three days after mailing or one day after transmission of a telegram or facsimile, as the case may be, to the representative persons named below: If to the Company: Corporate Secretary Tesoro Petroleum Corporation 8700 Tesoro Drive San Antonio, Texas 78217 If to the Employee: Steve Wormington 3230 C Street Anchorage, Alaska 99503-3918 6 7 IN WITNESS WHEREOF, the parties have executed this Agreement as of the day and year first above written. COMPANY: TESORO PETROLEUM CORPORATION By /s/ BRUCE A. SMITH ------------------------ Bruce A. Smith Chief Operating Officer EMPLOYEE: /s/ STEVE WORMINGTON ------------------------ Steve Wormington 7 EX-10.20 6 PHANTOM STOCK OPTION AGREEMENT 1 ITEM 14(a)3, EXHIBIT 10.20 TESORO PETROLEUM CORPORATION PHANTOM STOCK OPTION AGREEMENT THIS AGREEMENT, effective October 29, 1997, is by and between Bruce A. Smith, Chairman of the Board of Directors, Chief Executive Officer and President of Tesoro Petroleum Corporation (the "CEO") and Tesoro Petroleum Corporation, a Delaware corporation (the "Company"). WITNESSETH: WHEREAS, the Compensation Committee of the Board of Directors of the Company has determined that a phantom stock option grant should be awarded to the CEO as stock-related compensation as part of the Company's long term incentive program and in recognition of the valuable contribution of the CEO and has directed the Company to enter into this Phantom Stock Option agreement (the "Agreement") with the CEO; NOW, THEREFORE, the Company and the CEO agree as follows: 1. GRANT OF OPTION ON PHANTOM STOCK. The Company hereby grants to the CEO effective October 29, 1997, ("Date of Grant"), an option on 175,000 notional shares ("Phantom Option Shares") of the Company's common stock, to receive cash compensation on the terms and conditions set forth in this Agreement, with such cash compensation at the time of exercise of the option being equal to the difference between the average of the highest and lowest quoted selling prices of the Company's common stock as quoted by the New York Stock Exchange on the trading date immediately preceding the date of exercise of the option and $16.9844, which was the average of the highest and lowest quoted selling prices on the Date of Grant. This option on Phantom Option Shares does not create any right of the CEO to shares of the Company's common stock, but only to receive the cash compensation as provided in this Agreement. The Company, under the Company's Executive Long-Term Incentive Plan or successor thereto (hereinafter referred to as the "Plan"), reserves the right to convert this option to a non-qualified stock option to purchase shares of the Company's common stock upon approval of the Committee provided for in the Plan, without the prior consent of the CEO. 2. PERIOD OF OPTION. The option granted herein will expire at 4:00 p.m. Central time on October 28, 2007, (Expiration Time) except that if the CEO ceases for any reason to be employed by the Company before the Expiration Time, the option shall terminate, subject to the provisions of Sections 7,8, 9 and 10 below. This option shall not be exercisable unless, at the time of such exercise, the CEO shall have completed at least twelve (12) months of service with the Company immediately following the Date of Grant. 2 Leave of absence, if approved in writing by an authorized officer of the Company, shall not be considered an interruption, cessation or termination of employment or continuous service for any purpose of this Agreement. The right to exercise the option shall occur in four (4) installments. The first such installment shall vest on the first anniversary of the Date of Grant and an additional installment shall vest on each succeeding anniversary of the Date of Grant to and including the fourth such anniversary. The number of Phantom Option Shares comprised in each of the first three (3) installments, shall be equal to fifteen percent (15%) of the total number of Phantom Option Shares, except that if this creates a number consisting of partial shares, such installment shall be rounded down to the nearest whole number of shares. The number of Phantom Option Shares comprised in the fourth installment shall be the balance of the Phantom Option Shares. The right to exercise this option with respect to the Phantom Option Shares comprised in each installment is cumulative; i.e., once such right has become exercisable it may be exercised in whole at any time or in part from time to time until the termination or expiration of this option. 3. EXERCISE AND PAYMENT. The CEO may exercise this option in whole or in part (but not as to a fraction of a Phantom Option Share) by giving written notice to the Company, in a form satisfactory to the Company, specifying the number of Phantom Option Shares in respect of which the CEO elects to exercise this option. This option shall be canceled in relation to the number of Phantom Option Shares in respect of which this option is exercised. Upon each exercise of this option, the Company as promptly as practicable, shall mail or deliver to the CEO a check in the amount determined to be due to the CEO in accordance with Section 1 of this Agreement. 4. NON-TRANSFERABILITY. This option and any rights and benefits under this Agreement may not be sold, transferred, pledged, encumbered, assigned, or otherwise alienated or hypothecated, other than by will or by the laws of descent and distribution, and it shall be exercisable, during the lifetime of the CEO, only by the CEO. 5. TERMINATION OF EMPLOYMENT FOR CAUSE. If the CEO's employment with the Company is terminated for Cause, all outstanding options under this Agreement held by the CEO shall be forfeited immediately, and no additional time for exercise shall be allowed regardless of the vested status of the options. For this purpose, "Cause" shall be determined by the Company's Board of Directors and shall have the meaning set forth in Article 2(f) of the Plan. 6. DISABILITY OF RECIPIENT. If the CEO becomes disabled (within the meaning of Section 22(e)(3) of the Internal Revenue Code) while the CEO is employed by the Company and such employment is terminated by reason of Disability as defined in Article 2(l) of the Plan, this option shall be exercisable within, but only within, the period of one year next succeeding the date that the Company determines the definition of Disability to have been satisfied, but in no event after the Expiration Time, to the same extent the CEO was entitled to exercise it on the date of determination of the CEO's Disability. -2- 3 7. DEATH OF CEO. If the CEO dies while employed by the Company all options which are exercisable as of the date of death shall be exercisable within, but only within, the period of one year next succeeding the date of death, but in no event after the Expiration Time, to the same extent the CEO was entitled to exercise it on the date of the CEO's death. The term "CEO," as used in this option, shall be deemed to include the estate of the CEO or any person who acquired the right to exercise this option by bequest or inheritance or otherwise by reason of the death of the CEO. 8. TERMINATION BY RETIREMENT. In the event that the CEO's employment is terminated by reason of Retirement as defined in Article 2(ab) of the Plan, all outstanding options which are exercisable as of the date of Retirement shall remain exercisable at any time prior to the Expiration Time, or for three (3) years after the effective date of Retirement, whichever is shorter. 9. EMPLOYMENT TERMINATION FOLLOWED BY DEATH. In the event that the CEO's employment terminates by reason of Disability or Retirement, and within the exercise period following such termination the CEO dies, then the remaining exercise period under outstanding vested options shall equal the longer of (i) one (1) year following death; or (ii) the remaining portion of the exercise period which was triggered by the employment termination. Such options shall be exercisable by such person or persons who shall have been named as the CEO's beneficiary, or by such persons who have acquired the CEO's rights under the option by will or by the laws of descent and distribution. 10. TERMINATION OF EMPLOYMENT FOR OTHER REASONS. If the CEO's employment shall terminate for any reason other than Retirement, death, Disability, for Cause or a Change in Control (as defined in the Plan), all options held by the CEO which are not vested as of the effective date of such termination shall be forfeited to the Company. In the event of termination for any reason other than Retirement, death, Disability, for Cause or a Change in Control, options which are vested as of such termination shall remain exercisable by Recipient for three (3) months after the effective date of such termination. 11. EMPLOYMENT. This Phantom Stock Option Agreement confers no right upon the CEO with respect to the continuation of employment with the Company, and subject to any contractual rights of CEO, shall not interfere with the right of the Company, or of the CEO, to terminate CEO's employment at any time. 12. ADJUSTMENTS UPON THE OCCURRENCE OF CERTAIN EVENTS. The provisions of this Phantom Stock Option Agreement are subject to adjustments in the event of any merger, reorganization, consolidation, recapitalization, separation, liquidation, stock dividend, split-up, common stock combination or other change in the corporate structure of the Company affecting the common stock of the Company. The Committee provided for in the Plan, may make such adjustments as it may determine to be appropriate and equitable, in its sole discretion, to prevent dilution or enlargement of rights, provided that the number of Phantom Option Shares subject to this Agreement shall always be a whole number. -3- 4 13. CHANGE IN CONTROL. Upon the occurrence of a Change in Control of the Company (as defined in the Plan), the provisions of Section 2, above which require that (i) the CEO shall have completed at least twelve (12) months of continuous employment with the Company and (ii) the right to exercise this option shall accrue in four (4) installments, shall be without force or effect, and any portion of this option which, but for such restrictions, would be exercisable in full, shall become immediately exercisable in full until this option shall expire or terminate. 14. FUNDING. It is specifically recognized by the Company and the CEO that this Agreement is only a general corporate obligation and that the CEO and the CEO's estate or any person who acquired any right to this Agreement by bequest or inheritance or otherwise, must rely upon the general credit of the Company for fulfillment of its obligations under this Agreement. No specific assets of the Company have been set aside or pledged in any way for the performance by the Company of its obligations under this Agreement nor shall any assets be pledged or set aside in any manner in the future to assure the performance by the Company of its obligations under this Agreement in any form in which they cannot be reached by the general creditors of the Company. It is intended that this Agreement shall be unfunded for tax purposes. 15. RESPONSIBILITY FOR WITHHOLDING OF TAXES. The Company will calculate the deductions from the amount of the compensation paid under this Agreement for any taxes required to be withheld by federal, state or local government and will cause them to be withheld. 16. LIMITATION OF RIGHTS. Nothing in this Agreement will be construed: (i) to give the CEO any right with respect to any compensation except under the terms of this Agreement, (ii) to give the CEO or his estate or any person who acquired any right by bequest or inheritance or otherwise any interest or right under this Agreement other than that of an unsecured general creditor of the Company. 17. NONALIENATION OF BENEFITS. No right or benefit provided by this Agreement is transferable. No right or benefit under this Agreement will be subject to anticipation, alienation, sale, assignment, pledge, encumbrance or charge. Any attempt to anticipate, alienate, sale, assign, pledge, encumber or charge the same will be void. No right or benefit under this Agreement will be liable for or subject to any debts, contracts, liabilities or torts of the person entitled to receive the benefit. Should the CEO or the CEO's estate or any person who acquired any benefit by bequest or inheritance or otherwise, become bankrupt or attempt to anticipate, alienate, sell, assign, pledge, encumber or charge the benefit provided by this Agreement, that benefit will, in the sole discretion of the Company, cease. In that event, the Company may hold or apply the benefit or any part of it for the benefit of the CEO or the CEO's estate or any person who acquired any benefit by bequest or inheritance or otherwise, in any manner or in any proportion the Company believes to be proper in its sole discretion, but it is not required to do so. 18. AMENDMENT OR TERMINATION OF THIS AGREEMENT. This Agreement may only be modified or terminated by an instrument in writing and executed by the Company and the CEO. -4- 5 19. SEVERABILITY. If any term, provision, covenant or condition of this Agreement is held to be invalid, void or otherwise unenforceable, the remaining portions of this Agreement will remain in full force and effect and will in no way be affected, impaired or invalidated. 20. NOTICE. Any notice hereunder by the CEO shall be given to the Company in writing and shall be deemed duly given only upon receipt thereof by the Secretary or an Assistant Secretary of the Company at the Company's office at 8700 Tesoro Drive, San Antonio, Texas 78217, or at such other address as the Company may designate by notice to the CEO. Any notice hereunder by the Company to the CEO shall be given in writing at such address as the CEO has on file with the Company. 21. INTERPRETATION AND CONSTRUCTION. The construction and interpretation of this Phantom Stock Option Agreement is vested in the Committee provided for in the Plan, and any construction and interpretation by such Committee shall be final and conclusive, and binding on all parties, including the Company, the CEO and the CEO's heirs, estate and beneficiary. The section headings are for convenience of reference only and shall not be deemed part of, or germane to the interpretation or construction thereof. 22. GOVERNING LAW. This Agreement shall be construed, administered and governed in all respect by the laws of the State of Texas. 23. BINDING EFFECT. This Agreement shall be binding upon the Company, its successors and assigns and the heirs, successors, legal representatives and other persons claiming by, through or under the CEO. TESORO PETROLEUM CORPORATION By: /s/ JAMES C. REED, JR. ---------------------------- JAMES C. REED, JR. Executive Vice President, General Counsel and Secretary /s/ BRUCE A. SMITH ------------------------------- BRUCE A. SMITH -5- EX-21 7 SUBSIDIARIES OF THE REGISTRANT 1 ITEM 14(a)3, EXHIBIT 21 SUBSIDIARIES OF THE REGISTRANT Tesoro Petroleum Corporation is publicly held and has no parent. The subsidiaries listed below are wholly-owned. Small or inactive subsidiaries are omitted from the list below. Such omitted subsidiaries, considered in the aggregate as a single subsidiary, would not constitute a "significant subsidiary" at the end of the year covered by this annual report.
INCORPORATED OR ORGANIZED NAME OF SUBSIDIARY (a) UNDER LAWS OF ----------------------- ------------- Tesoro Alaska Petroleum Company............................................ Delaware Kenai Pipe Line Company................................................. Delaware Tesoro Bolivia Petroleum Company........................................... Texas Tesoro Exploration and Production Company (b).............................. Delaware Tesoro Gas Resources Company, Inc. (b) .................................... Delaware Tesoro E&P Company, L.P. (b)............................................ Delaware Tesoro Marine Services Holding Company..................................... Delaware Tesoro Marine Services, Inc............................................. Delaware Tesoro Northstore Company.................................................. Alaska
- -------------- (a) Where the name of a subsidiary is indented, it is wholly-owned by its immediate parent listed at the margin above it, unless otherwise indicated. (b) Tesoro E&P Company, L.P. is owned 99% by Tesoro Gas Resources Company, Inc. and 1% by Tesoro Exploration and Production Company. EX-23.1 8 CONSENT OF DELOITTE & TOUCHE LLP 1 ITEM 14(a)3, EXHIBIT 23.1 INDEPENDENT AUDITORS' CONSENT Board of Directors and Stockholders Tesoro Petroleum Corporation We consent to the incorporation by reference in Registration Statement No. 333-25379 of Tesoro Petroleum Corporation on Form S-8 of our report dated January 28, 1998, appearing in this Annual Report on Form 10-K of Tesoro Petroleum Corporation for the year ended December 31, 1997. DELOITTE & TOUCHE LLP San Antonio, Texas March 30, 1998 EX-23.2 9 CONSENT OF NETHERLAND, SEWELL & ASSOCIATES, INC. 1 ITEM 14(a)3, EXHIBIT 23.2 CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS We hereby consent to the references to our firm in the Annual Report of Tesoro Petroleum Corporation on Form 10-K for the fiscal year ended December 31, 1997, filed with the Securities and Exchange Commission in Washington, D.C. pursuant to the Securities Exchange Act of 1934. NETHERLAND, SEWELL & ASSOCIATES, INC. By: /s/ FREDERIC D. SEWELL ----------------------------------- Frederic D. Sewell President Dallas, Texas March 25, 1998 EX-27.1 10 FINANCIAL DATA SCHEDULE
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM TESORO PETROLEUM CORPORATION'S FINANCIAL STATEMENTS AS OF AND FOR THE YEAR ENDED DECEMBER 31, 1997, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 YEAR DEC-31-1997 DEC-31-1997 8,352 0 77,655 1,373 87,359 181,835 718,346 304,523 627,808 107,495 115,314 0 0 4,418 328,546 627,808 937,917 943,460 824,991 824,991 46,363 0 6,699 49,120 18,435 30,685 0 0 0 30,685 1.16 1.14
EX-27.2 11 RESTATED FINANCIAL DATA SCHEDULE
5 1,000 YEAR DEC-31-1996 DEC-31-1996 22,796 0 129,528 1,515 74,488 237,343 573,353 256,842 582,587 137,868 79,260 0 0 4,402 299,663 582,587 975,361 1,039,778 854,311 854,311 41,459 0 15,382 115,147 38,347 76,800 0 (2,290) 0 74,510 2.87 2.81 Earnings per share have been restated to comply with SFAS No. 128. Earnings per share is after a net extraordinary loss on extinguishment of debt of $0.09 per basic and diluted share.
EX-27.3 12 RESTATED FINANCIAL DATA SCHEDULE
5 1,000 YEAR DEC-31-1995 DEC-31-1995 13,941 0 79,376 1,842 80,453 182,464 478,880 217,191 519,153 104,935 155,007 0 0 4,130 212,384 519,153 970,172 1,002,883 855,187 855,187 42,620 0 20,902 61,868 4,379 57,489 0 (2,857) 0 54,632 2.22 2.18 Earnings per share have been restated to comply with SFAS No. 128. Earnings per share is after a net extraordinary loss on extinguishment of debt of $0.12 per basic share and $0.11 per diluted share.
-----END PRIVACY-ENHANCED MESSAGE-----