-----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, G9uauMi1c9tvHA48GnV/+ypwUuHvcYSLRG1bIPhIRsl9XJqM1CI2WVhQFNuJ6tD7 QVzf64+CaM89HVT61kBDZg== 0000950129-96-000417.txt : 19960325 0000950129-96-000417.hdr.sgml : 19960325 ACCESSION NUMBER: 0000950129-96-000417 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 8 CONFORMED PERIOD OF REPORT: 19951231 FILED AS OF DATE: 19960322 SROS: NYSE SROS: PSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: TESORO PETROLEUM CORP /NEW/ CENTRAL INDEX KEY: 0000050104 STANDARD INDUSTRIAL CLASSIFICATION: PETROLEUM REFINING [2911] IRS NUMBER: 950862768 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-03473 FILM NUMBER: 96537417 BUSINESS ADDRESS: STREET 1: 8700 TESORO DR CITY: SAN ANTONIO STATE: TX ZIP: 78217 BUSINESS PHONE: 2108288484 10-K 1 TESORO PETROLEUM CORPORATION 12/31/95 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, 1995 OR / / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM ............ TO ............
COMMISSION FILE NUMBER 1-3473 TESORO PETROLEUM CORPORATION (Exact Name of Registrant as Specified in Its Charter) DELAWARE 95-0862768 (State or Other Jurisdiction of (I.R.S. Employer Incorporation or Organization) Identification No.)
8700 TESORO DRIVE, SAN ANTONIO, TEXAS 78217 (Address of Principal Executive Offices) (Zip Code) REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 210-828-8484 --------------------- SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED - --------------------------------------------------- ----------------------------------------- Common Stock, $.16 2/3 par value New York Stock Exchange Pacific Stock Exchange Preferred Stock Purchase Rights New York Stock Exchange Pacific Stock Exchange 12 3/4% Subordinated Debentures due March 15, 2001 New York Stock Exchange 13% Exchange Notes due December 1, 2000 New York 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 March 1, 1996, the aggregate market value of the voting stock held by nonaffiliates of the registrant was approximately $204,974,831 based upon the closing price of its shares on the New York Stock Exchange Composite tape. At March 1, 1996, there were 25,734,991 shares of the registrant's Common Stock outstanding. --------------------- DOCUMENTS INCORPORATED BY REFERENCE
DOCUMENT FORM 10-K PART --------------------------------------- --------------- Proxy Statement for 1996 Annual Meeting Part III
- -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- 2 TESORO PETROLEUM CORPORATION INDEX TO ANNUAL REPORT ON FORM 10-K
PAGE ---- PART I Item 1. BUSINESS..................................................................... 3 Refining and Marketing..................................................... 3 Exploration and Production................................................. 7 Marine Services............................................................ 13 Competition................................................................ 14 Other...................................................................... 14 Government Regulation and Legislation...................................... 15 Employees.................................................................. 18 Executive Officers of the Registrant....................................... 18 Item 2. PROPERTIES................................................................... 20 Item 3. LEGAL PROCEEDINGS............................................................ 20 Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.......................... 23 PART II Item 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS........ 23 Item 6. SELECTED FINANCIAL DATA...................................................... 24 Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS................................................................. 25 Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.................................. 39 Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE................................................................. 73 PART III Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT........................... 73 Item 11. EXECUTIVE COMPENSATION....................................................... 73 Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT............... 73 Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS............................... 73 PART IV Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K............. 73 SIGNATURES.............................................................................. 81
2 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 and marketing, natural gas exploration and production, and marine services. The Company was incorporated in Delaware in 1968 (a successor by merger to a California corporation incorporated in 1939). For financial information relating to industry segments, see Management's Discussion and Analysis of Financial Condition and Results of Operations in Item 7 and Note C of Notes to Consolidated Financial Statements in Item 8. RECENT EVENTS On March 10, 1996, Peter M. Detwiler resigned as a director of the Company in order to devote more time to other business interests. Mr. Detwiler, who joined the Board of Directors in 1967, would not be eligible to stand for reelection at the Company's next annual meeting due to exceeding the policy on term limits under the Company's governance policy. Patrick J. Ward was elected to the Company's Board of Directors on March 11, 1996. Mr. Ward has 47 years of experience in international energy operations with Caltex Petroleum Corporation, where he recently retired as Chairman, President and Chief Executive Officer. During 1995, the Company restructured certain operations in its former Oil Field Supply and Distribution segment by exiting the land-based portion of its petroleum product distribution business and, in February 1996 the Company acquired Coastwide Energy Services, Inc. ("Coastwide") and combined these operations with the Company's remaining oil field supply and distribution operations, forming a Marine Services segment. The Company's Marine Services segment will provide a broad range of products and logistical support services to the offshore drilling and drilling-related businesses operating in the Gulf of Mexico. See "Marine Services" discussed below and Notes B and C of Notes to Consolidated Financial Statements in Item 8. On December 26, 1995, a group of five holders of Tesoro's Common Stock, led by Kevin S. Flannery (the "Flannery Group"), beneficially owning in the aggregate approximately 5.7% of the outstanding shares of Tesoro Common Stock, filed a Form 13D with the Securities and Exchange Commission ("SEC") announcing that they had formed a "group" identified as "The Stockholders' Committee for New Management of Tesoro Petroleum Corporation" (the "Committee"), to seek to acquire control of Tesoro through the replacement of the current Tesoro Board of Directors with persons selected by the Committee. For further information on this matter, see Item 3, Legal Proceedings. 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, in the Pacific Northwest and in certain Far Eastern markets. During 1995, products from the Company's refinery accounted for approximately 65% of such sales, including products received on exchange in the U.S. West Coast market, with the remaining 35% being purchased from other refiners and suppliers. Entering 1996, the Company's purchases from other refiners and suppliers should decline as the Company discontinues its operations in California which is further discussed below. The Company's refinery, which is located in Kenai, 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, heavy oils and residual products. Alaska North Slope ("ANS") and Cook Inlet crude oils are the primary feedstocks for the refinery. To assure the availability of crude oil to the refinery, the Company has a royalty crude oil purchase contract with the State of Alaska ("State") (see "Crude Oil Supply" discussed below). During 1995, the refinery processed approximately 68% ANS crude oil, 26% Cook Inlet crude oil and 6% other 3 4 refinery feedstocks, which yielded refined products consisting of approximately 27% gasoline, 45% middle distillates, 10% heavy oils and 18% residual product. In December 1994, the Company completed the installation of a vacuum unit at the refinery, at a cost of $25 million, which reduces the refinery's yield of residual products by further processing these volumes into higher-valued products. In 1995, the Company implemented initiatives that increased the demand for the refinery's production and improved the refinery's capacity utilization and efficiencies. In this regard, the Company expanded its marketing efforts by branding and rebranding sales outlets in Alaska and the Pacific Northwest and by exporting products to the Russia Far East. CRUDE OIL SUPPLY The refinery is designed to process crude oil with up to 1.0% sulphur content. As such, the refinery can process Cook Inlet, ANS and certain foreign crude oils. ANS Crude Oil. ANS crude oil is a heavy crude oil which contains an average of 1.0% sulphur. In 1995, approximately 68% of the refinery's feedstock was ANS crude oil, of which approximately 37,500 barrels per day were purchased under a royalty crude oil purchase contract with the State, which expired at the end of 1995. The agreement between the Company and the State required the Company to purchase approximately 40,000 barrels per day at the weighted average net-back price reported by the three major North Slope producers for ANS crude oil delivered to the U.S. West Coast. Under this agreement, the Company had the right to sell or exchange up to 20% of the ANS crude oil purchased from the State during 1995. In 1995, the Company renegotiated a new three-year contract with the State covering the period January 1, 1996 through December 31, 1998. The new contract provides for the purchase of approximately the same volumes of ANS royalty crude oil as the previous contract with such crude oil being priced at the weighted average price reported to the State by a major North Slope producer of ANS crude oil as valued at Pump Station No. 1 on the Trans Alaska Pipeline System ("TAPS"). Under the new contract, the Company is required to utilize in its refinery operations volumes equal to at least 80% of the ANS crude oil to be purchased from the State. This contract contains provisions that, under certain conditions, allow the Company to temporarily or permanently reduce its purchase obligation. All ANS crude oil feedstock is delivered to the refinery by tanker through the Kenai Pipe Line Company ("KPL") marine terminal which the Company purchased in early 1995. Cook Inlet Crude Oil. Cook Inlet crude oil, a lighter crude oil that contains an average of .1% sulphur, accounted for approximately 26% of the refinery's feedstock supply in 1995. The Company obtains Cook Inlet crude oil from several producers on the Kenai Peninsula under short-term contracts. Cook Inlet crude oil is delivered by tanker through the Company's KPL terminal or through an existing pipeline to the refinery. Other Supply. In 1995, the Company's refinery obtained approximately 6% of its feedstock supply from other sources. The other supply consisted of heavy atmospheric gas oil ("HAGO") and foreign crude oil. The HAGO feedstock was purchased from a local competitor's refinery and from a U.S. West Coast refinery under short-term contracts. HAGO is a refinery byproduct which generates various light refined products with no residual fuel oil. The foreign crude oil, purchased in spot quantities, is delivered to the refinery by tanker through the KPL marine terminal. The Company evaluates the economic viability of processing foreign crude oil in its refinery and will occasionally purchase spot quantities to supplement its normal crude oil supply. ANS Agreement. In January 1993, the Company entered into an agreement with the State ("ANS Agreement") that settled a contractual dispute concerning the value of ANS royalty crude oil previously sold to the Company. The ANS Agreement provided that $97.1 million was owed to the State by the Company. Under the ANS Agreement, the Company paid the State $10.3 million in January 1993 and 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 at the Company's refinery. For 1995, 1994 and 1993, based on a per barrel throughput charge of 16 cents, the Company's variable payments to the State amounted to $2.9 million, $2.8 million and $2.6 million, respectively. The per barrel charge increases to 24 cents in 1996 and to 30 cents in 1998 with one cent annual incremental increases thereafter through 2001. In January 2002, the Company is 4 5 obligated to pay the State $60 million; provided, however, that such payment may be deferred indefinitely 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 variable monthly payments are secured by a mortgage on the Company's refinery. The Company's obligations under the ANS Agreement and the mortgage are subordinated to current and future senior debt of up to $175 million plus any indebtedness incurred subsequent to the date of the agreement to improve the Company's refinery. For further information concerning the Company's settlement with the State, see Note I of Notes to Consolidated Financial Statements in Item 8. REFINING AND MARKETING ACTIVITIES The following table summarizes the Company's refining and marketing operations for the three years ended December 31, 1995, 1994 and 1993:
YEARS ENDED DECEMBER 31, ---------------------------- 1995 1994 1993 ------ ------ ------ Refinery Throughput (average daily barrels)...................... 50,569 46,032 49,753 ====== ====== ====== Refinery Production (average daily barrels): Gasoline....................................................... 14,298 11,728 12,021 Middle distillates and other................................... 23,182 20,615 21,487 Heavy oils and residual products............................... 14,516 15,118 17,573 ------ ------ ------ Total Refinery Production.............................. 51,996 47,461 51,081 ====== ====== ====== Product Sales (average daily barrels): Gasoline....................................................... 24,526 23,191 22,466 Middle distillates............................................. 37,988 33,256 29,354 Heavy oils and residual products............................... 14,787 14,228 16,945 ------ ------ ------ Total Product Sales.................................... 77,301 70,675 68,765 ====== ====== ====== Product Sales Prices ($/barrel): Gasoline....................................................... $28.21 27.03 27.82 Middle distillates............................................. $24.40 24.47 27.39 Heavy oils and residual products............................... $13.66 10.93 11.19
ALASKA MARKETING Gasoline. With the vacuum unit operational in late 1994, the Company's refinery production of gasoline increased by 22% in 1995. As a result, the Company implemented initiatives to increase the Company's market share of gasoline sales in Alaska. By the end of 1995, the Company had successfully increased its market share to approximately 43% in its geographic market area, from 29% at 1994 year-end, primarily by adding 42 stations to its marketing locations. These additions included the branding and rebranding of 31 stations. The Company distributes gasoline to end users in Alaska, either by retail sales through its 7-Eleven convenience store locations and two other Company operated locations, by wholesale sales through 97 branded and 28 unbranded dealers and jobbers and 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 and operates such stores in 38 locations, 32 of which sell Company-branded gasoline. During 1995, these convenience stores sold an average of 72,000 gallons of gasoline per day. 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. 5 6 Middle Distillates. The Company is a major supplier of commercial jet fuel into the Alaskan marketplace, with all of its production being marketed in Alaska to passenger and cargo airlines. The demand for jet fuel in Alaska currently exceeds the production of all refiners in Alaska, and several marketers, including the Company, import jet fuel into Alaska to meet excess demand. Substantially all of the Company's diesel fuel and other distillate production is sold on a wholesale basis in Alaska primarily for marine and industrial purposes. Generally, the production of diesel fuel by refiners in Alaska is in balance with demand; however, because of the high 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 vacuum unit, which uses residual fuel oil as a feedstock, reduced the refinery's yield of residual product by further processing these volumes into light vacuum gas oil (LVGO), heavy vacuum gas oil (HVGO) and vacuum tower bottoms (VTB). The LVGO is further processed in the 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 a catalytic hydrocracker feedstock, while the VTBs are generally sold on the U.S. West Coast where they are blended with light cycle oil to produce bunker fuel. The vacuum unit has reduced the percentage of production sold as bunker fuel from 32% in 1994 to 18% in 1995. U.S. WEST COAST AND PACIFIC NORTHWEST MARKETING During 1995, the Company conducted domestic wholesale marketing operations, primarily in California, Oregon and Washington with its principal office located in Long Beach, California. These operations sold approximately 29,100 barrels per day of refined products in 1995, of which approximately 18% was received from major oil companies in exchange for products from the Company's refinery, approximately 12% was received directly from the refinery and 70% was purchased from other suppliers. In 1995, the Company expanded its presence in the Pacific Northwest by branding ten stations in five cities in Washington and Oregon. During 1995, the Company sold refined products in the bulk market and through 27 terminal facilities, of which four are owned by the Company. Due to market conditions, the Company is currently in the process of discontinuing its operations in California and intends to sell three of its Company-owned facilities. The Company will continue to sell refined products in the Pacific Northwest through branded stations in addition to six terminal facilities, one of which is owned by the Company. TRANSPORTATION The Company charters an American flag vessel, the Potomac Trader, whose primary use is to transport ANS crude oil from the TAPS terminal at Valdez, Alaska to the Company's refinery. The Company charters another American flag vessel, the Chesapeake Trader, which is used primarily to transport heavy oils and residual product to the U.S. West Coast and occasionally to transport feedstocks to the Company's refinery. The Potomac Trader and Chesapeake Trader are chartered under five-year agreements expiring in 2000. Also, in 1995, the Company chartered a Russian flag vessel, the Igrim, under a six-month agreement with three six-month renewal options. In late 1995, the Company exercised its right to renew the charter for six months. The Igrim is used primarily to transport refined products from the Company's refinery to the Far East. 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 Company's 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 1995, the pipeline transported an average of approximately 22,100 barrels of petroleum products per day, all of which were transported for the Company. In March 1995, the Company acquired all of the outstanding stock of Kenai Pipe Line Company ("KPL"), a common carrier pipeline and dock facility, for $3 million. By owning this facility, the Company is 6 7 assured of uninterrupted use of the dock and pipeline for unloading crude oil feedstocks and loading product inventory on tankers and barges. During 1995, KPL transported approximately 49,900 barrels of crude oil per day and 33,700 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." EXPLORATION AND PRODUCTION OVERVIEW The Company's exploration and production strategy is to use its proven experience and technology to capitalize on the underexplored formations of the Wilcox Trend in South Texas and of the Chaco Basin in Bolivia. During 1995, the Company's U.S. program began its initial shift from the Bob West Field, an almost fully developed field, to other portions of the Wilcox Trend in South Texas. Within its target region, the Company will primarily pursue prospects in underexplored zones similar to those in the Bob West Field, from 10,000 feet to 15,000 feet deep. The Company is building its prospect inventory from an 8,500-mile seismic database and an extensive well log library. The Company currently has 15 South Texas prospects in inventory encompassing 20,000 gross (8,000 net) acres. Since 1976, the Company has operated two concessions in Bolivia and, since that date, discovered six fields. Three of these Bolivian fields are producing gas at market restricted rates, two fields are currently shut-in and one field has been discovered subsequent to year-end. UNITED STATES Bob West Field. During 1995, the Company's U.S. operations were concentrated primarily in the Bob West Field, a field that was discovered by the Company in 1990. The Bob West Field is located in the southern part of the Wilcox Trend in Starr and Zapata Counties, Texas. 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. Continued successful development of the Bob West Field led to the completion of 17 gross development wells during 1995, bringing the cumulative number of gross producing wells in the field in which the Company participated to 63. Three additional wells were being drilled at year-end and seven additional well locations, the majority of which are expected to be drilled during 1996, have been selected for further development of this 4,000-acre field. 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. These units do not include acreage related to the Company's natural gas sales contract with Tennessee Gas Pipeline Company, which as discussed in Note N of Notes to Consolidated Financial Statements in Item 8, is the subject of current litigation. Also 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 billion cubic feet ("Bcf"), or 40%, of the Company's total net proved domestic reserves at the time of the sale. Through the date of the sale, natural gas production from the interests sold had contributed approximately $11 million to revenues and $4 million to operating profit of the Company's Exploration and Production segment for 1995. Consideration for the sale was $74 million, which was adjusted on a preliminary basis 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, which is subject to final post-closing adjustments, was used to redeem $34.6 million of the Company's outstanding 12 3/4% Subordinated Debentures, reduce borrowing under the Company's Revolving Credit Facility and improve corporate liquidity. The Company does not expect any final post-closing adjustments to be material. 7 8 After the sale of certain interests, at December 31, 1995, the Company owns interests in 49 gross wells, or approximately 100 Bcf of net proved reserves, in the Bob West Field. The Company's revenue interests in the field range from 28% to 57% and its working interests range from 33% to 70%. In addition, the Company owns a 70% interest in the field's central gas processing facility which has a capacity of 350 million cubic feet ("Mmcf") per day. During 1995, the Company's net production from the Bob West Field wells averaged approximately 113 Mmcf per day. Excluding the production from the 14 wells that were sold during September 1995, the Company's net production from the field averaged 89 Mmcf per day. Other Areas of South Texas. In addition to the continued development of the Bob West Field, during 1995 the Company also participated in the drilling of nine exploratory wells in other portions of the Wilcox Trend in South Texas, five of which were successfully completed as producing wells. One of the wells, the Tesoro Longoria #1 exploratory well in Webb County of South Texas, marked the discovery of a new natural gas field (the "Tea Jay Field"). Tesoro serves as operator of this well which is currently flowing at a gross rate of 5 Mmcf per day of natural gas. At year-end 1995, the Company held a 45% working interest in the Tea Jay Field and has subsequently acquired an additional 4% working interest. As a result of the initial exploratory well, the Company added approximately 4 Bcf to its net proved reserves in 1995. A seismic program has been completed at the 2,400-acre Tea Jay Field to assist in identifying future drilling sites. The Tesoro Longoria #2 delineation well, which began drilling in February 1996, incurred a blowout on March 15, 1996 before reaching target depth. The Company is currently in the process of determining whether the well can be salvaged or whether it will have to drill a replacement well. The Company does not anticipate any significant adverse economic impact from the well blowout. The Company is uncertain as to the future impact of this field upon its operations. Reserves. The following table shows the estimated proved reserves for each of the Company's U.S. fields as of December 31, 1995, based on evaluations prepared by Netherland, Sewell & Associates, Inc.:
PRESENT NET NET SOUTH VALUE OF PROVED PROVED GROSS TEXAS PROVED GAS OIL PRODUCING FIELD NAME COUNTY OPERATORS RESERVES(1) RESERVES RESERVES WELLS - ----------- ------ -------------------------- ------------- -------- ---------- --------- ($ THOUSANDS) (MMCF) (THOUSANDS OF BARRELS) Bob West Starr Coastal Oil & Gas Corp. and $ 160,901(2) 100,014 -- 49 Sanchez-O'Brien Oil & Gas Tea Jay Webb Tesoro 4,913 4,248 8 1 Lopeno Zapata Mustang Oil & Gas Corp. 2,920 2,111 -- 3 Other 5 4 -- 4 --------- ------- ---- ----- $ 168,739 106,377 8 57 ========== ======= ==== =====
- --------------- (1) Represents the discounted future net cash flows before income taxes. See Note Q of Notes to Consolidated Financial Statements in Item 8 for additional information regarding the Company's proved reserves and standardized measure. (2) See Legal Proceedings in Item 3 and Notes N and Q of Notes to Consolidated Financial Statements in Item 8 regarding litigation concerning the Tennessee Gas Contract. Based on the Contract Price, the discounted future net cash flows before income taxes at December 31, 1995 was $168.7 million, compared with $120.7 million at spot market prices. 8 9 Reserve Replacement. In 1995, the Company's U.S. proved reserve additions, including revisions, totaled 96 Bcf, replacing 230% of its U.S. production of 42 Bcf. Excluding revisions, 50 Bcf were added for a 120% U.S. replacement rate. These reserve additions were achieved at a low cost, bringing the Company's three-year average finding cost to $.70 per thousand cubic feet equivalent ("Mcfe"), as illustrated by the following table:
YEARS ENDED DECEMBER 31, ------------------------------- THREE YEAR 1995 1994 1993 TOTAL ------- ------- ------- ---------- Expenditures (in thousands)............... $49,446 $60,379 $28,640 $138,465 Proved Natural Gas Reserves Added, including Revisions (Mmcfe)............. 96,494 39,487 60,595 196,576 Costs per Mcfe............................ $ .51 $ 1.53 $ .47 $ .70
These additions were realized with an 85% domestic drilling success rate during 1995, reflecting a 100% success rate on the 17 development wells and a 56% success rate on the nine exploratory wells. Tennessee Gas Contract. The Company has interests in two 352-acre producing units in the Bob West Field that are subject to a Gas Purchase and Sales Agreement (the "Tennessee Gas Contract") with Tennessee Gas Pipeline Company ("Tennessee Gas") expiring on January 31, 1999. The Tennessee Gas Contract requires Tennessee Gas to purchase gas from the two producing units pursuant to a contract price ("Contract Price"). During the month of December 1995, the Contract Price was in excess of $8.60 per Mcf which was substantially above the average spot market price of $1.84 per Mcf. The Tennessee Gas Contract is presently the subject of litigation. In 1995, approximately 17% of the Company's total U.S. production was sold under the Tennessee Gas Contract representing 57% of the Company's U.S. natural gas revenues for the year. See Legal Proceedings in Item 3 and Notes N and Q of Notes to Consolidated Financial Statements in Item 8. 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 to common carrier pipeline facilities. In addition, the Company owns a 50% interest in the twenty-inch diameter Starr-Zapata natural gas pipeline that was constructed during 1994 to transport gas 26 miles from the Starr County Gathering System to a market hub at Fandango, Texas. The Company does not operate either facility. During 1995, the gross average daily throughput was 223 Mmcf per day and 178 Mmcf per day for the Starr County Gathering System and the Starr-Zapata pipeline, respectively, of which 113 Mmcf per day and 93 Mmcf per day, respectively, were for the Company's production. The Starr County Gathering System receives a transportation fee of $.06 per Mcf and the Starr-Zapata Pipeline receives a fee of $.07 per Mcf for volumes transported. For further information regarding the Company's U.S. operations, see Notes B, C and Q of Notes to Consolidated Financial Statements in Item 8. 9 10 U.S. Operating Statistics
YEARS ENDED DECEMBER 31, -------------------------------- 1995 1994 1993 -------- ------- ------- Net Natural Gas Production (average daily Mcf)............... 114,490 83,796 38,767 Average Natural Gas Sales Price ($/Mcf)(1): Spot market................................................ $ 1.34 1.48 1.89 Tennessee Gas Contract(2).................................. $ 8.41 7.93 7.51 Weighted average........................................... $ 2.57 2.86 3.43 Average Operating Expenses ($/Mcf): Lease operating expenses................................... $ .11 .11 .12 Severance taxes -- spot market............................. .09 .09 .11 -------- ------ ------ Total production costs -- spot market(1)........... .20 .20 .23 Administrative support and other........................... .07 .08 .09 -------- ------ ------ Total operating expenses -- spot market............ $ .27 .28 .32 ======== ====== ====== Severance taxes -- Tennessee Gas Contract.................. $ 0.58 0.52 0.50 Total weighted average production costs(1)................. $ 0.29 0.29 0.34 Total weighted average operating expenses.................. $ 0.35 0.37 0.42 Depletion Rate ($/Mcf)....................................... $ .69 .79 .78 Exploratory Wells Drilled: Productive -- Gross........................................ 5.0 3.0 1.0 Productive -- Net.......................................... 1.5 1.5 .4 Dry holes -- Gross......................................... 4.0 2.0 1.0 Dry holes -- Net........................................... 2.1 1.1 .5 Development Wells Drilled: Productive -- Gross........................................ 17.0 20.0 15.0 Productive -- Net.......................................... 9.7 11.1 7.9 Dry holes -- Gross......................................... -- 1.0 -- Dry holes -- Net........................................... -- .4 --
DECEMBER 31, 1995 -------------- GROSS NET ----- ---- Productive Gas Wells(3)....................................................... 57 28.3 Acreage (in thousands): Developed................................................................... 5 2 Undeveloped................................................................. 19 7
- --------------- (1) Amounts previously reported have been restated for certain reclassifications between revenues and operating expenses. (2) See Item 3, Legal Proceedings, and Notes N and Q of Notes to Consolidated Financial Statements in Item 8 regarding litigation concerning the Tennessee Gas Contract. (3) Included in total productive wells is 1 gross (.6 net) well with multiple completions. At December 31, 1995, the Company was participating in the drilling of 3 gross (1.0 net) wells. BOLIVIA The Company's Bolivian exploration and production operations are located in southern Bolivia near the border of Argentina, where the Company has discovered six fields since 1976. With estimated net proved natural gas reserves of 98 Bcfe at December 31, 1995 and average gas production of 18.7 Mmcf per day in 1995, Tesoro is one of the largest independent producers of natural gas in Bolivia. The Company is the 10 11 operator of a joint venture that holds two Contracts of Operation with Yacimientos Petroliferos Fiscales Bolivianos ("YPFB"), the Bolivian state-owned oil and gas company. Block 18. The Company has a 75% interest in a Contract of Operation, which expires in 2007, covering approximately 93,000 acres in Block 18. The Company has drilled five exploratory wells and 12 development wells within three separate fields in Block 18. During 1995, the Company's net production from these fields averaged 18.7 Mmcf of gas per day and 567 barrels of condensate per day. The Company and its joint venture participant are entitled to receive a quantity of hydrocarbons equal to 40% of the total production, net of Bolivian taxes and royalties on production, which are payable in kind. The Company is currently selling all of its natural gas production from the La Vertiente, Escondido and Taiguati Fields in Block 18 to YPFB which in turn sells the natural gas to Yacimientos Petroliferos Fiscales, S.A. ("YPF"), a publicly-held company based in Argentina. During 1994, the contract between YPFB and YPF was extended through March 31, 1997, maintaining approximately the same volumes as the previous contract. Currently, the Company is selling its natural gas production to YPFB based on the volume and pricing terms in the contract between YPFB and YPF. Block 20. The Company has a 72.6% interest in a Contract of Operation, which expires in 2008, covering approximately 1.2 million acres in Block 20. The Company and its joint venture participant are entitled to receive a quantity of hydrocarbons equal to 50% of the total production, net of Bolivian taxes and royalties on production, which are payable in kind. The development of Block 20 is currently limited by a lack of access to major gas-consuming markets, which is further discussed below. Prior to 1995, the Company discovered the Los Suris Field with two wells that are shut-in pending the approval by the Government of Bolivia of a commercialization agreement. During 1995, the Company discovered the Palo Marcado Field by completing a discovery well that is also shut in. The Palo Marcado well was the third well of a five-well exploratory program that was approved by YPFB and the Government of Bolivia. The fourth well was drilling at year-end 1995 on the Ibibobo prospect. After completion of the five-well exploratory program in July 1996, the existing Contract of Operation provides that YPFB will select inactive parcels to be relinquished from the 1.2 million acres currently under contract in Block 20 with the Company retaining only its producing fields and indicated discoveries. Reserves. The table below shows the estimated proved reserves for each of the Company's Bolivian fields as of December 31, 1995, based on evaluations prepared by Netherland, Sewell & Associates, Inc. These evaluations assume that the Company's access to markets is limited to current sales rates through the termination dates of the existing Contracts of Operation (see "Proposed Bolivian Hydrocarbons Law" and "Access to New Markets" discussed below). Each of the following fields is operated by the Company:
PRESENT NET NET NUMBER OF GROSS WELLS VALUE OF PROVED PROVED ------------------------------ CONTRACT OF PROVED GAS OIL PRODUCING SHUT-IN WELLS IN OPERATION FIELD RESERVES(1) RESERVES RESERVES WELLS WELLS PROGRESS - ------------ ----------------- ------------- -------- ---------- --------- ------- -------- ($ THOUSANDS) (MMCF) (THOUSANDS OF BARRELS) Block 18 Escondido $26,863 45,020 869 3 2 -- La Vertiente 13,910 16,646 406 5 -- -- Taiguati 681 833 16 1 -- -- Block 20 Los Suris 7,272 25,897 305 -- 2 -- Palo Marcado(2) -- -- -- -- 1 -- Ibibobo(3) -- -- -- -- -- 1 ---------- ------ -------- ----- ---- ---- $48,726 88,396 1,596 9 5 1 ========== ====== ======== ===== ==== ====
- --------------- (1) Represents the discounted future net cash flows before income taxes. See Note Q of Notes to Consolidated Financial Statements in Item 8 for additional information regarding the Company's proved reserves and standardized measure. 11 12 (2) The Palo Marcado discovery is not counted in the Company's proved reserves at year-end due to current limitations on the Company's access to markets. See "Proposed Bolivian Hydrocarbons Law" and "Access to New Markets" discussed below. (3) The Ibibobo X-2 was completed subsequent to year-end 1995. Proposed Bolivian Hydrocarbons Law. On February 14, 1996, the President of Bolivia submitted to the Bolivian Congress proposed legislation that would, if enacted, significantly impact the Company's operations in Bolivia. Among other matters, the proposed legislation would grant the Company the option to convert its Contracts of Operation to new Shared Risk Contracts or to remain under the old contract terms. If converted, the new Shared Risk Contracts would include extended contract termination dates, more favorable acreage relinquishment terms, and a revised fiscal regime of taxes and tariffs. The new contract terms could extend the Company's contracts on Block 18 and Block 20 to 2017 and 2029 from their current expiration dates of 2007 and 2008, respectively. This could result in an immediate increase of up to 35% in the Company's proved Bolivian reserves, which are currently limited by the contract termination dates. In addition to retaining the Company's producing fields and indicated discoveries, the new acreage relinquishment terms could allow the Company to retain approximately two-thirds of the remaining unexplored Block 20 acreage, subject to exploration drilling obligations to be specified by the Bolivian government. The Company is currently assessing all aspects of this proposed legislation. Access To New Markets. During 1994, feasibility studies proceeded for several pipeline projects to new markets in Brazil, Chile and Paraguay. In August 1994, the governments of Brazil and Bolivia announced an extension of their previous agreement to jointly construct a pipeline from Rio Grande in central Bolivia to the industrial area along the Atlantic seaboard of Brazil. Both YPFB and Petrobras, the Brazilian state-owned petroleum company, have selected natural gas transmission industry partners for their respective portions of this project. The proposed pipeline to Brazil, with a capacity of 1 Bcf per day, is currently expected to begin construction in 1997 and is expected to be operational by early 1999. The planned capacity of the pipeline would ultimately increase the Bolivian natural gas export capacity to six times current levels. The Company currently supplies over 20% of the Bolivian natural gas export volumes. Details of the proposed pipeline to Brazil are in the process of being finalized. The Company is assessing how the proposed pipeline will impact the demand for the Company's gas or the ability of the Company to market its gas. For further information regarding the Company's Bolivian operations, see Notes C and Q of Notes to Consolidated Financial Statements in Item 8. 12 13 Bolivia Operating Statistics
YEARS ENDED DECEMBER 31, ----------------------------- 1995 1994 1993 ------- ------ ------ Net Production(1): Natural gas (average daily Mcf)............................... 18,650 22,082 19,232 Condensate (average barrels per day).......................... 567 733 663 Average Sales Price: Natural gas ($/Mcf)........................................... $ 1.28 1.20 1.22 Condensate ($/barrel)......................................... $ 14.39 13.28 14.26 Average Operating Expenses ($/net equivalent Mcf): Production costs.............................................. $ .07 .06 .14 Value-added taxes............................................. .06 .10 .09 Administrative support and other.............................. .35 .25 .27 ------- ------ ------ Total Operating Expenses.............................. $ .48 .41 .50 ======= ====== ====== Depletion Rate ($/net equivalent Mcf)........................... $ .03 -- -- Exploratory Wells Drilled: Productive -- Gross........................................... 1.0 1.0 -- Productive -- Net............................................. .7 .7 -- Dry Holes -- Gross............................................ -- 1.0 -- Dry Holes -- Net.............................................. -- .7 --
DECEMBER 31, 1995 -------------- GROSS NET ----- ---- Productive Gas Wells(2)...................................................... 14 10.4 Acreage (in thousands): Developed.................................................................. 38 29 Undeveloped................................................................ 1,210 880
- --------------- (1) Represents the Company's net production before Bolivian taxes, which are payable in-kind. (2) Included in total productive wells are 8 gross (6.0 net) wells with multiple completions. At December 31, 1995 the Company was participating in the drilling of 1 gross (.7 net) well. MARINE SERVICES (FORMERLY OIL FIELD SUPPLY AND DISTRIBUTION) In 1995, the Company restructured certain operations in its former Oil Field Supply and Distribution segment by exiting the land-based portion of its petroleum product distribution business, reducing the number of Company sites to 14 terminals, primarily marine-based, at year-end. These operations, which are located at various sites along the Texas and Louisiana Gulf Coast, sold lubricants, fuels and specialty petroleum products primarily to onshore and offshore drilling contractors. These products are used to power and lubricate machinery on drilling and production locations. The Company also provided products for marine, commercial and industrial applications. In 1995, sales of refined products, primarily diesel fuel, amounted to approximately 7,300 barrels per day from the Company's petroleum products distribution business. In February 1996, the Company purchased 100% of the outstanding capital stock of Coastwide Energy Services, Inc. ("Coastwide"). Coastwide is primarily a provider of services and a wholesale distributor of diesel fuel and lubricants to the offshore drilling industry in the Gulf of Mexico. The Company will combine its remaining petroleum distribution operations with Coastwide, forming a Marine Services segment. As a combined operation, the Marine Services segment will consist of 20 terminals, primarily marine-based, along the Texas and Louisiana Gulf Coast and will provide a broad range of products and logistical support services to the offshore industries operating in the Gulf of Mexico. Customers include companies engaged in oil and 13 14 gas exploration and production and seismic evaluation, as well as offshore construction and other drilling-related businesses. See Notes B and C of Notes to Consolidated Financial Statements in Item 8. COMPETITION The oil and gas industry is highly competitive in all phases, including the refining and marketing of crude oil and petroleum products and the search for and development of oil and gas reserves. The industry also competes with other industries that supply the energy and fuel requirements of industrial, commercial, individual and other consumers. The Company competes with a substantial number of major integrated oil companies and other companies having materially greater financial and other resources. These competitors have a greater ability to bear the economic risks inherent in all phases of the industry. In addition, unlike the Company, many competitors also produce large volumes of crude oil that may 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 to the United States, thereby further increasing competition in the domestic natural gas market. The refining and marketing businesses are highly competitive, with price being the principal factor in competition. In the refining market, the Company's refinery competes primarily with three other refineries in Alaska and, to a lesser extent, refineries on the U.S. West Coast. Given the refinery's proximity to the Alaskan market, the Company believes it enjoys a cost advantage in that market versus refineries on the U.S. West Coast. However, there is no assurance that the Company's cost advantage can be maintained. The Company's refining competition in Alaska consists of a refinery situated near Fairbanks owned by MAPCO, Inc. and two refineries situated near Valdez and Fairbanks owned by Petro Star Inc. The Company estimates that such other refineries have a combined capacity to process approximately 176,000 barrels per day of crude oil. ANS crude oil is the only feedstock used in these competing refineries. After processing the crude oil and removing the lighter-end products, which 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 product. The Company's refinery is not directly connected to the TAPS, and the Company, therefore, cannot return its residual product to the TAPS. In general, the competing refineries in Alaska do not have the same downstream capabilities that the Company currently possesses. The Company estimates that its refinery has the capacity to produce approximately twice the volume of light products per barrel of ANS crude oil that any of the competing refineries is currently able to produce. The Company's marketing business in Alaska is segmented by product line. The Company believes it is the largest producer and distributor of gasoline in Alaska, with the largest network of branded and unbranded dealers and jobbers. The Company is 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. Jet fuel sales are concentrated in Anchorage, where the Company is one of two principal suppliers to, and the only supplier with a direct pipeline into, the Anchorage International Airport, which is a major hub for air cargo traffic to the Far East. Diesel fuel is sold primarily on a wholesale basis. The Company's U.S. West Coast and Pacific Northwest marketing business is primarily a distribution business selling to independent dealers and jobbers outside major urban areas. The Company competes against independent marketing companies and, to a lesser extent, integrated oil companies when engaging in these marketing operations. OTHER 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 14 15 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 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 natural gas wellhead pricing, sales, certificate and abandonment regulation of first sales by the FERC 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 natural gas. Since the latter part of 1985, through its Order Nos. 436, 500 and 636, 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. A related effort has been made with respect to intrastate pipeline operations pursuant to the FERC's authority under Section 311 of the NGPA, under which the FERC establishes rules by which intrastate pipelines may participate in certain interstate activities without becoming subject to full NGA jurisdiction. 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 FERC's latest action in this area, Order No. 636, issued April 8, 1992, reflected the FERC's finding that under the current regulatory structure, interstate pipelines and other gas merchants, including producers, do not compete on an equal basis. The FERC asserted that Order No. 636 was designed to equalize that marketplace. This equalization process is being implemented through negotiated settlements in individual pipeline service restructuring proceedings, designed specifically to "unbundle" those services (e.g., gathering, transportation, sales and storage) provided by many interstate pipelines so that producers of natural gas may secure services from the most economical source, whether interstate pipelines or other parties. In many instances, the result of the FERC initiatives has been to substantially reduce or bring 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. The FERC has issued final orders in all of the individual pipeline restructuring proceedings and all of the interstate pipelines are now operating under new open access tariffs. Although Order No. 636 does not regulate gas producers, such as the Company, the FERC has stated that Order No. 636 is 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 under Order No. 636 will have on the Company and its gas sales efforts. In addition, numerous petitions seeking judicial review of Order Nos. 636, 636A and 636B and seeking review of the FERC's orders approving open access tariffs for the individual pipelines have already been filed. Because the restructuring requirements that emerge from this lengthy process may be significantly different from those of Order No. 636 as originally promulgated, it is not possible to predict what effect, if any, the final rule resulting from Order No. 636 will have on the Company. The Company does not believe that it will be affected by any action taken with respect to Order No. 636 any differently than other gas producers and marketers with which it competes. In late 1993, the FERC initiated a proceeding seeking industry-wide comments about its role in regulating natural gas gathering performed by interstate pipelines or their affiliates. In 1994, the FERC granted a number of interstate pipeline applications to abandon certificated gathering facilities to non-jurisdictional entities. The rates charged by these entities, which may or may not be affiliated with the interstate pipeline, are no longer regulated by the FERC. Under the individual orders, gathering services must 15 16 be continued to existing customers and be provided in an open-access and non-discriminatory manner. These orders are now subject to rehearing before the FERC and numerous parties will likely seek judicial review. 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. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue indefinitely into the future. 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 (the "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. At this time, the Company cannot estimate the cost of the new standards imposed by the EPA or what technologies or changes in processes the Company may have to install or undertake to achieve compliance with the applicable new requirements. The Company's refinery as well as some other Company facilities will require submission of an application for a Clean Air Act Amendment Title V permit during 1996 and 1997. When issued, although specifics are still undetermined, the amended permit will involve stricter monitoring requirements and additional equipment. The Company believes it can comply with these new requirements without adversely affecting operations. The passage of the Federal Clean Air Act Amendments of 1990 prompted adoption of regulations by the State 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. On October 21, 1993, the United States Congress granted the State one additional year of exemption from requiring the use of oxygenated gasoline. In addition, the EPA has been directed to conduct additional studies of potential health effects of oxygenated fuel in Alaska. In the fall of 1994, the State mandated the use of oxygenated fuels containing ethanol in the Anchorage area, from January 1, through February 28, 1995. This was a shortened period due to time constraints faced by gasoline sellers in transporting ethanol to Alaska, and in making the necessary modifications to terminal facilities for blending of the products. In following years, the period for use of oxygenated gasoline in Anchorage will be November 1, through the last day of February of the succeeding year. 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. The EPA issued its final notice on March 22, 1994 approving an extension for the State until 16 17 October 1, 1996. In December 1995, the State submitted an additional application for a permanent waiver. The EPA has not acted on the State's December 1995 application for a permanent waiver. 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. The Company estimates that such sales accounted for less than 1% of its refined product sales in Alaska during 1995. 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 a tanker to transport crude oil from the Valdez, Alaska pipeline terminal through Prince William Sound and Cook Inlet to its 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 50,000 barrels for a tanker carrying fewer than 500,000 barrels of crude oil or equal to 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 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. Current State regulations in Alaska require installation of dike liners in secondary containment systems for petroleum storage tanks by January 1997. This requirement affects all storage tanks. New storage tanks built after 1992 must have such liners and older tanks must be retrofitted and have liners installed. The Company expects the deadline for this work to be extended and possibly changed to lessen its financial impact. However, if such changes do not occur, expenditures in the range of $8 million starting in 1996 will be required to bring the Company's tanks into compliance. 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 within the State of Alaska. The Company continues to monitor, test and make physical improvements in its current operations which result in a cleaner environment. The Company may be required to make significant expenditures for removal or upgrading of underground storage tanks at several of its current and former service station locations by December 22, 1998; however, the Company does not expect to make any material capital expenditures for such purposes during 1996 and does not expect that such expenditures subsequent to 1996 will have a material adverse effect on the financial condition of the Company. Environmental Expenditures. The Company's capital expenditures for environmental control purposes amounted to approximately $1 million during 1995. The Company anticipates that it will incur capital 17 18 expenditures for such purposes in 1996 of approximately $3 million, primarily for the removal and upgrading of underground storage tanks, and starting in 1996 approximately $8 million for the installation of dike liners; however, the Company is applying for an alternate compliance schedule, allowed for under the Alaska regulations, regarding dike liner installation at the Company's Alaska facilities. This alternate schedule, if granted, will allow the Company additional time to assess an alternate remedy to the requirement, under Alaska environmental regulations. There can be no assurance that an alternate schedule will be granted. For further information regarding environmental matters, see "Legal Proceedings" in Item 3 and "Environmental Controls" and "Underground Storage Tanks" discussed above. BOLIVIA The Company's operations in Bolivia are subject to the Bolivian General Law of Hydrocarbons and various other laws and regulations. The General Law of Hydrocarbons imposes certain limitations on the Company's ability to conduct its operations in Bolivia. In the Company's opinion, neither the General Law of Hydrocarbons nor other limitations currently imposed by Bolivian laws, regulations and practices will have a material adverse effect upon its Bolivian operations. The Company is subject to Bolivian taxation at the rate of 30% of the gross production of hydrocarbons at the wellhead, which is retained and paid by YPFB for the Company's account. In 1987, the Bolivian General Corporate Income Tax Law was replaced by a tax system, including a value-added tax, which is not imposed on net income. As a result, it is uncertain whether the Company can treat the Bolivian hydrocarbons tax as creditable in the United States for federal income tax purposes. In December 1994, Bolivia modified its 1987 tax system, and reintroduced a tax on net income. Until such time as regulations are issued, it is unclear whether the Company can treat the 30% gross production taxes as creditable for U.S. tax purposes. For information on proposed legislation regarding a Bolivian hydrocarbons law, see "Exploration and Production -- Bolivia" discussed above. EMPLOYEES At December 31, 1995, the Company employed approximately 840 persons, of which approximately 35 were located in foreign countries. None of the Company's employees are represented by a union for collective bargaining purposes. The Company considers its relations with its employees to be satisfactory. 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 March 1, 1996.
POSITION NAME AGE POSITION HELD SINCE - ----------------------------- --- ------------------------------------------ --------------- Bruce A. Smith............... 52 President and Chief Executive Officer September 1995 James C. Reed, Jr............ 51 Executive Vice President, General Counsel September 1995 and Secretary Gaylon H. Simmons............ 56 Executive Vice President September 1993 William T. Van Kleef......... 44 Senior Vice President and Chief Financial September 1995 Officer Don E. Beere................. 55 Vice President, Controller February 1992 Thomas E. Reardon............ 49 Vice President, Human Resources and September 1995 Environmental Gregory A. Wright............ 46 Vice President, Corporate Communications September 1995 and Treasurer
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 18 19 the corresponding meeting of the Board in the next year or until a successor shall have been elected or shall have qualified. The business experience of the Company's executive officers for the past five years is described below. Positions, unless otherwise specified, are with the Company. Bruce A. Smith............. President and Chief Executive Officer since September 1995. Executive Vice President, Chief Financial Officer and Chief Operating Officer from July 1995 through September 1995. Executive Vice President responsible for Exploration and Production Operations and Chief Financial Officer from September 1993 to July 1995. Vice President and Chief Financial Officer from September 1992 to September 1993. Vice President and Treasurer of Valero Energy Corporation from 1986 to 1992. James C. Reed, Jr.......... Executive Vice President, General Counsel and Secretary since September 1995. Senior Vice President, General Counsel and Secretary from August 1994 to September 1995. Vice President, General Counsel and Secretary from September 1993 to August 1994. Vice President, Secretary from December 1992 to September 1993. Vice President, Secretary of Tesoro Petroleum Companies, Inc., from February 1992 to December 1992. Vice President, Assistant Secretary of Tesoro Petroleum Companies, Inc., from 1990 to 1992. Gaylon H. Simmons.......... Executive Vice President responsible for Refining, Marketing and Crude Supply Operations since September 1993. Senior Vice President, Refining, Marketing and Crude Supply from January 1993 to September 1993. President and Chief Executive Officer of Simmons Sirvey Group, Inc. from 1991 to December 1992. President and Chief Executive Officer of Permian Corporation from 1989 to 1991. William T. Van Kleef....... Senior Vice President and Chief Financial Officer since September 1995. Vice President, Treasurer from March 1993 to September 1995. Financial Consultant from January 1992 to February 1993. Consultant to Parker & Parsley (successor to the assets and operations of Damson Oil Corporation and its affiliates) from February 1991 to December 1991. Vice President and Chief Financial Officer of Damson Oil Corporation from 1986 to 1991. Don E. Beere............... Vice President, Controller since February 1992. Vice President, Internal Audit and Management Systems of Tesoro Petroleum Companies, Inc. from 1990 to 1992. Director, Internal Audit and Management Systems from 1989 to 1990. Thomas E. Reardon.......... Vice President, Human Resources and Environmental since September 1995. Vice President, Human Resources and Environmental Services of Tesoro Petroleum Companies, Inc. 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, Corporate Communications and Treasurer since September 1995. Vice President, Corporate Communications from February 1995 to September 1995. Vice President, Corporate Communications of Tesoro Petroleum Companies, Inc. 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. Vice President, Investor Relations of Valero Energy Corporation from 1989 to 1992. 19 20 ITEM 2. PROPERTIES See information appearing under Item 1, Business herein and Notes B, C and Q of Notes to Consolidated Financial Statements in Item 8. ITEM 3. LEGAL PROCEEDINGS Gas Purchase and Sales Contract. The Company is selling a portion of the gas produced from its Bob West Field to Tennessee Gas Pipeline Company ("Tennessee Gas") under a Gas Purchase and Sales Agreement ("Tennessee Gas Contract") which provides that the price of gas shall be the maximum price as calculated in accordance with Section 102(b)(2) ("Contract Price") of the Natural Gas Policy Act of 1978 ("NGPA"). In August 1990, Tennessee Gas filed suit against the Company in the District Court of Bexar County, Texas, alleging that the Tennessee Gas Contract is not applicable to the Company's properties and that the gas sales price should be the price calculated under the provisions of Section 101 of the NGPA rather than the Contract Price. During the month of December 1995, the Contract Price was in excess of $8.60 per Mcf and the average spot market price was $1.84 per Mcf. For the year ended December 31, 1995, approximately 17% of the Company's net U.S. natural gas production was sold under the Tennessee Gas Contract. Tennessee Gas also claimed that the contract should be considered an "output contract" under Section 2.306 of the Texas Uniform Commercial Code ("UCC") and that the increases in volumes tendered under the contract exceeded those allowable for an output contract. The District Court judge returned a verdict in favor of the Company on all issues. On appeal by Tennessee Gas, the Court of Appeals for the Fourth Supreme Judicial District of Texas affirmed the validity of the Tennessee Gas Contract as to the Company's properties and held that the price payable by Tennessee Gas for the gas was the Contract Price. The Court of Appeals remanded the case to the trial court based on its determination (i) that the Tennessee Gas Contract was an output contract and (ii) that a fact issue existed as to whether the increases in the volumes of gas tendered to Tennessee Gas under the contract were made in bad faith or were unreasonably disproportionate to prior tenders. The Company sought review of the appellate court ruling on the output contract issue in the Supreme Court of Texas. Tennessee Gas also sought review of the appellate court ruling denying the remaining Tennessee Gas claims in the Supreme Court of Texas. The appellate court decision was the first decision reported in Texas holding that a take-or-pay contract was an output contract. The Supreme Court of Texas heard arguments in December 1994 regarding the output contract issue and certain of the issues raised by Tennessee Gas. On August 1, 1995, the Supreme Court of Texas, in a divided opinion, affirmed the decision of the appellate court on all issues, including that the price under the Tennessee Gas Contract is the Contract Price, and determined that the Tennessee Gas Contract was an output contract and remanded the case to the trial court for determination of whether gas volumes tendered by the Company to Tennessee Gas were tendered in good faith and were not unreasonably disproportionate to any normal or otherwise comparable prior output or stated estimates in accordance with the UCC. The Company filed a motion for rehearing before the Texas Supreme Court on the issue of whether the Tennessee Gas Contract is an output contract. The Company believes that, if this issue is tried, the gas volumes tendered to Tennessee Gas will be found to have been in good faith and otherwise in accordance with the requirements of the UCC. However, there can be no assurance as to the ultimate outcome at trial. In conjunction with the District Court judgment and on behalf of all sellers under the Tennessee Gas Contract, Tennessee Gas is presently required to post a supersedeas bond in the amount of $206 million. Under the terms of this bond, for the period September 17, 1994 through April 30, 1996, Tennessee Gas is required to take at least its entire monthly take-or-pay obligation and pay for gas taken at $3.00 per Mmbtu, which approximates $3.00 per Mcf ("Bond Price"). The $206 million bond represents an amount which together with anticipated sales of natural gas at the Bond Price will equal the anticipated value of the Tennessee Gas Contract from September 17, 1994 through April 30, 1996. Except for the period September 17, 1994 through August 13, 1995, the difference between the spot market price and the Bond Price is refundable in the event Tennessee Gas ultimately prevails in the litigation. The Company retains the right to receive the Contract Price for all gas sold to Tennessee Gas. 20 21 Through December 31, 1995, under the Tennessee Gas Contract, the Company recognized cumulative net revenues in excess of spot market prices totaling approximately $117.3 million. Of the $117.3 million incremental net revenues, the Company has received $11.0 million that is nonrefundable and $55.6 million which the Company could be required to repay in the event of an adverse ruling. The remaining $50.7 million of incremental net revenues is classified in the Company's Consolidated Balance Sheet as a noncurrent receivable at December 31, 1995 and represents the unpaid difference between the Contract Price and the Bond Price as described above. An adverse outcome of this litigation could require the Company to reverse as much as $106.3 million of the incremental revenues and could require the Company to repay as much as $55.6 million for amounts received above spot prices, plus interest if awarded by the court. See Notes N and Q of Notes to Consolidated Financial Statements in Item 8. Consent Solicitation. On December 26, 1995, a group of five holders of Tesoro's Common Stock, led by Kevin S. Flannery (the "Flannery Group"), beneficially owning in the aggregate approximately 5.7% of the outstanding shares of Tesoro Common Stock, filed a Form 13D with the Securities and Exchange Commission ("SEC") announcing that they had formed a "group" identified as "The Stockholders' Committee for New Management of Tesoro Petroleum Corporation" (the "Committee"), to seek to acquire control of Tesoro through the replacement of the current Tesoro Board of Directors with persons selected by the Committee. In the Schedule 13D filed by the Flannery Group, the Flannery Group stated that it would seek to accomplish its goal of replacing the Tesoro Board of Directors by soliciting the written consent of holders of Tesoro Common Stock through a consent solicitation. On December 26, 1995, the Committee filed preliminary materials with the SEC to solicit stockholders' written consents. On December 26, 1995, the Flannery Group filed a suit in the Federal District Court for the Western District of Texas, San Antonio Division (Civil Action SA95CA1298) against the Company and Bruce A. Smith, its President and Chief Executive Officer. The suit asks the court (i) to enjoin the Company and Mr. Smith from bringing legal action for wrongdoing by the plaintiffs in any other court, (ii) to declare that the Company's Shareholder Rights Plan does not apply to the Committee's efforts to solicit written consents, (iii) to declare that the Company's By-laws permit stockholders to remove directors by consent, (iv) to declare that the plaintiffs have complied with certain federal securities laws and (v) to enjoin the Company and Mr. Smith from taking any action to delay or otherwise unlawfully interfere with the Committee's efforts to solicit consents. However, the complaint contains no allegations whatsoever that either the Company or Mr. Smith has done anything to delay or otherwise unlawfully interfere with the Committee's solicitation. On January 8, 1996, the Company moved to dismiss the Flannery Group's complaint since it does not allege an actual case or controversy, does not allege any actual illegal conduct by the Company and otherwise improperly requests that the court make legal determinations that are not ripe for consideration. The Company also filed an answer and counterclaims which include allegations that the Flannery Group or members thereof and others have violated the federal securities laws, have disseminated false and misleading information to the Company's stockholders in an effort to take control of the Company and tortiously interfered with the business of the Company, resulting in significant harm to the Company. Also, on January 8, 1996, the United States District Court, at the request of the Company, issued a temporary restraining order restraining the Flannery Group from taking any action in furtherance of its consent solicitation, including soliciting or attempting to solicit consents, filing or disseminating to the Company's stockholders or the public any Schedule 13D or 14A statements relating to the Company, or making any false or misleading statements regarding the Company. In connection with the request for the restraining order, the Company volunteered not to commence any judicial proceedings in any other forum that would require litigation of issues common to those before the court or to take any action unlawfully to delay or interfere with the plaintiffs' efforts to solicit written consents. On January 12, 1996, the court entered an order disqualifying counsel for the Flannery Group and subsequently extended the temporary restraining order as a result. On January 31, 1996, the court held a hearing on the Company's preliminary injunction motion. In connection therewith, the Flannery Group filed with the court a substantially revised Schedule 14A statement purporting to correct the false and misleading statements that the Company claims are in the Flannery Group's initial 14A statement. On February 1, 1996, the court dissolved the temporary restraining order and denied the motion for a preliminary injunction. Based on information contained in a filing with the SEC, the 21 22 Flannery Group on or about February 29, 1996 mailed its consent solicitation material to the Company's stockholders. On March 5, 1996, the Company mailed its consent revocation material to the Company's stockholders. Refund Claim. In July 1994, Simmons Oil Corporation, also known as David Christopher Corporation, a former customer of the Company ("Customer"), filed suit against the Company in the United States District Court for the District of New Mexico for a refund in the amount of approximately $1.2 million, plus interest of approximately $4.4 million and attorney's fees, related to a gasoline purchase from the Company in 1979. The Customer also alleges entitlement to treble damages and punitive damages in the aggregate amount of $16.8 million. The refund claim is based on allegations that the Company renegotiated the acquisition price of gasoline sold to the Customer and failed to pass on the benefit of the renegotiated price to the Customer in violation of Department of Energy price and allocation controls then in effect. In May 1995, the court issued an order granting the Company's motion for summary judgment and dismissed with prejudice all the claims in the Customer's complaint. In June 1995, the Customer filed a notice of appeal with the U.S. Court of Appeals for the Federal Circuit. The Company cannot predict the ultimate resolution of this matter but believes the claim is without merit. Environmental Matters. In March 1991, the Company entered into a Consent Order with the Alaska Department of Environmental Conservation substantially similar to Consent Orders reached with the Environmental Protection Agency ("EPA") in September 1989. These Consent Orders provide for the investigation and cleanup of hydrocarbons in the soil and groundwater at the Company's Alaska refinery, which resulted from sewer hub seepage associated with the underground oil/water sewer system. The Consent Orders formalized efforts, which commenced in 1987, to remedy the presence of hydrocarbons in the soil and groundwater and provide for the performance of additional future work. The Company has replaced or rebuilt the drainage hubs and has initiated a subsurface monitoring and interception system designed to identify the extent of hydrocarbons present in the groundwater and to remove the hydrocarbons. In March 1992, the Company received a Compliance Order and Notice of Violation from the EPA alleging violations by the Company of the New Source Performance Standards under the Clean Air Act at its Alaska refinery. These allegations include failure to install, maintain and operate monitoring equipment over a period of approximately six years, failure to perform accuracy testing on monitoring equipment, and failure to install certain pollution control equipment. From March 1992 to July 1993, the EPA and the Company exchanged information relevant to these allegations. In addition, the EPA conducted an environmental audit of the Company's refinery in May 1992. As a result of this audit, the EPA is also alleging violation of certain regulations related to asbestos materials. In October 1993, the EPA referred these matters to the Department of Justice ("DOJ"). The DOJ contacted the Company to begin negotiating a resolution of these matters. The DOJ has indicated that it is willing to enter into a judicial consent decree with the Company and that this decree would include a penalty assessment. Negotiations on the penalty are in progress. The DOJ is currently considering a penalty assessment of approximately $1.5 million. The Company is continuing to negotiate with the DOJ but cannot predict the ultimate outcome of the negotiations. The Company, along with numerous other parties, has been identified by the 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 (the "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. At this time, the Company is unable to determine the extent of the Company's liability related to the Site; however, the extent of the Company's allocated financial contribution to the cleanup of these sites is expected to be minimal based on the number of companies and the volumes of waste involved. The Company believes that its liability at the Site will be limited based upon the payment by the Company of a de minimis settlement amount of $2,500 at a similar site in Louisiana. The Company believes that the aggregate amount of such liability, if any, would not have a material adverse effect on the Company. 22 23 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The principal markets on which the Company's Common Stock is traded are the New York Stock Exchange and the Pacific Stock Exchange. The per share market price ranges for the Company's Common Stock during 1995 and 1994 are summarized below:
1995 1994 ------------- ------------ QUARTERS HIGH LOW HIGH LOW -------- ----- --- ---- --- First................................................... $10 5/8 8 3/4 12 3/8 5 1/4 Second.................................................. $12 9 1/2 12 1/8 9 7/8 Third................................................... $10 3/8 8 11 1/4 8 1/2 Fourth.................................................. $ 9 1/2 7 1/4 10 8 1/2
At March 1, 1996, there were approximately 4,000 holders of record of the Company's 25,734,991 outstanding shares of Common Stock. The Company did not pay dividends on its Common Stock for the periods set forth above. 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. 23 24 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.
THREE MONTHS YEAR ENDED ENDED YEARS ENDED DECEMBER 31, DECEMBER SEPTEMBER ------------------------------ 31, 30, 1995 1994 1993 1992 1991(1) 1991 ------ ----- ----- ----- ------ ------ (IN MILLIONS EXCEPT PER SHARE AMOUNTS) STATEMENTS OF OPERATIONS DATA Gross Operating Revenues: Refining and Marketing...................................... $771.0 687.0 687.2 810.7 196.8 898.6 Exploration and Production Oil and gas producing(2)(3)............................... 119.0 100.7 61.0 42.1 12.5 59.0 Gas transportation(3)..................................... 5.7 3.1 1.0 -- -- -- Marine Services............................................. 74.5 77.9 80.7 93.5 36.5 134.3 Intersegment Eliminations(4)................................ -- -- -- (.4) (5.2) (7.1) ------ ----- ----- ----- ------ ------ Total Gross Operating Revenues........................ $970.2 868.7 829.9 945.9 240.6 1,084.8 ====== ===== ===== ===== ====== ====== Segment Operating Profit (Loss), Including Gain on Sales of Assets(5): Refining and Marketing...................................... $ .7 2.4 15.2 (14.9) 1.7 19.3 Exploration and Production Oil and gas producing(2)(5)............................... 104.5 61.4 39.8 29.1 7.4 35.6 Gas transportation........................................ 5.1 2.9 .9 -- -- -- Marine Services............................................. (4.4) (2.3) (3.6) (4.7) (1.2) (.5) ------ ----- ----- ----- ------ ------ Total Segment Operating Profit........................ $105.9 64.4 52.3 9.5 7.9 54.4 ====== ===== ===== ===== ====== ====== Earnings (Loss) Before Extraordinary Loss and the Cumulative Effect of Accounting Changes................................ $ 57.5 20.5 17.0 (45.3) (.4) 3.9 Extraordinary Loss on Extinguishment of Debt.................. (2.9) (4.8) -- -- -- -- Cumulative Effect of Accounting Changes....................... -- -- -- (20.6) -- -- ------ ----- ----- ----- ------ ------ Net Earnings (Loss)(6)........................................ $ 54.6 15.7 17.0 (65.9) (.4) 3.9 ====== ===== ===== ===== ====== ====== Net Earnings (Loss) Applicable to Common Stock(6)............. $ 54.6 13.0 7.8 (75.1) (2.7) (5.3) ====== ===== ===== ===== ====== ====== Earnings (Loss) per Primary and Fully Diluted* Share(6)(7): Earnings (loss) before extraordinary loss and the cumulative effect of accounting changes.............................. $ 2.29 .77 .54 (3.87) (.19) (.37) Extraordinary loss on extinguishment of debt................ (.11) (.21) -- -- -- -- Cumulative effect of accounting changes..................... -- -- -- (1.47) -- -- ------ ----- ----- ----- ------ ------ Net earnings (loss)......................................... $ 2.18 .56 .54 (5.34) (.19) (.37) ====== ===== ===== ===== ====== ====== Average Common and Common Equivalent Shares Outstanding(7): Primary..................................................... 25.1 23.2 14.3 14.1 14.1 14.1 Fully diluted............................................... 25.1 24.7 19.1 18.8 18.8 18.8 CAPITAL EXPENDITURES Refining and Marketing...................................... $ 9.3 32.0 7.1 3.7 .8 4.4 Exploration and Production Oil and gas producing..................................... 53.2 60.4 28.6 9.3 3.0 19.3 Gas transportation........................................ .2 5.2 .7 -- -- -- Other....................................................... 1.2 2.0 1.1 2.4 .1 .8 ------ ----- ----- ----- ------ ------ Total Capital Expenditures............................ $ 63.9 99.6 37.5 15.4 3.9 24.5 ====== ===== ===== ===== ====== ====== BALANCE SHEET AND OTHER DATA Total Assets.................................................. $519.2 484.4 434.5 446.7 494.7 496.8 Working Capital............................................... $ 77.5 85.9 124.5 122.6 106.1 95.4 Long-Term Debt and Other Obligations, Less Current Portion(7).................................................. $155.0 192.2 180.7 175.5 130.3 127.0 Redeemable Preferred Stock(7)................................. $ -- -- 78.1 71.7 57.4 57.4 Common Stock and Other Stockholders' Equity(7)(8)............. $216.5 160.7 58.5 50.7 137.0 137.4
- --------------- * Anti-dilutive. 24 25 (1) The Company's fiscal year-end was changed from September 30 to December 31, effective January 1, 1992. (2) The Company is involved in litigation related to a natural gas sales contract. For additional information concerning this dispute, see Legal Proceedings in Item 3 and Notes N and Q of Notes to Consolidated Financial Statements in Item 8. (3) Amounts previously reported have been restated for certain reclassifications between revenues and operating expenses. (4) Intersegment eliminations represented sales from Refining and Marketing to Marine Services (formerly Oil Field Supply and Distribution), at prices which approximated market. (5) Segment operating profit represents pretax earnings (loss) before certain corporate expenses, interest income and interest expense. Operating profit from Exploration and Production in 1995 included a gain of approximately $33 million from the sale of certain interests in the Bob West Field (see Note B of Notes to Consolidated Financial Statements in Item 8). (6) Net earnings for 1995 and 1994 included extraordinary losses of $2.9 million and $4.8 million, respectively, related to early extinguishments of debt. The net loss for 1992 included a charge of $20.6 million for the cumulative effect of the adoption of SFAS No. 106, "Employer's Accounting for Postretirement Benefits Other Than Pensions," and SFAS No. 109, "Accounting for Income Taxes." (7) For information on the Company's recapitalization and equity offering in 1994, see Note H of Notes to Consolidated Financial Statements in Item 8. (8) No dividends were paid on common shares during the periods presented above. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS RESULTS OF OPERATIONS Net earnings of $54.6 million ($2.18 per share) in 1995 compare to $15.7 million ($.56 per share) in 1994. Noncash extraordinary losses on extinguishments of debt amounted to $2.9 million ($.11 per share) in 1995 and $4.8 million ($.21 per share) in 1994, both relating to early redemptions of the Company's 12 3/4% Subordinated Debentures ("Subordinated Debentures"). Earnings before extraordinary loss amounted to $57.5 million ($2.29 per share) in 1995 and $20.5 million ($.77 per share) in 1994. Net earnings for 1994 were reduced by $2.7 million of dividend requirements on preferred stock. Comparability between 1995 and 1994 was further impacted by certain significant transactions. Earnings for 1995 included an after-tax gain of approximately $33 million from the sale of certain interests in the Bob West Field in South Texas and a charge of approximately $5 million for employee terminations and other restructuring costs. During 1994, earnings were favorably impacted by a refund of $8.5 million received in settlement of a tariff dispute and a gain of $2.4 million from the sale of assets, partially offset by net charges of approximately $7 million related to environmental contingencies and other matters. Excluding these significant transactions from both years, the improvement in net earnings of approximately $12 million in 1995 was primarily attributable to increased natural gas production from the Company's exploration and production operations in South Texas and improvements in the Company's refining and marketing operations, in spite of difficult industry conditions that prevailed throughout most of the year. Net earnings of $15.7 million ($.56 per share) in 1994 compare with $17.0 million ($.54 per share) in 1993. Earnings before the extraordinary loss in 1994 were $20.5 million ($.77 per share). As described above, earnings in 1994 benefited from a refund received in settlement of a tariff dispute and a gain from the sale of assets, partially offset by net charges related to environmental contingencies and other matters. During 1993, the Company's earnings benefited from the resolutions of several state tax issues, resulting in a net reduction of $3.0 million in income tax expense and $5.2 million in interest expense. In addition, a gain of $1.4 million was recognized in 1993 for the retirement of $11.25 million principal amount of Subordinated Debentures, which were purchased to satisfy the initial sinking fund requirement on such debt. Excluding these transactions, the improvement in net earnings of approximately $9 million in 1994 was primarily attributable to increased natural gas production from the Company's exploration and production operations in South Texas, partially offset by the impact of lower spot market prices for sales of natural gas and lower operating results from the Company's refining and marketing operations. 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 25 26 Company. The Company conducts its operations in the following business segments: Refining and Marketing; Exploration and Production; and Marine Services (formerly Oil Field Supply and Distribution). REFINING AND MARKETING
1995 1994 1993 ------- ------- ------- (DOLLARS IN MILLIONS EXCEPT PER BARREL AMOUNTS) GROSS OPERATING REVENUES Refined products................................................ $ 664.5 582.7 590.9 Other, primarily crude oil resales and merchandise.............. 106.5 104.3 96.3 ------- ------- ------- Gross Operating Revenues..................................... $ 771.0 687.0 687.2 ======= ======= ======= OPERATING PROFIT Gross margin -- refined products................................ $ 85.3 85.3 89.4 Gross margin -- other........................................... 12.3 13.1 13.2 ------- ------- ------- Gross margin................................................. 97.6 98.4 102.6 Operating expenses.............................................. 84.7 88.2 76.9 Depreciation and amortization................................... 11.9 10.4 10.3 Other, including gain on asset sales............................ .3 (2.6) .2 ------- ------- ------- Operating Profit............................................. $ .7 2.4 15.2 ======= ======= ======= CAPITAL EXPENDITURES.............................................. $ 9.3 32.0 7.1 ======= ======= ======= REFINERY OPERATIONS -- THROUGHPUT (average daily barrels)......... 50,569 46,032 49,753 ======= ======= ======= REFINERY OPERATIONS -- PRODUCTION (average daily barrels) Gasoline........................................................ 14,298 11,728 12,021 Middle distillates and other.................................... 23,182 20,615 21,487 Heavy oils and residual products................................ 14,516 15,118 17,573 ------- ------- ------- Total Refinery Production.................................... 51,996 47,461 51,081 ======= ======= ======= REFINERY OPERATIONS -- PRODUCT SPREAD ($/barrel) Average yield value of products manufactured.................... $ 20.35 19.48 20.11 Cost of raw materials........................................... 16.88 15.65 15.73 ------- ------- ------- Refinery Product Spread...................................... $ 3.47 3.83 4.38 ======= ======= ======= REFINING AND MARKETING -- TOTAL PRODUCT SALES (average daily barrels) Gasoline........................................................ 24,526 23,191 22,466 Middle distillates.............................................. 37,988 33,256 29,354 Heavy oils and residual products................................ 14,787 14,228 16,945 ------- ------- ------- Total Product Sales.......................................... 77,301 70,675 68,765 ======= ======= ======= REFINING AND MARKETING -- TOTAL PRODUCT SALES PRICES ($/barrel) Gasoline........................................................ $ 28.21 27.03 27.82 Middle distillates.............................................. $ 24.40 24.47 27.39 Heavy oils and residual products................................ $ 13.66 10.93 11.19 REFINING AND MARKETING -- GROSS MARGINS ON TOTAL PRODUCT SALES ($/barrel) Average sales price............................................. $ 23.55 22.59 23.54 Average costs of sales*......................................... 20.53 19.67 19.98 ------- ------- ------- Gross margin................................................. $ 3.02 2.92 3.56 ======= ======= =======
- --------------- * Computations of per barrel average costs of sales in 1994 exclude the benefits of an $8.5 million tariff refund and $1.5 million in favorable feedstock cost adjustments. 26 27 Sources of total product sales include products manufactured at the refinery, existing inventory balances and products purchased from third parties. Margins on sales of purchased products, together with the effect of changes in inventories, are included in the gross margin on total product sales presented above. During 1995, 1994 and 1993, the Company's purchases of refined products for resale approximated 25,500, 27,200 and 19,300 average daily barrels, respectively. The refinery product spread presented above represents the excess of yield value of the products manufactured at the refinery over the cost of raw materials used to manufacture such products. 1995 Compared to 1994. The Refining and Marketing segment attained operating profit of $.7 million in 1995, despite industry refining margins that were among the lowest in a decade. These results compare with operating profit of $2.4 million in 1994, which benefited from an $8.5 million refund received in settlement of a tariff dispute, a gain of $2.4 million from the sale of assets and favorable feedstock cost adjustments of $1.5 million, partially offset by $6.6 million for environmental contingencies and other matters. There were no comparable significant transactions recorded in 1995. Excluding these items from 1994, operating profit in 1995 reflected an improvement of $4.1 million from the 1994 operating results. The Company's average feedstock costs increased by 8%, from $15.65 per barrel in 1994 to $16.88 per barrel in 1995, while the average yield value of the Company's refinery production increased by only 4%, from $19.48 per barrel in 1994 to $20.35 per barrel in 1995. Increased demand for Alaska North Slope ("ANS") crude oil for use as a feedstock in West Coast refineries and declining production volumes of ANS, combined with an oversupply of products in Alaska and on the West Coast, resulted in higher feedstock costs for the Company relative to increases in refined product sales prices. As a result, the Company's refined product margins were depressed in 1995. The start-up in December 1994 of a vacuum unit at the Company's refinery increased the yield of higher-valued products during 1995 and lessened the impact of these industry conditions on the Company's refinery spread. The Company's refinery yield of residual products was reduced to 18% of total production in 1995 from 32% of total production in 1994. In addition, margins on sales of inventories and purchased volumes combined to improve the segment's gross margins on total product sales to $3.02 per barrel in 1995, compared to $2.92 per barrel in 1994. The Company's total refinery production increased by 10%, including a 22% increase in gasoline volumes and a 12% increase in middle distillates volumes. Accordingly, in 1995, the Company implemented initiatives that increased the demand for the refinery's production and improved the refinery's capacity utilization and efficiencies. In these regards, the Company expanded its marketing efforts by branding and rebranding sales outlets in Alaska and the Pacific Northwest and by exporting refined products to the Far East, including Russia. Revenues from export sales totaled $18.5 million in 1995 compared to $5.2 million in 1994. The Company's total product sales increased to 77,301 average barrels per day in 1995 from 70,675 average barrels per day in 1994. Revenues from sales of refined products in 1995 were higher than in 1994 due to higher sales prices and the increase in sales volumes. To optimize the refinery's feedstock mix and in response to market conditions, the Company at times resells previously purchased crude oil which aggregated $75.8 million in 1995 and $72.3 million in 1994. Costs of sales were higher in 1995 due to higher volumes and prices. Operating expenses decreased by $3.5 million in 1995 primarily due to lower environmental costs, partly offset by increased employee costs and fuels and utilities expense. Depreciation and amortization increased by $1.5 million in 1995 due to capital additions, primarily the vacuum unit, completed in late 1994. Included in 1994 was a $2.4 million gain from the sale of assets. 1994 Compared to 1993. Throughout most of 1994, the Refining and Marketing segment was adversely affected by the volatile product market and increased demand for ANS crude oil. The adverse effect of market conditions on the segment's 1994 results, combined with charges of $6.6 million for environmental contingencies and other matters, was partially offset by a refund of $8.5 million received in settlement of a tariff dispute, a gain of $2.4 million from the sale of assets and favorable feedstock cost adjustments of $1.5 million. Excluding these items, the segment's operating profit of $2.4 million for 1994 would be reduced to a loss of $3.4 million, compared with operating profit of $15.2 million in 1993. The decrease in operating 27 28 results was primarily attributable to lower gross margins on sales of refined products, which fell to $2.92 per barrel in 1994, from $3.56 per barrel in 1993. Revenues from sales of refined products in 1994 were lower than 1993 due to lower sales prices. However, these lower refined product revenues in 1994 were partially offset by crude oil resales of $72.3 million, compared to $62.1 million in 1993. The increase in operating expenses of $11.3 million was primarily for environmental matters and, to a lesser extent, higher advertising and maintenance expenses. During 1994, the Company improved the refinery's economics, which included upgrading feedstocks, more closely matching production with product demand within Alaska and initiating new marketing efforts within and outside Alaska. These efforts reduced the Company's overall refinery production in 1994, particularly residual fuel oil. During 1994, the Company reduced its average daily refinery throughput and production by 7% from the 1993 levels. This reduction in throughput enabled the Company to reduce the percentage of lower-quality ANS crude oil in the feedstock mix to 59% in 1994, compared with 72% in 1993. By utilizing a greater percentage of higher-quality feedstocks (which results in higher-valued production yields), the Company can economically operate the refinery at reduced throughput levels. Operating the refinery at lower throughput levels resulted in less production of certain products in 1994, particularly residual fuel oil, for which there is no significant market in Alaska. During 1994, residual fuel oil produced at the refinery was exported from Alaska and sold into U.S. West Coast and Far East markets. These markets had generally been weak for 1994 and the past several years due to a global oversupply of this product. EXPLORATION AND PRODUCTION
1995 1994 1993 -------- ------ ------ (DOLLARS IN MILLIONS EXCEPT PER UNIT AMOUNTS) U.S. OIL AND GAS Gross operating revenues(1)(2)............................... $ 107.3 87.5 48.4 Production costs(2).......................................... 12.0 9.0 4.7 Other operating expenses..................................... 2.9 2.3 1.2 Depreciation, depletion and amortization..................... 29.0 24.1 11.1 Gain on sale of assets....................................... 33.5 -- -- -------- ------ ------ Operating Profit -- U.S. Oil and Gas...................... 96.9 52.1 31.4 -------- ------ ------ U.S. GAS TRANSPORTATION Gross operating revenues..................................... 5.7 3.1 1.0 Operating expenses........................................... .3 -- .1 Depreciation and amortization................................ .3 .2 -- -------- ------ ------ Operating Profit -- U.S. Gas Transportation............... 5.1 2.9 .9 -------- ------ ------ BOLIVIA Gross operating revenues..................................... 11.7 13.2 12.6 Production costs............................................. .6 .6 1.2 Other operating expenses..................................... 3.2 3.3 3.0 Depreciation, depletion and amortization..................... .3 -- -- -------- ------ ------ Operating Profit -- Bolivia............................... 7.6 9.3 8.4 -------- ------ ------ TOTAL OPERATING PROFIT -- EXPLORATION AND PRODUCTION........... $ 109.6 64.3 40.7 ======== ====== ====== U.S. Capital expenditures (including U.S. gas transportation)..... $ 49.6 65.6 29.3 ======== ====== ====== Net natural gas production (average daily Mcf) -- Spot market and other..................................... 94,668 65,841 28,168 Tennessee Gas Contract(1)................................. 19,822 17,955 10,599 -------- ------ ------ Total Production..................................... 114,490 83,796 38,767 ======== ====== ======
28 29
1995 1994 1993 -------- ------ ------ (DOLLARS IN MILLIONS EXCEPT PER UNIT AMOUNTS) Average natural gas sales price per Mcf(2) -- Spot market............................................... $ 1.34 1.48 1.89 Tennessee Gas Contract(1)................................. $ 8.41 7.93 7.51 Average................................................... $ 2.57 2.86 3.43 Average production costs per Mcf(2)(3)....................... $ .29 .29 .34 Total operating expenses per Mcf............................. $ .35 .37 .42 Depletion per Mcf............................................ $ .69 .79 .78 BOLIVIA Capital expenditures......................................... $ 3.8 -- -- Net natural gas production (average daily Mcf)............... 18,650 22,082 19,232 Average natural gas sales price per Mcf...................... $ 1.28 1.20 1.22 Net crude oil (condensate) production (average daily barrels).................................................. 567 733 663 Average crude oil price per barrel........................... $ 14.39 13.28 14.26 Average production costs per net equivalent Mcf.............. $ .07 .06 .14 Total operating expenses per net equivalent Mcf.............. $ .48 .41 .50
- --------------- (1) The Company is involved in litigation with Tennessee Gas Pipeline Company ("Tennessee Gas") relating to a natural gas sales contract ("Tennessee Gas Contract"). See "Capital Resources and Liquidity -- Tennessee Gas Contract" and Notes N and Q of Notes to Consolidated Financial Statements in Item 8. (2) Amounts previously reported have been restated for certain reclassifications between revenues and operating expenses. (3) Production costs for the Company's U.S. operations include such items as severance taxes, property taxes, insurance and materials and supplies. Since severance taxes are based upon sales prices of natural gas, the average production costs presented above include the impact of above-market prices for sales under the Tennessee Gas Contract. Production costs per Mcf of natural gas sold in the spot market were approximately $.20, $.20 and $.23 for 1995, 1994 and 1993, respectively. EXPLORATION AND PRODUCTION -- UNITED STATES 1995 Compared to 1994. Operating profit of $96.9 million in 1995 from the Company's U.S. oil and gas operations included a gain of approximately $33 million from the sale of certain interests in the Bob West Field. Excluding this gain, operating profit from these operations would have been approximately $63 million in 1995 compared with $52 million in 1994, reflecting a continued successful drilling program which resulted in an increase in the Company's U.S. natural gas production in South Texas. After the sale of certain Bob West Field interests in September 1995, which included interests in 14 gross producing wells, the number of wells in which the Company had an interest was reduced to 57 at year-end 1995, compared with 48 producing wells at year-end 1994. The Company's U.S. natural gas production sold into the spot market increased by 44% and production sold under the Tennessee Gas Contract increased by 10%. Revenues increased by $20 million due to these increases in production, but were partially offset by lower spot market natural gas sales prices. The Company's weighted average sales price decreased to $2.57 per Mcf during 1995 from $2.86 per Mcf in 1994, reflecting lower spot market sales prices and a lower percentage of production sold to Tennessee Gas at above-market prices. In 1995, approximately 17% of the Company's total U.S. production was sold to Tennessee Gas, compared to 21% in 1994 and 27% in 1993. The Company recognizes revenues for sales to Tennessee Gas based on a contract price, which exceeded a nonrefundable cash price by an aggregate of $41 million, net of severance taxes, in 1995. Total production costs and other operating expenses were higher in 1995 due to the increased production levels and severance taxes related to the above-market pricing of sales to Tennessee Gas, but were relatively unchanged on a per Mcf basis. The impact of the increased production volumes on depletion expense was substantially offset by a 13% reduction in the depletion rate 29 30 which resulted from additions to proved reserves during the year and elimination of proportionately higher future development costs on the reserves sold in the Bob West Field. In 1995, operating results from the Exploration and Production segment included natural gas production of approximately 24 Mmcf per day, revenues of $11 million and operating profit of $4 million related to the interests that were sold in the Bob West Field. For further information regarding the sale of these interests, see Note B of Notes to Consolidated Financial Statements in Item 8. Under the terms of a bond posting related to the Tennessee Gas litigation, Tennessee Gas must until April 30, 1996 take at least its entire monthly take-or-pay obligation and pay for gas taken at $3.00 per Mmbtu. Without the bonding arrangements associated with the litigation, Tennessee Gas could elect, and from time to time has elected, not to take gas under the Tennessee Gas Contract. The Company recognizes revenues under the Tennessee Gas Contract based on the quantity of natural gas actually taken by Tennessee Gas. While Tennessee Gas has the right to elect not to take gas during any contract year, this right is subject to an obligation to pay within 60 days after the end of such contract year for gas not taken, subject to the provisions of the bond posting. The contract year ends on January 31 of each year. Although the failure to take gas could adversely affect the Company's income and cash flows from operating activities within a contract year, the Company should recover reduced cash flows shortly after the end of the contract year under the take-or-pay provisions of the Tennessee Gas Contract, subject to the provisions of the bond posting. See "Capital Resources and Liquidity -- Tennessee Gas Contract" and Notes N and Q of Notes to Consolidated Financial Statements in Item 8. The Company enters into commodity price swap agreements to reduce the risk caused by fluctuations in the prices of natural gas in the spot market. During 1995 and 1994, the Company used such arrangements to set the price of 38% and 11%, respectively, of the natural gas production that it sold in the spot market. During each of the years 1995 and 1994, the Company realized net gains in gas revenues of approximately $.3 million from these price swap arrangements. These gains had the effect of adding $.01 per Mcf to the Company's average spot market sales price for 1995 and 1994. As of January 9, 1996, the Company had entered into such price swaps for 1996 production totaling 8.4 billion cubic feet for an average Houston Ship Channel price of $1.77 per Mcf. In 1995, the Company's average spot market wellhead price per Mcf was $.25 less than the average Houston Ship Channel index, the difference representing transportation and marketing costs from the wellhead in South Texas. For further information on the Company's natural gas price swap agreements, see Note P of Notes to Consolidated Financial Statements in Item 8. In addition to the natural gas producing activities, during 1995 the Company's results included revenues of $5.7 million and operating profit of $5.1 million for transportation of natural gas to common carrier pipelines in the South Texas area, of which approximately 51% relates to transportation of the Company's production. The increase in these results in 1995, compared to 1994, was due to higher transmission volumes stemming primarily from the development of the Bob West Field together with an expansion of the pipeline in mid-1994. 1994 Compared to 1993. The number of producing wells in which the Company has a working interest increased to 48 at year-end 1994, compared with 26 at the end of 1993, resulting in a 116% increase in the Company's U.S. natural gas production. Revenues from the U.S. oil and gas operations increased by $39.1 million in 1994 primarily due to the increased production. However, revenues were adversely impacted by a 17% decline in the weighted average sales price of natural gas, which included a 22% drop in spot market prices. Due to the increase in volumes sold in the spot market, the percentage contribution of sales at above-market prices under the Tennessee Gas Contract was reduced. In 1994, approximately 21% of the Company's net production from the Bob West Field was sold under the Tennessee Gas Contract, compared with 27% in 1993. Total production costs and depreciation, depletion and amortization were higher in 1994 due to the increased production level. Operating results from the Company's natural gas transportation operations increased by $2.0 million due to higher transmission volumes associated with the increased production levels in South Texas. Transportation of the Company's production accounted for approximately 58% and 74% of these results in 1994 and 1993, respectively. 30 31 EXPLORATION AND PRODUCTION -- BOLIVIA 1995 Compared to 1994. Operating profit from the Company's Bolivian operations decreased by $1.7 million in 1995, reflecting a 16% decrease in net natural gas production. During 1994, the Company had benefited from higher levels of production due to the inability of another producer to satisfy gas supply requirements. Partially offsetting the decrease in production in 1995 were increases in the average prices of natural gas and condensate production. The Company's Bolivian natural gas production is sold to Yacimientos Petroliferos Fiscales Bolivianos ("YPFB"), which in turn sells the natural gas to Yacimientos Petroliferos Fiscales, S.A. ("YPF"), a publicly-held company based in Argentina. During 1994, the contract between YPFB and YPF was extended through March 31, 1997, maintaining approximately the same volumes as the previous contract. Currently, the Company is selling its natural gas production to YPFB based on the volume and pricing terms in the contract between YPFB and YPF. 1994 Compared to 1993. Results from the Company's Bolivian operations improved by $.9 million in 1994, primarily due to a 15% increase in average daily natural gas production. The Company was producing gas at higher levels during 1994 due to the inability of another producer to satisfy gas supply requirements. MARINE SERVICES
1995 1994 1993 ------ ----- ----- (DOLLARS IN MILLIONS) Gross Operating Revenues........................................... $ 74.5 77.9 80.7 Costs of Sales..................................................... 64.9 67.5 68.4 ------ ----- ----- Gross Margin..................................................... 9.6 10.4 12.3 Operating and Other Expenses....................................... 13.7 12.4 15.5 Depreciation and Amortization...................................... .3 .3 .4 ------ ----- ----- Operating Loss................................................... $ (4.4) (2.3) (3.6) ====== ===== ===== Capital Expenditures............................................... $ .4 .2 .3 ====== ===== ===== Refined Product Sales (average daily barrels)...................... 7,336 7,774 7,368 ====== ===== =====
1995 Compared to 1994. In 1995, the Company continued consolidating certain operations in its former Oil Field Supply and Distribution segment by exiting the land-based portion of its petroleum product distribution business, reducing the total number of Company sites to 14, primarily marine-based, at year-end. In these regards, four Texas locations were sold in 1995. Included in operating and other expenses in 1995 was a charge of $.8 million related to employee terminations and other exit costs. Revenues and costs of sales were lower in 1995 due to reduced volumes while these operations were being consolidated. In February 1996, the Company purchased 100% of the outstanding capital stock of Coastwide Energy Services, Inc. ("Coastwide"). Coastwide is primarily a provider of services and a wholesale distributor of diesel fuel and lubricants to the offshore drilling industry in the Gulf of Mexico. The Company will combine its remaining petroleum distribution operations with Coastwide, forming a Marine Services segment. As a combined operation, the Marine Services segment will consist of 20 terminals, primarily marine-based, and will provide a broad range of products and logistical support services to the offshore drilling and drilling-related businesses. On a pro forma basis, if the purchase would have occurred at the beginning of 1995, the Coastwide operations would have added approximately $40 million to the Company's 1995 revenues. For additional information on this acquisition, see Note B of Notes to Consolidated Financial Statements in Item 8. 1994 Compared to 1993. Although sales volumes of refined products increased by 6% in 1994, sales prices and gross margins were impacted by strong competition in an oversupplied market. By consolidating certain of the Company's terminals and discontinuing the environmental products marketing operations, operating and other expenses were reduced to $12.4 million in 1994 from $15.5 million in 1993. Included in operating expenses in 1994 were charges of $1.9 million for discontinuing the Company's environmental products marketing operations. 31 32 GENERAL AND ADMINISTRATIVE EXPENSES General and administrative expenses of $16.4 million in 1995 compare with $14.7 million in 1994 and $16.7 million in 1993. The increase in 1995 was primarily due to higher employee and other benefit costs. The decrease in 1994, compared to 1993, was principally due to lower expenses resulting from cost reduction measures previously implemented at the Company. INTEREST EXPENSE Interest expense of $20.9 million in 1995 compares with $18.7 million in 1994 and $14.5 million in 1993. The increase in 1995, compared with 1994, was primarily due to interest on the vacuum unit financing and cash borrowings under the Revolving Credit Facility during 1995 and interest capitalized in 1994 related to the construction of the vacuum unit. As discussed in Notes H and I of Notes to Consolidated Financial Statements, in December 1995, the Company redeemed $34.6 million of its Subordinated Debentures which, together with lower borrowings under the Company's Revolving Credit Facility, are expected to result in future annual interest expense savings of approximately $5 million. The increase in 1994, compared with 1993, was primarily due to a reduction of $5.2 million recorded in 1993 related to the resolution of outstanding issues with several state taxing authorities, partially offset by $.9 million of capitalized interest in 1994. OTHER EXPENSE Other expense of $8.5 million in 1995 compares with $7.4 million in 1994 and $4.2 million in 1993. The increase in 1995, compared with 1994, was primarily due to severance costs and related benefits of $3.8 million resulting from a reduction in administrative workforce and other employee terminations (see Note J of Notes to Consolidated Financial Statements in Item 8), partially offset by lower environmental and other expenses related to the Company's former operations. The increase in 1994, compared with 1993, was primarily due to higher environmental and other costs associated with the Company's former operations and to a gain of $1.4 million recorded in 1993 for the extinguishment of debt. INCOME TAXES Income taxes of $4.4 million in 1995 compare with $5.6 million in 1994 and $1.7 million in 1993. The decrease in 1995 was primarily due to lower state income taxes. No income taxes were provided on the gain on sales of assets during 1995 due to the utilization of previously unrecognized net operating losses and other carryforwards. The increase in 1994, compared with 1993, was primarily due to a reduction of $3.0 million recorded in 1993 for resolution of outstanding issues with several state taxing authorities. IMPACT OF CHANGING PRICES The Company's operating results and cash flows are sensitive to the volatile changes in energy prices. Major shifts in the cost of crude oil used for refinery feedstocks and the price of refined products can result in a change in gross margin from the refining and marketing operations, as prices received for refined products may or may not keep pace with changes in crude oil costs. These energy prices, together with volume levels, also determine the carrying value of crude oil and refined product inventory. Likewise, changes in natural gas prices impact revenues and the present value of estimated future net revenues and cash flows from the Company's exploration and production operations. From time to time, the Company may increase or decrease its natural gas production in response to market conditions. The carrying value of oil and gas assets may also be subject to noncash write-downs based on changes in natural gas prices and other determining factors. CAPITAL RESOURCES AND LIQUIDITY The Company operates in an environment where markets for crude oil, natural gas and refined products historically have been volatile and are likely to continue to be volatile in the future. The Company's liquidity and capital resources are significantly impacted by changes in the supply of and demand for crude oil, natural 32 33 gas and refined petroleum products, market uncertainty and a variety of additional factors that are beyond the control of the Company. These factors include, among others, the level of consumer product demand, weather conditions, the proximity of the Company's natural gas reserves to pipelines, the capacities of such pipelines, fluctuations in seasonal demand, governmental regulations, the price and availability of alternative fuels and overall economic conditions. The Company cannot predict the future markets and prices for its natural gas or refined products and the resulting future impact on earnings and cash flows. The Company's future capital expenditures, borrowings under its credit arrangements and other sources of capital will be affected by these conditions. Although the Company expects continued market improvement, the Company's operations in the past have been adversely affected by depressed market conditions. The Company continues to assess its existing asset base in order to maximize returns and financial flexibility through diversification, acquisitions and divestitures in all of its operating segments. This ongoing assessment includes, in the Exploration and Production segment, evaluating ways in which the Company might diversify the mix of its oil and gas assets and reduce the asset concentration associated with the Bob West Field. In the Refining and Marketing segment, the Company has been engaged in an ongoing effort to evaluate these assets and operations and has considered possible joint ventures, strategic alliances or business combinations; however, such evaluations have not resulted in any transaction. The Company continues to assess its Marine Services segment, pursuing opportunities to consolidate operations and improve efficiencies. As a result of this ongoing assessment, the Company has taken two significant steps in 1995: o In September 1995, the Company sold certain interests in the Bob West Field which would have required approximately $19 million of capital expenditures for future development of proven reserves. Net proceeds from the sale of these interests in the Bob West Field were used to redeem $34.6 million of the Company's outstanding Subordinated Debentures, reduce borrowings under its Revolving Credit Facility and improve corporate liquidity (see Notes B and I of Notes to Consolidated Financial Statements in Item 8). o During 1995, the Company restructured certain operations in its former Oil Field Supply and Distribution segment by exiting the land-based portion of its petroleum product distribution business, and in February 1996 the Company acquired Coastwide and combined these operations with the Company's remaining oil field supply and distribution operations. At closing, consideration for the stock of Coastwide includes 946,883 shares of Tesoro's Common Stock and approximately $5.9 million in cash. The market price of Tesoro's Common Stock was $9.00 per share at closing of this transaction. Upon exchange of Coastwide's remaining warrants, options and convertible debentures, the Company will issue approximately 440,000 additional shares of Tesoro's Common Stock and pay $1.8 million in cash. CREDIT ARRANGEMENTS The Company has financing and credit arrangements under a three-year corporate Revolving Credit Facility ("Facility") dated April 20, 1994, with a consortium of ten banks. The Facility, which is subject to a borrowing base, provides for (i) the issuance of letters of credit up to the full amount of the borrowing base and (ii) cash borrowings up to the amount of the borrowing base attributable to domestic oil and gas reserves. Outstanding obligations under the Facility are secured by liens on substantially all of the Company's trade accounts receivable and product inventory and by mortgages on the Company's refinery and South Texas natural gas reserves. Under the terms of the Facility, which has been amended from time to time, the Company is required to maintain specified levels of working capital, tangible net worth, consolidated cash flow and refining and marketing cash flow, as defined. Among other matters, the Facility contains certain restrictions with respect to (i) capital expenditures, (ii) incurrence of additional indebtedness, and (iii) dividends on capital stock. The Facility contains other covenants customary in credit arrangements of this kind. Future compliance with certain financial covenants is primarily dependent on the Company's maintenance of specified levels of cash flows from operations, capital expenditures, levels of borrowings and the value of the Company's domestic oil and gas reserves. In October 1995, the Facility was amended which, among other matters, (i) reduced available commitments from $100 million to $90 million, (ii) permitted the Company to redeem a portion of its outstanding Subordinated Debentures, and (iii) reduced the required level 33 34 of refining and marketing cash flow. If the Company's refining and marketing cash flow, as defined, does not meet required levels, the $90 million availability will be incrementally reduced, but not below $80 million. At December 31, 1995, the Company had available commitments under the Facility of $90 million which included a domestic oil and gas reserve component of $40 million. At December 31, 1995, the Company had outstanding letters of credit under the Facility of approximately $50 million and no cash borrowings outstanding, with remaining unused available commitments of $40 million. For the year ended December 31, 1995, the Company's gross borrowings and repayments under the Facility totaled $262 million, averaging approximately $6 million outstanding per day, which were used on a short-term basis to finance working capital requirements and capital expenditures. DEBT AND OTHER OBLIGATIONS On December 1, 1995, the Company redeemed $34.6 million of its outstanding Subordinated Debentures at a price equal to 100% of the principal amount, plus accrued interest to the redemption date. Following this partial redemption, all future sinking fund requirements are satisfied and the Company has $30 million principal amount of Subordinated Debentures outstanding, which is due March 15, 2001 and bears interest at 12-3/4% per annum. The Company's funded debt obligations as of December 31, 1995 also included $44.1 million principal amount of 13% Exchange Notes ("Exchange Notes") which bear interest at 13% per annum, mature December 1, 2000 and have no sinking fund requirements. The Subordinated Debentures and Exchange Notes are redeemable at the option of the Company at 100% of principal amount, plus accrued interest. The Company continuously reviews financing alternatives with respect to its Subordinated Debentures and Exchange Notes. However, there can be no assurance whether or when the Company would propose other refinancings. During 1995, the Company reduced its ratio of long-term debt to capitalization from 54% at year-end 1994 to 42% at year-end 1995. The indenture governing the Subordinated Debentures contains certain covenants, including a restriction that prevents the current payment of cash dividends on Common Stock and currently limits the Company's ability to purchase or redeem any shares of its capital stock. The limitation of dividend payments included in the indenture governing the Exchange Notes is less restrictive than the limitation imposed by the Subordinated Debentures. For further information on redemption provisions and restrictions on dividends, see Note I of Notes to Consolidated Financial Statements in Item 8. Under an agreement reached in 1993, which settled a contractual dispute with the State of Alaska ("State"), the Company paid the State $10.3 million in January 1993 and 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 at the Company's refinery. In 1995, 1994 and 1993, based on a per barrel throughput charge of 16 cents, the Company's variable payments to the State amounted to $2.9 million, $2.8 million and $2.6 million, respectively. The per barrel charge increases to 24 cents in 1996 and 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 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 secured by a mortgage on the Company's 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 Company's refinery. CAPITAL EXPENDITURES Capital spending in 1995 amounted to $64 million, which was funded from available cash reserves, cash flows from operations and borrowings under the Facility. Capital expenditures for the Company's exploration and production segment were approximately $53 million, or 83%, of total capital expenditures. During 1995, the Company participated in the drilling of 17 development wells in the Bob West Field and nine exploratory 34 35 wells in other areas of South Texas. Capital projects for the Company's refining and marketing operations for 1995 totaled $9 million, primarily for capital improvements at the refinery and expansion of the Company's retail locations in Alaska and the Pacific Northwest. For 1996, the Company has under consideration total capital expenditures of approximately $51 million (excluding amounts related to the purchase of Coastwide). The exploration and production segment accounts for $41 million, or 80%, of the budgeted expenditures with $36 million planned for U.S. activities and $5 million for Bolivia. Planned U.S. expenditures include $21 million for exploration, development and acquisition outside of the Bob West Field and $15 million for development of the Bob West Field which the Company expects to substantially complete in 1996. As a result of the sale in September 1995 of certain interests in the Bob West Field, the Company reduced future capital expenditures by approximately $19 million which would otherwise have been required to develop the proved reserves that were sold. In Bolivia, the drilling program includes two exploratory wells, one of which is currently being tested. Capital spending for the refining and marketing segment is projected to be $9 million, which includes amounts for installation of facilities to allow the Company to begin producing and marketing asphalt in Alaska and for improvements and upgrades at the Company's refinery and convenience store operations. Capital expenditures for 1996 are expected to be financed through a combination of cash flows from operations, available cash reserves and borrowings under the Facility. CASH FLOWS FROM OPERATING, INVESTING AND FINANCING ACTIVITIES At December 31, 1995, the Company's net working capital totaled $77.5 million, which included cash and cash equivalents of $13.9 million. For information on litigation related to a natural gas sales contract and the related impact on the Company's cash flows from operations, see "Tennessee Gas Contract" below and Notes N and Q of Notes to Consolidated Financial Statements in Item 8. Components of the Company's cash flows are set forth below (in millions):
1995 1994 1993 ------ ----- ----- Cash Flows From (Used In): Operating Activities..................................... $ 35.4 60.3 21.8 Investing Activities..................................... 2.4 (91.2) (23.4) Financing Activities..................................... (37.9) 8.3 (8.7) ------ ----- ----- Decrease in Cash and Cash Equivalents...................... $ (.1) (22.6) (10.3) ====== ===== =====
During 1995, net cash from operating activities totaled $35 million, compared with $60 million in 1994. 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. Under a settlement agreement entered into in 1993, variable payments to the State totaled $2.9 million in 1995. 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 Subordinated Debentures and other payments of long-term debt. The Company's gross borrowings and repayments under the Facility totaled $262 million during 1995. Net cash from operating activities increased to $60 million in 1994, compared with $22 million in 1993. This increase in cash flows was primarily related to sales of increased natural gas production from the Bob West Field, partially offset by lower prices received for such sales of natural gas and reduced cash flows from the refining and marketing operations. Variable payments to the State totaled $2.8 million in 1994. Net cash used in investing activities of $91 million during 1994 included capital expenditures of $100 million, mainly for exploration and production activities in the Bob West Field and installation of the vacuum unit at the Company's refinery. During 1994, the Company participated in the drilling of 20 development wells and two exploratory wells in the Bob West Field and the expansion of the field's gas processing facilities and pipelines. In addition, the Company participated in the drilling of five exploratory wells and one unsuccessful 35 36 development well in other areas of South Texas. These uses of cash in investing activities in 1994 were partially offset by a net decrease of $6 million in short-term investments and cash proceeds of $3 million from sales of assets. Net cash from financing activities of $8 million during 1994 included $15 million in borrowings under the Vacuum Unit Loan and $4 million net proceeds from an equity offering (see Note H of Notes to Consolidated Financial Statements in Item 8). These financing sources of cash during 1994 were partially offset by the repayment of net borrowings of $5 million under interim financing arrangements early in 1994 and dividends of $2 million paid on preferred stock. During 1994, cash and cash equivalents decreased by $23 million. During 1993, cash and cash equivalents decreased by $10 million. Net cash from operating activities of $22 million in 1993 was primarily due to net earnings adjusted for certain noncash charges, partially offset by payments totaling $12.9 million to the State under a settlement agreement and increased working capital requirements. Net cash used in investing activities of $23 million during 1993 included capital expenditures of $37 million, mainly for exploration and production activities in the Bob West Field. During 1993, the Company completed the expansion of a gas processing facility and pipeline and participated in the drilling of 15 development gas wells in this field. In addition, the Company participated in drilling four exploratory wells and one development well outside of the Bob West Field in 1993. These uses of cash in investing activities were partially offset by a net decrease of $14 million in short-term investments. Net cash used in financing activities of $9 million in 1993 included the repurchase of $11.25 million principal amount of Subordinated Debentures for $9.7 million in cash, partially offset by borrowings of $5 million under interim financing arrangements. The Company did not pay dividends on preferred stocks in 1993. TENNESSEE GAS CONTRACT The Company is selling a portion of the gas produced from its Bob West Field to Tennessee Gas Pipeline Company ("Tennessee Gas") under a Gas Purchase and Sales Agreement ("Tennessee Gas Contract") which provides that the price of gas shall be the maximum price as calculated in accordance with Section 102(b)(2) ("Contract Price") of the Natural Gas Policy Act of 1978 ("NGPA"). In August 1990, Tennessee Gas filed suit against the Company in the District Court of Bexar County, Texas, alleging that the Tennessee Gas Contract is not applicable to the Company's properties and that the gas sales price should be the price calculated under the provisions of Section 101 of the NGPA rather than the Contract Price. During the month of December 1995, the Contract Price was in excess of $8.60 per Mcf and the average spot market price was $1.84 per Mcf. For the year ended December 31, 1995, approximately 17% of the Company's net U.S. natural gas production was sold under the Tennessee Gas Contract. Tennessee Gas also claimed that the contract should be considered an "output contract" under Section 2.306 of the Texas Uniform Commercial Code ("UCC") and that the increases in volumes tendered under the contract exceeded those allowable for an output contract. The District Court judge returned a verdict in favor of the Company on all issues. On appeal by Tennessee Gas, the Court of Appeals for the Fourth Supreme Judicial District of Texas affirmed the validity of the Tennessee Gas Contract as to the Company's properties and held that the price payable by Tennessee Gas for the gas was the Contract Price. The Court of Appeals remanded the case to the trial court based on its determination (i) that the Tennessee Gas Contract was an output contract and (ii) that a fact issue existed as to whether the increases in the volumes of gas tendered to Tennessee Gas under the contract were made in bad faith or were unreasonably disproportionate to prior tenders. The Company sought review of the appellate court ruling on the output contract issue in the Supreme Court of Texas. Tennessee Gas also sought review of the appellate court ruling denying the remaining Tennessee Gas claims in the Supreme Court of Texas. The appellate court decision was the first decision reported in Texas holding that a take-or-pay contract was an output contract. The Supreme Court of Texas heard arguments in December 1994 regarding the output contract issue and certain of the issues raised by Tennessee Gas. On August 1, 1995, the Supreme Court of Texas, in a divided opinion, affirmed the decision of the appellate court on all issues, including that the price under the Tennessee Gas Contract is the Contract Price, and determined that the Tennessee Gas Contract was an output contract and remanded the case to the trial court for determination of whether gas volumes tendered by the Company to Tennessee Gas were tendered in good faith and were not unreasonably 36 37 disproportionate to any normal or otherwise comparable prior output or stated estimates in accordance with the UCC. The Company filed a motion for rehearing before the Texas Supreme Court on the issue of whether the Tennessee Gas Contract is an output contract. The Company believes that, if this issue is tried, the gas volumes tendered to Tennessee Gas will be found to have been in good faith and otherwise in accordance with the requirements of the UCC. However, there can be no assurance as to the ultimate outcome at trial. In conjunction with the District Court judgment and on behalf of all sellers under the Tennessee Gas Contract, Tennessee Gas is presently required to post a supersede as bond in the amount of $206 million. Under the terms of this bond, for the period September 17, 1994 through April 30, 1996, Tennessee Gas is required to take at least its entire monthly take-or-pay obligation and pay for gas taken at $3.00 per Mmbtu, which approximates $3.00 per Mcf ("Bond Price"). The $206 million bond represents an amount which together with anticipated sales of natural gas at the Bond Price will equal the anticipated value of the Tennessee Gas Contract from September 17, 1994 through April 30, 1996. Except for the period September 17, 1994 through August 13, 1995, the difference between the spot market price and the Bond Price is refundable in the event Tennessee Gas ultimately prevails in the litigation. The Company retains the right to receive the Contract Price for all gas sold to Tennessee Gas. Through December 31, 1995, under the Tennessee Gas Contract, the Company recognized cumulative net revenues in excess of spot market prices totaling approximately $117.3 million. Of the $117.3 million incremental net revenues, the Company has received $11.0 million that is nonrefundable and $55.6 million which the Company could be required to repay in the event of an adverse ruling. The remaining $50.7 million of incremental net revenues is classified in the Company's Consolidated Balance Sheet as a noncurrent receivable at December 31, 1995 and represents the unpaid difference between the Contract Price and the Bond Price as described above. An adverse outcome of this litigation could require the Company to reverse as much as $106.3 million of the incremental revenues and could require the Company to repay as much as $55.6 million for amounts received above spot prices, plus interest if awarded by the court. For further information concerning the Tennessee Gas Contract, see Note Q of Notes to Consolidated Financial Statements in Item 8. OTHER MATTERS Environmental The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, which change frequently, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites or install additional controls or other modifications or changes in use for certain emission sources. The Company is currently involved in remedial responses and has incurred cleanup expenditures associated with environmental matters at a number of sites, including certain of its own properties. In addition, the Company is holding discussions with the Department of Justice concerning the assessment of penalties with respect to certain alleged violations of the Clean Air Act. At December 31, 1995, the Company's accruals for environmental matters, including the alleged violations of the Clean Air Act, amounted to $9.9 million. Also included in this amount is a noncurrent liability of approximately $4 million for remediation of the KPL properties, which liability has been funded by the former owners of KPL through a restricted escrow deposit. Based on currently available information and the participation of other parties or former owners in remediation actions, the Company believes these accruals are adequate. In addition, to comply with environmental laws and regulations, the Company anticipates that it will be required to make capital improvements in 1996 of approximately $3 million, primarily for the removal and upgrading of underground storage tanks, and starting in 1996 approximately $8 million for the installation of dike liners; however, the Company is applying for an alternate compliance schedule, allowed for under the Alaska regulations, regarding dike liner installation at the Company's Alaska facilities. This alternate schedule, if granted, will allow the Company additional time to assess an alternate remedy to the dike liner requirement, under Alaska environmental regulations. 37 38 Conditions that require additional expenditures may exist for various Company sites, including, but not limited to, the Company's refinery, retail gasoline outlets (current and closed locations) and petroleum product terminals, and for compliance with the Clean Air Act. The amount of such future expenditures cannot currently be determined by the Company. For further information on environmental contingencies, see Note N of Notes to Consolidated Financial Statements in Item 8 and "Government Regulation and Legislation -- United States -- Environmental Controls" in Item 1. Crude Oil Purchase Contract In 1995, the Company renegotiated a new three-year contract with the State for the purchase of royalty crude oil covering the period January 1, 1996 through December 31, 1998. The new contract provides for the purchase of approximately 40,000 barrels per day of ANS royalty crude oil, the primary feedstock for the Company's refinery, and is priced at the weighted average price reported to the State by a major North Slope producer of ANS crude oil as valued at Pump Station No. 1 on the Trans Alaska Pipeline System. Under this agreement, the Company is required to utilize in its refinery operations volumes equal to at least 80% of the ANS crude oil to be purchased from the State. This contract contains provisions that, under certain conditions, allow the Company to temporarily or permanently reduce its purchase obligations. The Company's previous contract with the State, for the purchase of approximately 40,000 barrels per day of ANS, expired on December 31, 1995. Severance Tax Exemption In February 1996, the Texas Railroad Commission certified substantially all of the Company's reserves in the Bob West Field as high cost gas from a tight formation. As a result of the certification, the Company anticipates that the Texas Comptroller's office will exempt the Company's gas production from tight formations in the Bob West Field from Texas severance taxes. If the severance tax exemption is received from the Comptroller's office, the Company estimates that the pretax present value of proved reserves as of December 31, 1995 will increase by approximately $7.7 million and that the Company could be eligible for a refund and tax credits for prior taxes paid of approximately $6 million. The potential refund and tax credits have not been recorded in the Company's financial statements. There is no assurance that the Company will receive the exemption or related refund or tax credits. For further information on the Company's reserves and standardized measure, see Note Q of Notes to Consolidated Financial Statements in Item 8. Other As discussed in Note N of Notes to Consolidated Financial Statements in Item 8, the Company is involved with other litigation and claims, none of which are expected to have a material adverse effect on the financial condition of the Company. RECENTLY ISSUED PRONOUNCEMENTS The Company has adopted Statement of Financial Accounting Standards ("SFAS") No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," which had no material impact on the Company's financial condition or results of operations in 1995. In October 1995, SFAS No. 123, "Accounting for Stock-Based Compensation," was issued which addresses the measurement of compensation expense for the issuance of stock options. The Company has evaluated SFAS No. 123 and intends to continue following APB Opinion No. 25 for expense recognition purposes, but will expand its disclosures regarding the fair value of issuance of stock options as required by SFAS No. 123 effective for the year ended December 31, 1996. 38 39 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, 1995 and 1994, and the related statements of consolidated operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 1995. 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, 1995 and 1994, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1995, in conformity with generally accepted accounting principles. DELOITTE & TOUCHE LLP San Antonio, Texas February 2, 1996 (February 20, 1996 as to Notes B and N) 39 40 TESORO PETROLEUM CORPORATION STATEMENTS OF CONSOLIDATED OPERATIONS (IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
YEARS ENDED DECEMBER 31, ------------------------------ 1995 1994 1993 ---------- ------- ------- REVENUES Refining and marketing........................................ $ 771,035 686,994 687,231 Exploration and production.................................... 124,670 103,773 62,038 Marine services............................................... 74,467 77,917 80,699 Gain on sales of assets and other............................. 32,711 3,259 456 ---------- ------- ------- Total Revenues........................................ 1,002,883 871,943 830,424 ---------- ------- ------- OPERATING COSTS AND EXPENSES Refining and marketing........................................ 758,329 676,697 662,133 Exploration and production.................................... 19,055 15,302 10,171 Marine services............................................... 77,803 80,507 84,050 Depreciation, depletion and amortization...................... 41,776 35,041 21,793 ---------- ------- ------- Total Operating Costs and Expenses.................... 896,963 807,547 778,147 ---------- ------- ------- OPERATING PROFIT................................................ 105,920 64,396 52,277 General and Administrative...................................... (16,453) (14,750) (16,712) Interest Expense, Net of Capitalized Interest................... (20,902) (18,749) (14,550) Interest Income................................................. 1,845 2,522 1,803 Other Expense, Net.............................................. (8,542) (7,363) (4,165) ---------- ------- ------- EARNINGS BEFORE INCOME TAXES AND EXTRAORDINARY LOSS ON EXTINGUISHMENT OF DEBT....................................................... 61,868 26,056 18,653 Income Tax Provision............................................ 4,379 5,573 1,697 ---------- ------- ------- EARNINGS BEFORE EXTRAORDINARY LOSS ON EXTINGUISHMENT OF DEBT.... 57,489 20,483 16,956 Extraordinary Loss on Extinguishment of Debt.................... (2,857) (4,752) -- ---------- ------- ------- NET EARNINGS.................................................... 54,632 15,731 16,956 Dividend Requirements on Preferred Stock........................ -- 2,680 9,207 ---------- ------- ------- NET EARNINGS APPLICABLE TO COMMON STOCK......................... $ 54,632 13,051 7,749 ========== ======= ======= EARNINGS PER SHARE Earnings Before Extraordinary Loss on Extinguishment of Debt....................................................... $ 2.29 .77 .54 Extraordinary Loss on Extinguishment of Debt.................. (.11) (.21) -- ---------- ------- ------- Net Earnings.................................................. $ 2.18 .56 .54 ========== ======= ======= WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES............ 25,107 23,196 14,290 ========== ======= =======
The accompanying notes are an integral part of these consolidated financial statements. 40 41 TESORO PETROLEUM CORPORATION CONSOLIDATED BALANCE SHEETS (DOLLARS IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
DECEMBER 31, ------------------ 1995 1994 -------- ------- ASSETS CURRENT ASSETS Cash and cash equivalents............................................... $ 13,941 14,018 Receivables, less allowance for doubtful accounts....................... 77,534 91,140 Inventories............................................................. 80,453 68,302 Prepayments and other................................................... 10,536 8,648 -------- ------- Total Current Assets............................................ 182,464 182,108 -------- ------- PROPERTY, PLANT AND EQUIPMENT Refining and marketing.................................................. 322,023 309,925 Exploration and production, full cost method of accounting: Properties being amortized........................................... 119,836 131,930 Properties not yet evaluated......................................... 5,118 3,758 Gas transportation................................................... 6,703 6,543 Marine services......................................................... 12,757 14,689 Corporate............................................................... 12,443 12,271 -------- ------- 478,880 479,116 Less accumulated depreciation, depletion and amortization............ 217,191 205,782 -------- ------- Net Property, Plant and Equipment............................... 261,689 273,334 -------- ------- RECEIVABLE FROM TENNESSEE GAS PIPELINE COMPANY............................ 50,680 -- -------- ------- OTHER ASSETS.............................................................. 24,320 28,918 -------- ------- Total Assets............................................... $519,153 484,360 ======== ======= LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES Accounts payable........................................................ $ 61,389 53,573 Accrued liabilities..................................................... 34,073 35,266 Current portion of long-term debt and other obligations................. 9,473 7,404 -------- ------- Total Current Liabilities....................................... 104,935 96,243 -------- ------- OTHER LIABILITIES......................................................... 42,697 35,175 -------- ------- LONG-TERM DEBT AND OTHER OBLIGATIONS, LESS CURRENT PORTION................ 155,007 192,210 -------- ------- COMMITMENTS AND CONTINGENCIES (Notes M and N) STOCKHOLDERS' EQUITY Preferred stock, no par value; authorized 5,000,000 shares including redeemable preferred shares; none issued or outstanding Common stock, par value $.16 2/3; authorized 50,000,000 shares; 24,780,134 shares issued and outstanding (24,389,801 in 1994)........ 4,130 4,065 Additional paid-in capital.............................................. 176,599 175,514 Retained earnings (accumulated deficit)................................. 35,785 (18,847) -------- ------- Total Stockholders' Equity...................................... 216,514 160,732 -------- ------- Total Liabilities and Stockholders' Equity................. $519,153 484,360 ======== =======
The accompanying notes are an integral part of these consolidated financial statements. 41 42 TESORO PETROLEUM CORPORATION STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY (IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
$2.20 $2.16 CUMULATIVE CUMULATIVE CONVERTIBLE CONVERTIBLE RETAINED PREFERRED PREFERRED EARNINGS STOCK STOCK COMMON STOCK ADDITIONAL (ACCUMU- ----------------- ---------------- --------------- PAID-IN LATED SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT CAPITAL DEFICIT) ------ -------- ------ ------- ------ ------ ---------- -------- DECEMBER 31, 1992........ -- $ -- 1,320 $ 1,320 14,071 $2,345 $ 86,647 $(39,647) Net earnings........... -- -- -- -- -- -- -- 16,956 Accrued dividends on preferred stocks.... -- -- -- -- -- -- -- (9,175) Stock awards and options............. -- -- -- -- 18 3 101 (32) ------ -------- ------ ------- ------ ------ -------- -------- DECEMBER 31, 1993........ -- -- 1,320 1,320 14,089 2,348 86,748 (31,898) Net earnings........... -- -- -- -- -- -- -- 15,731 Accrued dividends on preferred stocks.... -- -- -- -- -- -- -- (2,680) Reclassification of $2.16 Preferred Stock and accrued and unpaid dividends thereon into Common Stock............... -- -- (1,320) (1,320) 6,598 1,099 9,670 -- Issuance of Common Stock in connection with reclassification of $2.20 Preferred Stock and accrued dividends thereon into equity......... 2,875 57,500 -- -- 1,900 317 20,914 -- Costs of Recapitalization.... -- -- -- -- -- -- (3,327) -- Offering, net.......... -- -- -- -- 5,851 975 55,992 -- Exercise of MetLife Louisiana Option.... (2,875) (57,500) -- -- (4,084) (681) 5,232 -- Stock awards and options............. -- -- -- -- 36 7 285 -- ------ -------- ------ ------- ------ ------ -------- -------- DECEMBER 31, 1994........ -- -- -- -- 24,390 4,065 175,514 (18,847) Net earnings........... -- -- -- -- -- -- -- 54,632 Stock awards and options............. -- -- -- -- 390 65 1,085 -- ------ -------- ------ ------- ------ ------ -------- -------- DECEMBER 31, 1995........ -- $ -- -- $ -- 24,780 $4,130 $ 176,599 $ 35,785 ====== ======== ====== ======= ====== ====== ======== ========
The accompanying notes are an integral part of these consolidated financial statements. 42 43 TESORO PETROLEUM CORPORATION STATEMENTS OF CONSOLIDATED CASH FLOWS (IN THOUSANDS)
YEARS ENDED DECEMBER 31, ---------------------------- 1995 1994 1993 -------- ------- ------- CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES Net earnings................................................... $ 54,632 15,731 16,956 Adjustments to reconcile net earnings to net cash from operating activities: Depreciation, depletion and amortization.................... 42,620 36,016 22,591 Loss (gain) on extinguishment of debt....................... 2,857 4,752 (1,422) Gain on sales of assets..................................... (32,659) (2,379) (60) Amortization of deferred charges and other.................. 1,556 2,800 3,323 Changes in operating assets and liabilities: Receivable from Tennessee Gas Pipeline Company............ (37,456) (13,224) -- Receivables, other trade.................................. 9,746 (7,279) 7,539 Inventories............................................... (11,599) 5,884 325 Other assets.............................................. (1,133) (1,808) (3,609) Accounts payable and accrued liabilities.................. 4,605 20,567 (12,800) Obligation payments to State of Alaska.................... (2,892) (2,754) (12,910) Other liabilities and obligations......................... 5,136 1,991 1,901 -------- ------- ------- Net cash from operating activities..................... 35,413 60,297 21,834 -------- ------- ------- CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES Capital expenditures........................................... (63,930) (99,587) (37,451) Proceeds from sales of assets.................................. 69,786 2,544 194 Sales of short-term investments................................ -- 7,926 40,314 Purchases of short-term investments............................ -- (1,974) (26,245) Other.......................................................... (3,452) (50) (247) -------- ------- ------- Net cash from (used in) investing activities........... 2,404 (91,141) (23,435) -------- ------- ------- CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES Repurchase of debentures....................................... (34,634) -- (9,675) Payments of long-term debt..................................... (2,979) (1,383) (1,643) Net borrowings (repayments) under revolving credit facilities.................................................. -- (5,000) 5,000 Issuance of long-term debt..................................... -- 15,000 -- Proceeds from issuance of common stock, net.................... -- 56,967 -- Repurchase of common and preferred stock....................... -- (52,948) -- Dividends on preferred stocks.................................. -- (1,684) -- Costs of Recapitalization and other............................ (281) (2,686) (2,354) -------- ------- ------- Net cash from (used in) financing activities........... (37,894) 8,266 (8,672) -------- ------- ------- DECREASE IN CASH AND CASH EQUIVALENTS............................ (77) (22,578) (10,273) CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR................... 14,018 36,596 46,869 -------- ------- ------- CASH AND CASH EQUIVALENTS AT END OF YEAR......................... $ 13,941 14,018 36,596 ======== ======= ======= SUPPLEMENTAL CASH FLOW DISCLOSURES Interest paid, net of $915 capitalized in 1994................. $ 18,132 15,898 19,288 ======== ======= ======= Income taxes paid.............................................. $ 4,046 5,361 5,125 ======== ======= =======
The accompanying notes are an integral part of these consolidated financial statements. 43 44 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE A -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Tesoro Petroleum Corporation is a natural resource company engaged in petroleum refining and marketing, natural gas exploration and production, and marine services. PRINCIPLES OF CONSOLIDATION AND PRESENTATION The Consolidated Financial Statements include the accounts of Tesoro Petroleum Corporation and its subsidiaries (collectively, the "Company" or "Tesoro") after elimination of significant intercompany balances and transactions. The preparation of these Consolidated Financial Statements required the use of management's best estimates and judgment that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the year. Actual results could differ from those estimates. Certain previously reported amounts have been reclassified to conform with the 1995 presentation. 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 The Company follows the lower of cost (last-in, first-out basis -- LIFO) or market method for valuing inventories of crude oil and wholesale refined products. All other inventories are valued principally at the lower of cost (generally on a first-in, first-out or weighted-average basis) or market. PROPERTY, PLANT AND EQUIPMENT The annual provisions for depreciation on the Company's property, plant and equipment have been computed in accordance with the following ranges of rates: Refining and Marketing............................................ 3 years to 33 years Exploration and Production........................................ 3 years to 25 years Marine Services................................................... 3 years to 45 years Corporate......................................................... 3 years to 20 years
The Company uses the full-cost method of accounting for oil and gas properties. 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 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. 44 45 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Assets recorded under capital leases have been capitalized in accordance with promulgations from the Financial Accounting Standards Board. Amortization of such assets is recorded over the shorter of lease terms or useful lives under methods that are consistent with the Company's depreciation policy for owned assets. Depreciation of other property is provided using primarily the straight-line method with rates based on the estimated useful lives of the properties and with an estimated salvage value of generally 20% for refinery assets and 10% for other assets. Amortization of leasehold improvements is provided using the straight-line method over the term of the respective lease or the useful life of the asset, whichever period is less. INCOME TAXES Deferred tax assets and liabilities are recognized for future income tax consequences attributable to differences between financial statement carrying amounts of existing 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 income 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. Estimated liabilities are not discounted to present value. Generally, the timing of these accruals coincides with completion of a feasibility study or the Company's commitment to a formal plan of action. 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, including publicly-traded issues, approximated the Company's estimates of the fair value of such items. EARNINGS PER SHARE Primary earnings per share is calculated on net earnings after deducting dividend requirements on preferred stocks and is based on the weighted average number of common and common equivalent shares outstanding during the period. Fully diluted earnings per share was the same as primary earnings per share since the assumed conversion of preferred stocks in 1994 and 1993 to common shares would be anti-dilutive. RECENTLY ISSUED PRONOUNCEMENTS The Company adopted Statement of Financial Accounting Standards ("SFAS") No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," which had no material impact on the Company's financial condition or results of operations in 1995. 45 46 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) In October 1995, SFAS No. 123, "Accounting for Stock-Based Compensation," was issued which addresses the measurement of compensation expense for the issuance of stock options. The Company has evaluated SFAS No. 123 and intends to continue following APB Opinion No. 25 for expense recognition purposes, but will expand its disclosures regarding the fair value of issuance of stock options as required by SFAS No. 123 effective for the year ended December 31, 1996. NOTE B -- ACQUISITIONS AND DIVESTITURES 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. These units do not include acreage related to the Company's natural gas sales contract with Tennessee Gas Pipeline Company, which, as discussed in Note N, is the subject of current litigation. Also 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. Through the date of the sale, natural gas production from the interests sold had contributed approximately $11 million to revenues and $4 million to operating profit of the Company's Exploration and Production segment for 1995. For information regarding changes in proved domestic reserves, see Note Q. Consideration for the sale was $74 million, which was adjusted on a preliminary basis 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, which is subject to final post-closing adjustments, was used to redeem $34.6 million of the Company's outstanding 12 3/4% Subordinated Debentures, reduce borrowings under the Company's Revolving Credit Facility and improve corporate liquidity (see Note I). The Company does not expect any final post-closing adjustments to be material. In February 1996, the Company purchased 100% of the capital stock of Coastwide Energy Services, Inc. ("Coastwide"). At closing, the consideration for the stock of Coastwide includes 946,883 shares of Tesoro's Common Stock and $5.9 million in cash. The market price of Tesoro's Common Stock was $9.00 per share at closing of this transaction. Upon exchange of Coastwide's remaining warrants, options and convertible debentures, the Company will issue approximately 440,000 additional shares of Tesoro's Common Stock and pay $1.8 million in cash. Coastwide is primarily a provider of services and a wholesale distributor of diesel fuel and lubricants to the offshore drilling industry in the Gulf of Mexico. The Company will combine its existing marine petroleum distribution operations with Coastwide, forming a Marine Services segment. The acquisition of Coastwide will be accounted for as a purchase in the first quarter of 1996. Accordingly, the purchase price will be allocated to the net assets acquired based upon their estimated fair values. In March 1995, the Company acquired all of the outstanding stock of Kenai Pipe Line Company ("KPL") for approximately $3 million cash. The Company transports its crude oil and a substantial portion of its refined products utilizing KPL's pipeline and marine terminal facilities in Kenai, Alaska. The acquisition was accounted for using the purchase method. NOTE C -- BUSINESS SEGMENTS The Company's revenues are derived from three business segments: Refining and Marketing, Exploration and Production, and Marine Services. Refining and Marketing includes the operations of the Company's refinery in Kenai, Alaska, which produces gasoline, jet fuel, diesel fuel, heavy oils and residual product. These products, together with other purchased products, are sold primarily at wholesale through terminal facilities and other locations in Alaska, California and the Pacific Northwest. In addition, Refining and Marketing sells gasoline, petroleum products 46 47 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) and convenience store items at retail through a chain of 7-Eleven convenience stores in Alaska. To optimize the refinery's feedstock mix and in response to market conditions, the Company at times resells previously purchased crude oil. These crude oil resales amounted to $75.8 million, $72.3 million and $62.1 million in 1995, 1994 and 1993, respectively. From time to time, Refining and Marketing exports products to customers in Far East markets. Revenues from such export sales amounted to $18.5 million, $5.2 million and $20.5 million in 1995, 1994 and 1993, respectively. Exploration and Production is engaged in the exploration, development and production of natural gas, primarily in the Wilcox Trend in South Texas and the Chaco Basin in Bolivia. The majority of the Company's South Texas production currently comes from the Bob West Field. See Notes N and Q for information regarding a natural gas sales contract in the Bob West Field that is the subject of litigation. In addition to natural gas producing activities, Exploration and Production activities include the transportation of natural gas to common carrier pipelines in the South Texas area, including transportation of the Company's production. In Bolivia, the Company operates through an interest in a joint venture agreement to explore for and produce hydrocarbons. The majority of the Company's Bolivian natural gas and condensate reserves are shut-in awaiting access to gas-consuming markets. Marine Services, which includes operations previously reported as Oil Field Supply and Distribution, is involved with the wholesale marketing of fuels, lubricants and specialty petroleum products, primarily to onshore and offshore drilling contractors along the Texas and Louisiana Gulf Coast area. During 1995, the Company consolidated certain operations in this segment by exiting the land-based portion of its petroleum product distribution business. In 1994, the Company discontinued its environmental remediation products and services operations formerly associated with this segment. With the recent acquisition of Coastwide discussed in Note B, the Company will combine its remaining marine petroleum distribution operations with Coastwide, forming a Marine Services segment which will provide a broad range of products and logistical support services to the offshore drilling and drilling-related businesses operating in the Gulf of Mexico. Segment operating profit is gross operating revenues and gains on asset sales 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. Operating profit from the Exploration and Production segment in 1995 included a gain of approximately $33 million from the sale of certain interests in the Bob West Field. Operating profit from the Refining and Marketing segment in 1994 included a gain of $2.4 million from the sale of assets and a refund of $8.5 million for a tariff issue, partially offset by net charges of approximately $5 million for environmental contingencies and other matters. Revenues previously reported for U.S. oil and gas and transportation operations have been restated for certain reclassifications between revenues and operating expenses. 47 48 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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.
YEARS ENDED DECEMBER 31, -------------------------- 1995 1994 1993 ------ ----- ----- (IN MILLIONS) GROSS OPERATING REVENUES Refining and Marketing -- Refined products.............................................. $664.5 582.7 590.9 Other, primarily crude oil resales and merchandise............ 106.5 104.3 96.3 Exploration and Production -- U.S. oil and gas.............................................. 107.3 87.5 48.4 U.S. gas transportation....................................... 5.7 3.1 1.0 Bolivia....................................................... 11.7 13.2 12.6 Marine Services.................................................. 74.5 77.9 80.7 ------ ----- ----- Total Gross Operating Revenues........................... $970.2 868.7 829.9 ====== ===== ===== OPERATING PROFIT (LOSS), INCLUDING GAIN ON SALES OF ASSETS Refining and Marketing........................................... $ .7 2.4 15.2 Exploration and Production -- U.S. oil and gas.............................................. 96.9 52.1 31.4 U.S. gas transportation....................................... 5.1 2.9 .9 Bolivia....................................................... 7.6 9.3 8.4 Marine Services.................................................. (4.4) (2.3) (3.6) ------ ----- ----- Total Operating Profit................................... 105.9 64.4 52.3 Corporate and Unallocated Costs.................................. (44.0) (38.3) (33.6) ------ ----- ----- Earnings Before Income Taxes and Extraordinary Loss.............. $ 61.9 26.1 18.7 ====== ===== ===== IDENTIFIABLE ASSETS Refining and Marketing........................................... $313.3 309.1 281.5 Exploration and Production -- U.S. oil and gas.............................................. 128.9 105.5 65.2 U.S. gas transportation....................................... 7.8 8.4 2.0 Bolivia....................................................... 17.8 11.1 6.5 Marine Services.................................................. 18.0 19.8 21.3 Corporate........................................................ 33.4 30.5 58.0 ------ ----- ----- Total Assets............................................. $519.2 484.4 434.5 ====== ===== ===== DEPRECIATION, DEPLETION AND AMORTIZATION Refining and Marketing........................................... $ 11.9 10.4 10.3 Exploration and Production -- U.S. oil and gas.............................................. 29.0 24.1 11.1 U.S. gas transportation....................................... .3 .2 -- Bolivia....................................................... .3 -- -- Marine Services.................................................. .3 .3 .4 Corporate........................................................ .8 1.0 .8 ------ ----- ----- Total Depreciation, Depletion and Amortization........... $ 42.6 36.0 22.6 ====== ===== =====
48 49 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
YEARS ENDED DECEMBER 31, -------------------------- 1995 1994 1993 ------ ----- ----- (IN MILLIONS) CAPITAL EXPENDITURES Refining and Marketing........................................... $ 9.3 32.0 7.1 Exploration and Production -- U.S. oil and gas.............................................. 49.4 60.4 28.6 U.S. gas transportation....................................... .2 5.2 .7 Bolivia....................................................... 3.8 -- -- Marine Services.................................................. .4 .2 .3 Corporate........................................................ .8 1.8 .8 ------ ----- ----- Total Capital Expenditures............................... $ 63.9 99.6 37.5 ====== ===== =====
NOTE D -- 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 (in thousands):
YEARS ENDED DECEMBER 31, -------------------------- 1995 1994 1993 ------ ----- ----- Balance at Beginning of Year............................... $1,816 2,487 2,587 Charged to Costs and Expenses.............................. 300 299 667 Recoveries of Amounts Previously Written Off and Other..... 122 (4) 71 Write-off of Doubtful Accounts............................. (396) (966) (838) ------ ----- ----- Balance at End of Year................................... $1,842 1,816 2,487 ====== ===== =====
Receivables at December 31, 1994 included $13.2 million for sales under a natural gas sales contract that is the subject of litigation, representing the difference between a contract price and the price being received by the Company under the terms of a court-ordered bonding arrangement. At December 31, 1995, a receivable of $50.7 million related to this contract was classified as noncurrent. For further information on this litigation, see Notes N and Q. NOTE E -- INVENTORIES Components of inventories at December 31, 1995 and 1994 were as follows (in thousands):
DECEMBER 31, ------------------- 1995 1994 ------- ------- Crude Oil and Wholesale Refined Products, at LIFO....................... $70,406 58,798 Merchandise and Retail Refined Products................................. 5,153 5,934 Materials and Supplies.................................................. 4,894 3,570 ------ ----- Inventories........................................................... $80,453 68,302 ======= ======
49 50 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) At December 31, 1995 and 1994, inventories valued using LIFO were lower than replacement cost by approximately $3.8 million and $1.8 million, respectively. NOTE F -- ACCRUED LIABILITIES The Company's current accrued liabilities as shown in the Consolidated Balance Sheets included the following (in thousands):
DECEMBER 31, ------------------ 1995 1994 ------- ------ Accrued Environmental Costs....................................... $ 5,935 10,829 Accrued Interest.................................................. 2,879 4,223 Accrued Employee and Pension Costs................................ 6,839 7,884 Accrued Taxes..................................................... 3,910 3,242 Other............................................................. 14,510 9,088 ------- ------ Accrued Liabilities............................................. $34,073 35,266 ======= ======
Other liabilities classified as noncurrent in the Consolidated Balance Sheets consisted of the following (in thousands):
DECEMBER 31, ------------------ 1995 1994 ------- ------ Accrued Postretirement Benefits................................... $28,706 26,131 Deferred Income Taxes............................................. 5,389 4,582 Accrued Environmental Costs....................................... 3,968 -- Other............................................................. 4,634 4,462 ------- ------ Other Liabilities............................................... $42,697 35,175 ======= ======
NOTE G -- INCOME TAXES The income tax provision included the following (in thousands):
YEARS ENDED DECEMBER 31, --------------------------- 1995 1994 1993 ------ ----- ------ Federal -- Current........................................ $ 708 700 -- Foreign................................................... 3,183 3,588 3,419 State..................................................... 488 1,285 (1,722) ------ ----- ------ Income Tax Provision.................................... $4,379 5,573 1,697 ====== ===== ======
50 51 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Deferred income taxes and benefits are provided for differences between financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Temporary differences and the resulting deferred tax assets and liabilities are summarized as follows (in thousands):
DECEMBER 31, -------------------- 1995 1994 -------- ------- Deferred Tax Assets: Net operating losses available for utilization through the year 2008.................................................. $ 29,695 16,921 Investment tax and other credits.............................. 9,762 8,196 Accrued postretirement benefits............................... 9,424 8,865 Settlement with the State of Alaska........................... 810 21,650 Settlement with Department of Energy.......................... 3,981 4,443 Other......................................................... 8,594 8,994 -------- ------- Total Deferred Tax Assets............................. 62,266 69,069 Deferred Tax Liabilities: Receivable related to gas contract............................ (17,699) -- Accelerated depreciation and property-related items........... (39,734) (43,621) -------- ------- Deferred Tax Assets Before Valuation Allowance.................. 4,833 25,448 Valuation Allowance............................................. (4,833) (25,448) State Income and Other Taxes.................................... (5,389) (4,332) Other........................................................... -- (250) -------- ------- Net Deferred Tax Liability............................ $ (5,389) (4,582) ======== =======
The following tables set forth the components of the Company's results of operations and a reconciliation of the normal statutory federal income tax with the provision for income taxes (in thousands):
YEARS ENDED DECEMBER 31, ------------------------------ 1995 1994 1993 -------- ------ ------ Earnings Before Income Taxes and Extraordinary Loss: United States........................................ $ 55,221 18,336 10,906 Foreign.............................................. 6,647 7,720 7,747 -------- ------ ------ $ 61,868 26,056 18,653 ======== ====== ====== Income Taxes at Statutory U.S. Corporate Tax Rate...... $ 21,654 9,120 6,529 Effect of: Foreign income taxes................................. 3,183 3,588 3,419 State income taxes (benefit)......................... 488 1,285 (1,722) Accounting recognition of operating loss tax benefits.......................................... (20,615) (9,120) (6,529) Other................................................ (331) 700 -- -------- ------ ------ Income Tax Provision................................. $ 4,379 5,573 1,697 ======== ====== ======
At December 31, 1995, the Company's net operating loss carryforwards were approximately $84.8 million for regular tax and approximately $71.0 million for alternative minimum tax. These tax loss carryforwards are available for future years and, if not used, will begin to expire in the year 2007. Also at December 31, 1995, the Company had approximately $8.2 million of investment tax credits and employee stock ownership credits available for carryover to subsequent years. These credits, if not used, will begin to expire in the year 2001. Additionally, at December 31, 1995, the Company had approximately $1.6 million of alternative minimum tax credit carryforwards to offset future regular tax liabilities. There is no expiration date for these credits. 51 52 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) During 1993, the Company resolved several outstanding issues with state taxing authorities resulting in a reduction of $3.0 million in state income tax expense and $5.2 million in related interest expense. NOTE H -- RECAPITALIZATION AND EQUITY OFFERING RECAPITALIZATION In 1994, the Company consummated exchange offers and adopted amendments to its Restated Certificate of Incorporation pursuant to which the Company's outstanding debt and preferred stocks were restructured (the "Recapitalization"). Significant components of the Recapitalization, together with a further redemption of debt in 1995, were as follows: (i) The Company in February 1994 exchanged $44.1 million principal amount of new 13% Exchange Notes ("Exchange Notes") due December 1, 2000 for a like principal amount of 12 3/4% Subordinated Debentures ("Subordinated Debentures") due March 15, 2001. This exchange, together with the redemption of $34.6 million of Subordinated Debentures in 1995, has satisfied all future sinking fund requirements resulting in $30 million principal amount of Subordinated Debentures due in 2001 (see Note I). The exchange of the Subordinated Debentures in 1994 and redemption in 1995 were accounted for as early extinguishments of debt, resulting in charges in 1995 and 1994 of $2.9 million and $4.8 million, respectively, which represented write-offs of unamortized bond discount and issue costs. No tax benefits were available to offset the extraordinary losses as the Company has provided a 100% valuation allowance to the extent of its deferred tax assets. (ii) The 1,319,563 outstanding shares of the Company's $2.16 Cumulative Convertible Preferred Stock ("$2.16 Preferred Stock"), which had a $25 per share liquidation preference, plus accrued and unpaid dividends aggregating $9.5 million at February 9, 1994, were reclassified into 6,465,859 shares of Common Stock. The Company also issued an additional 132,416 shares of Common Stock on behalf of the holders of $2.16 Preferred Stock in connection with the settlement of litigation related to the reclassification of the $2.16 Preferred Stock. In addition, the Company paid $.5 million for certain legal fees and expenses in connection with such litigation. The reclassification of the $2.16 Preferred Stock eliminated annual preferred dividend requirements of $2.9 million on the $2.16 Preferred Stock. The issuance of the Common Stock in connection with the reclassification and settlement of litigation that was recorded in 1994 resulted in an increase in Common Stock of approximately $1 million, equal to the aggregate par value of the Common Stock issued, and an increase in additional paid-in capital of approximately $9 million. (iii) The Company and MetLife Security Insurance Company of Louisiana ("MetLife Louisiana"), the holder of all of the Company's outstanding $2.20 Cumulative Convertible Preferred Stock ("$2.20 Preferred Stock"), entered into an agreement in 1994 pursuant to which MetLife Louisiana agreed, among other matters, to waive all existing mandatory redemption requirements, to consider all accrued and unpaid dividends on the $2.20 Preferred Stock (aggregating $21.2 million at February 9, 1994) to have been paid, and to grant to the Company a three-year option (the "MetLife Louisiana Option") to purchase all of MetLife Louisiana's holdings of $2.20 Preferred Stock and Common Stock for approximately $53 million prior to June 30, 1994 (after giving effect to the cash dividend on the $2.20 Preferred Stock paid in May 1994), all in consideration for, among other things, the issuance by the Company to MetLife Louisiana of 1,900,075 shares of Common Stock. Such additional shares were also subject to the MetLife Louisiana Option. These actions resulted in the reclassification of the $2.20 Preferred Stock into equity capital at its aggregate liquidation preference of $57.5 million and the recording of an increase in additional paid-in capital of approximately $21 million in February 1994. 52 53 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) EQUITY OFFERING In June 1994, the Company completed a public offering (the "Offering") of 5,850,000 shares of its Common Stock for the purpose of raising funds to exercise the MetLife Louisiana Option. Net proceeds to the Company from the Offering, after deduction of associated expenses, were approximately $57.0 million. On June 29, 1994, the Company exercised the MetLife Louisiana Option in full for approximately $53.0 million, acquiring 2,875,000 shares of $2.20 Preferred Stock having a liquidation value of $57.5 million and 4,084,160 shares of Common Stock having an aggregate market value of $45.9 million (based on a closing price of $11.25 per share on June 28, 1994). The exercise eliminated annual preferred dividend requirements of $6.3 million on the $2.20 Preferred Stock. The Offering and the exercise in full of the MetLife Louisiana Option resulted in a net increase of 1,765,840 outstanding shares of Common Stock, the retirement of $57.5 million of the $2.20 Preferred Stock, and increases in Common Stock of approximately $.3 million, additional paid-in capital of approximately $61.2 million and cash of approximately $4.0 million in June 1994. See Note I for information on the Company's long-term debt, including restrictions on dividend payments. NOTE I -- LONG-TERM DEBT AND OTHER OBLIGATIONS Long-term debt and other obligations consisted of the following (in thousands):
DECEMBER 31, -------------------- 1995 1994 -------- ------- 12 3/4% Subordinated Debentures due 2001........................ $ 27,806 59,146 13% Exchange Notes due 2000..................................... 44,116 44,116 Liability to State of Alaska.................................... 62,313 61,856 Vacuum Unit Loan................................................ 13,393 15,000 Liability to Department of Energy............................... 11,874 13,194 Industrial Revenue Bonds........................................ 1,654 2,385 Capital Lease Obligations (interest at 11%)..................... 2,693 3,540 Other........................................................... 631 377 -------- ------- 164,480 199,614 Less Current Portion............................................ 9,473 7,404 -------- ------- $155,007 192,210 ======== =======
Aggregate maturities of long-term debt and obligations for each of the five years following December 31, 1995 are as follows (in thousands): 1996............................................................. $9,473 1997............................................................. $9,963 1998............................................................. $9,594 1999............................................................. $9,581 2000............................................................. $9,795
REVOLVING CREDIT FACILITY The Company has financing and credit arrangements under a three-year corporate Revolving Credit Facility ("Facility") dated April 20, 1994, with a consortium of ten banks. The Facility, which is subject to a borrowing base, provides for (i) the issuance of letters of credit up to the full amount of the borrowing base and (ii) cash borrowings up to the amount of the borrowing base attributable to domestic oil and gas reserves. Outstanding obligations under the Facility are secured by liens on substantially all of the Company's trade accounts receivable and product inventory and by mortgages on the Company's refinery and South Texas 53 54 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) natural gas reserves. Under the terms of the Facility, which has been amended from time to time, the Company is required to maintain specified levels of working capital, tangible net worth, consolidated cash flow and refining and marketing cash flow, as defined. Among other matters, the Facility contains certain restrictions with respect to (i) capital expenditures, (ii) incurrence of additional indebtedness, and (iii) dividends on capital stock. The Facility contains other covenants customary in credit arrangements of this kind. Future compliance with certain financial covenants is primarily dependent on the Company's maintenance of specified levels of cash flows from operations, capital expenditures, levels of borrowings and the value of the Company's domestic oil and gas reserves. In October 1995, the Facility was amended which, among other matters, (i) reduced available commitments from $100 million to $90 million, (ii) permitted the Company to redeem a portion of its outstanding Subordinated Debentures, and (iii) reduced the required level of refining and marketing cash flow. If the Company's refining and marketing cash flow, as defined, does not meet required levels, the $90 million availability will be incrementally reduced, but not below $80 million. At December 31, 1995, the Company had available commitments under the Facility of $90 million which included a domestic oil and gas reserve component of $40 million. At December 31, 1995, the Company had outstanding letters of credit under the Facility of approximately $50 million and no cash borrowings outstanding, with remaining unused available commitments of $40 million. For the year ended December 31, 1995, the Company's gross borrowings and repayments under the Facility totaled $262 million, averaging approximately $6 million outstanding per day, which were used on a short-term basis to finance working capital requirements and capital expenditures. Under the Facility, cash borrowings are limited to the amount of the domestic oil and gas reserve component of the borrowing base, which has most recently been determined to be approximately $40 million. The oil and gas component of the borrowing base is redetermined at least semi-annually. The lenders or the Company may request additional redeterminations. Fees on outstanding letters of credit range from 1.25% to 2.25% per annum, depending upon the Company's fixed charge coverage ratio, as defined, while the excess of total available commitments over cash borrowings and outstanding letters of credit incur fees of one-half of 1% per annum. Cash borrowings under the Facility will reduce the availability of letters of credit on a dollar-for- dollar basis; however, letter of credit issuances will not reduce cash borrowing availability unless the aggregate dollar amount of outstanding letters of credit exceeds the sum of the accounts receivable and inventory components of the borrowing base. Cash borrowings bear interest at (i) the higher of the prime rate, as defined, or the federal funds rate, as defined, plus an additional percentage ranging from one-fourth of 1% to 1.25%, or (ii) the Eurodollar rate, as defined, plus an additional percentage ranging from 1.25% to 2.25%, depending upon the Company's cash flow coverage ratio, as defined in the Facility. VACUUM UNIT LOAN In 1994, the National Bank of Alaska and the Alaska Industrial Development & Export Authority provided a loan to the Company of up to $15 million of the cost of the vacuum unit for the Company's refinery (the "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 (8.42% at December 31, 1995) 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, 1995) for the remainder. The Vacuum Unit Loan is secured by a first lien on the Company's refinery. The Vacuum Unit Loan contains covenants and restrictions similar to those under the Facility. At December 31, 1995, the Company satisfied all of its covenants except for an annual refinery cash flow requirement, as defined in the Vacuum Unit Loan agreement. The lenders waived this refinery cash flow requirement for the year ended December 31, 1995. 54 55 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 12 3/4% SUBORDINATED DEBENTURES AND 13% EXCHANGE NOTES In 1983, the Company issued $120 million of 12 3/4% Subordinated Debentures at a price of 84.559% of the principal amount, due March 15, 2001. The Subordinated Debentures are redeemable at the option of the Company at 100% of principal amount plus accrued interest. Sinking fund payments sufficient to retire $11.25 million principal amount of debentures annually commenced on March 15, 1993. The Company satisfied the initial sinking fund requirement by purchasing $11.25 million principal amount of debentures at market value in January 1993. The exchange of $44.1 million principal amount of Subordinated Debentures for Exchange Notes in February 1994 satisfied the 1994 sinking fund requirement and, except for $.9 million, satisfied sinking fund requirements for the Subordinated Debentures through 1997. In December 1995, the Company redeemed $34.6 million of its outstanding Subordinated Debentures. Following this redemption, which satisfied all future sinking fund requirements, the Company has $30 million principal amount of outstanding Subordinated Debentures due 2001. See Note H for further information on the Recapitalization and redemption of debt. At December 31, 1995 and 1994, Subordinated Debt amounted to $27.8 million (net of discount of $2.2 million) and $59.1 million (net of discount of $5.5 million), respectively. The indenture contains restrictions on payment of dividends on the Company's Common Stock and purchases or redemptions of any of its capital stock. Due to losses in prior years, as of December 31, 1995, the Company must generate approximately $60 million of future net earnings applicable to Common Stock or from the issuance of capital stock before future dividends can be paid on Common Stock or before purchases or redemptions can be made of capital stock. The Exchange Notes mature December 1, 2000, and have no sinking fund requirements. The Exchange Notes are redeemable at the option of the Company at 100% of principal amount plus accrued interest except that no optional redemption may be made unless an equal principal amount of, or all the outstanding, Subordinated Debentures are concurrently redeemed. The Exchange Notes rank pari passu with the other senior debt of the Company and with the Subordinated Debentures, and senior in right of payment of the obligation to the State of Alaska (discussed below) and all other subordinated indebtedness of the Company. The indenture governing the Exchange Notes contains limitations on dividends that are less restrictive than the limitation under the Subordinated Debentures. 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 paid the State $10.3 million in January 1993 and 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 at the Company's refinery. In 1995, 1994 and 1993, based on a per barrel throughput charge of 16 cents, the Company's variable payments to the State totaled $2.9 million, $2.8 million and $2.6 million, respectively. The per barrel charge increases to 24 cents in 1996 and 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 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 secured by a mortgage 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. 55 56 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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. Through December 31, 1995, the Company had paid $44.2 million to the DOE since 1989. The Company's remaining obligation is to pay $11.9 million, exclusive of interest at 6%, over the next seven years. INDUSTRIAL REVENUE BONDS The industrial revenue bonds mature in 1997 and require semiannual payments of approximately $365,000. The bonds bear interest at a variable rate (6 3/8% at December 31, 1995), which is equal to 75% of the National Bank of Alaska's prime rate. The bonds are collateralized by the Company's refinery sulphur recovery unit, which had a carrying value of approximately $6.1 million at December 31, 1995. CAPITAL LEASE OBLIGATIONS The Company is the lessee of certain buildings and equipment under capital leases with remaining lease terms of three to 13 years. These buildings and equipment are primarily used in the Company's convenience store operations in Alaska. The assets and liabilities under capital leases are recorded at the present value of the minimum lease payments. Property, plant and equipment at December 31, 1995 included assets held under capital leases of $5.2 million with a net book value of $1.2 million. 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 are presented below (in thousands):
YEARS ENDED DECEMBER 31, ------------------------------ 1995 1994 1993 ------- ------ ------- Service Costs........................................... $ 1,147 1,121 931 Interest Cost........................................... 3,549 3,351 3,513 Actual Return on Plan Assets............................ (8,299) (217) (5,695) Net Amortization and Deferral........................... 4,288 (3,408) 1,488 ------ ------ ------ Net Pension Expense................................... $ 685 847 237 ====== ====== ======
56 57 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The funded status of the Company's retirement plan and amounts included in the Company's Consolidated Balance Sheets are set forth in the following table (in thousands):
DECEMBER 31, ------------------ 1995 1994 ------- ------ Actuarial Present Value of Benefit Obligation: Vested benefit obligation....................................... $39,012 35,877 ====== ===== Accumulated benefit obligation.................................. $41,659 38,102 ====== ===== Plan Assets at Fair Value......................................... $42,406 38,100 Projected Benefit Obligation...................................... 47,992 43,650 ------ ----- Plan Assets Less Than Projected Benefit Obligation................ (5,586) (5,550) Unrecognized Net Loss............................................. 7,319 9,029 Unrecognized Prior Service Costs.................................. (415) (490) Unrecognized Net Transition Asset................................. (4,412) (5,648) ------ ----- Accrued Pension Expense Liability............................... $(3,094) (2,659) ====== =====
Retirement plan assets are primarily comprised of common stock and bond funds. Actuarial assumptions used to measure the projected benefit obligations at December 31, 1995, 1994 and 1993 included a discount rate of 7 1/2%, 8 1/2% and 7%, respectively, and a compensation increase rate of 5%, 6% and 4 1/2%, respectively. The expected long-term rate of return on assets was 8 1/2% for 1995 and 9% for 1994 and 1993. 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 based upon the estimated requirements of the plan. The components of net pension expense for the ESP are presented below (in thousands):
YEARS ENDED DECEMBER 31, ----------------------- 1995 1994 1993 ----- ---- ---- Service Costs................................................ $ 364 474 426 Interest Cost................................................ 205 273 291 Actual Return on Plan Assets................................. (325) (230) (256) Net Amortization and Deferral................................ 471 228 295 ----- ---- ---- Net Pension Expense........................................ $ 715 745 756 ===== ==== ====
During 1995, 1994 and 1993, the Company incurred additional ESP expense of $1.5 million, $.4 million and $.5 million, respectively, for settlements, curtailments and other benefits resulting from a cost reduction program and other employee terminations. 57 58 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The funded status of the ESP and amounts included in the Company's Consolidated Balance Sheets are set forth in the following table (in thousands):
DECEMBER 31, ---------------- 1995 1994 ------ ----- Actuarial Present Value of Benefit Obligation: Vested benefit obligation......................................... $2,470 3,071 ====== ===== Accumulated benefit obligation.................................... $3,038 3,621 ====== ===== Plan Assets at Fair Value........................................... $4,447 3,822 Projected Benefit Obligation........................................ 4,155 4,075 ------ ----- Plan Assets in Excess of (Less Than) Projected Benefit Obligation... 292 (253) Unrecognized Net Loss............................................... 2,343 2,158 Unrecognized Prior Service Costs.................................... 395 495 Unrecognized Net Transition Obligation.............................. 643 843 ------ ----- Prepaid Pension Asset............................................. $3,673 3,243 ====== =====
Assets of the ESP consist of a group annuity contract. Actuarial assumptions used to measure the projected benefit obligation at December 31, 1995, 1994 and 1993 included a discount rate of 7 1/2%, 8 1/2% and 7%, respectively, and a compensation increase rate of 5%, 5% and 4 1/2%, respectively. The expected long-term rate of return on assets was 8% for 1995 and 9% for 1994 and 1993. NON-EMPLOYEE DIRECTOR RETIREMENT PLAN The Company has an unfunded Non-Employee Director Retirement Plan (the "Director Retirement Plan") which provides that any eligible non-employee director who elects to participate in the Director Retirement Plan and who has served on the Company's Board of Directors for at least three full years will be entitled to a retirement payment beginning the later of the director's sixty-fifth birthday or such later date that the individual's service as a director ends. In 1995, the Company recognized expense of $.8 million related to the Director Retirement Plan, substantially all attributable to non-recurring prior service costs. At December 31, 1995, the Director Retirement Plan's projected benefit obligation and present value of the vested and accumulated benefit obligation discounted at 7 1/2% were estimated to be $.8 million. The Company's Consolidated Balance Sheet at December 31, 1995 included $.7 million in other liabilities related to the Director Retirement Plan. RETIREE HEALTH CARE AND LIFE INSURANCE BENEFITS The Company provides health care and life insurance benefits to retirees and eligible dependents who were participating in the Company's group insurance program at retirement. 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. 58 59 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The components of net periodic postretirement benefits expense, other than pensions, for 1995, 1994 and 1993 included the following (in thousands):
YEARS ENDED DECEMBER 31, -------------------------- 1995 1994 1993 ------ ----- ----- Health Care: Service costs............................................ $ 447 471 420 Interest costs........................................... 1,399 1,264 1,396 ------ ----- ----- Net Periodic Postretirement Expense................... $1,846 1,735 1,816 ====== ===== ===== Life Insurance: Service costs............................................ $ 174 198 100 Interest costs........................................... 584 518 492 ------ ----- ----- Net Periodic Postretirement Expense................... $ 758 716 592 ====== ===== =====
The following tables show the status of the plans reconciled with the amounts in the Company's Consolidated Balance Sheets (in thousands):
DECEMBER 31, ------------------ 1995 1994 ------- ------ Health Care: Accumulated Postretirement Benefit Obligation -- Retirees........................................................ $13,831 14,066 Active participants eligible to retire.......................... 1,382 1,309 Other active participants....................................... 4,118 3,490 ------- ------ 19,331 18,865 Unrecognized net gain (loss).................................... 328 (164) ------- ------ Accrued Postretirement Benefit Liability..................... $19,659 18,701 ======= ====== Life Insurance: Accumulated Postretirement Benefit Obligation -- Retirees........................................................ $ 5,888 5,321 Active participants eligible to retire.......................... 452 421 Other active participants....................................... 1,590 1,324 ------- ------ 7,930 7,066 Unrecognized net loss........................................... (665) (438) ------- ------ Accrued Postretirement Benefit Liability..................... $ 7,265 6,628 ======= ======
The weighted average annual rate of increase in the per capita cost of covered health care benefits is assumed to be 8% for 1996, decreasing gradually to 6% by the year 2009 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, 1995 by $3.7 million and the aggregate of service cost and interest cost components of net periodic postretirement benefits for the year then ended by $.4 million. Actuarial assumptions used to measure the accumulated postretirement benefit obligation at December 31, 1995, 1994 and 1993 included a discount rate of 7 1/2%, 8 1/2% and 7%, respectively, and a compensation rate increase of 5%, 6% and 4 1/2%, respectively. 59 60 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) THRIFT PLAN The Company's employee thrift plan provides for contributions by eligible employees into designated investment funds with a matching contribution by the Company of 50% of the employee's basic contribution. The Company's contributions amounted to $400,000, $547,000 and $482,000 during 1995, 1994 and 1993, respectively. EMPLOYEE TERMINATIONS AND OTHER COSTS In 1995, the Company incurred a charge of $5.2 million, primarily for employee termination costs associated with restructuring the Company's organization and operations. Other expense included $3.8 million of this charge, representing primarily severance and related benefits resulting from a reduction in administrative workforce and other employee terminations together with settlements and curtailments under the Company's executive security plan. Operating expenses and other included the remaining $1.4 million of this charge which was related to employee terminations and exit costs in the Company's operating segments. The Company's Consolidated Balance Sheet as of December 31, 1995 included an accrual of approximately $.9 million relating to these costs, the majority of which will be paid during the first quarter of 1996. NOTE K -- INCENTIVE STOCK PLANS The Company has two employee incentive stock plans, the Amended Incentive Stock Plan of 1982 (the "1982 Plan") and the Executive Long-Term Incentive Plan (the "1993 Plan"), and a 1995 Non-Employee Director Stock Option Plan (the "1995 Plan") (collectively, the "Plans"). Shares of unissued Common Stock reserved for the Plans totaled 1,767,724 at December 31, 1995, which included 39,315 shares representing awards granted under the Plans that had not yet been issued. 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 1993 Plan provides for the issuance of awards in a variety of forms, including restricted stock, incentive stock options, nonqualified stock options, stock appreciation rights and performance share and performance unit awards. The 1993 Plan, which provides for the grant of up to 1,250,000 shares of the Company's Common Stock, will expire, unless earlier terminated, as to the issuance of awards in the year 2003. At December 31, 1995, the Company had 407,287 shares available for future grants under the 1993 Plan. Stock appreciation rights under the 1982 Plan become exercisable in three to five annual installments, normally beginning with the first anniversary of the date of the grant, and expire ten years from the date of grant. Stock appreciation rights entitle the employee to receive, without payment to the Company, the incremental increase in market value of the related stock from date of grant to date of exercise, payable in cash. Related compensation expense is charged to earnings over periods earned. During 1994, compensation expense related to stock appreciation rights was approximately $20,000 as a result of the market price of the related stock exceeding the exercise price of the stock appreciation rights. During 1995 and 1993, no compensation expense was recognized since the market value of the Company's Common Stock remained below the exercise price. Stock options under the 1982 Plan and 1993 Plan may be granted at exercise prices equal to the market value on the date the options are granted. The options granted generally become exercisable after one year in 20% increments per year and expire ten years from date of grant. Options granted to certain officers under the 1982 Plan are subject to accelerated vesting provisions based upon the improvement in the market price of the Company's Common Stock during a period immediately preceding their employment anniversary dates. Stock awards and performance shares granted to officers and key employees under the 1982 Plan and 1993 Plan amounted to 137,253 and 83,015 common shares in 1994 and 1993, respectively. No stock awards 60 61 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) or performance shares were granted in 1995. Compensation expense, representing the excess of the market value of the Common Stock on the dates of the awards over the purchase price to be paid by the employee, is charged to earnings over the periods that the shares are earned and amounted to $1,319,000 and $572,000 in 1994 and 1993, respectively. The 1995 Plan, which was approved by the Company's stockholders on May 4, 1995, provides for the granting of 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, received an option to purchase 5,000 shares of Common Stock. In addition, 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. At December 31, 1995, the Company had 36,000 options outstanding and 114,000 shares available for future grants under the 1995 Plan. A summary of the activity in the Plans is set forth below:
STOCK OPTIONS --------------------------- OUTSTANDING EXERCISABLE ----------- ----------- December 31, 1992............................................. 712,634 103,080 Granted at $2.925 to $5.250................................. 349,680 -- Becoming exercisable........................................ -- 127,044 Cancelled or expired........................................ (45,444) (44,278) ----------- ----------- December 31, 1993............................................. 1,016,870 185,846 Granted at $8.938 to $9.500................................. 524,600 -- Becoming exercisable........................................ -- 312,880 Exercised................................................... (18,764) (18,764) Cancelled or expired........................................ (26,413) (1,083) ----------- ----------- December 31, 1994............................................. 1,496,293 478,879 Granted at $8.000 to $11.375................................ 450,000 -- Becoming exercisable........................................ -- 615,103 Exercised................................................... (507,467) (507,467) Cancelled or expired........................................ (266,745) (225,736) ----------- ----------- December 31, 1995 ($2.925 to $12.625)......................... 1,172,081 360,779 ========= ========
STOCK APPRECIATION RIGHTS --------------------------- OUTSTANDING EXERCISABLE ----------- ----------- December 31, 1992............................................. 124,450 114,898 Becoming exercisable........................................ -- 7,042 Cancelled or expired........................................ (54,687) (53,521) --------- -------- December 31, 1993............................................. 69,763 68,419 Becoming exercisable........................................ -- 1,344 Exercised................................................... (14,921) (14,921) Cancelled or expired........................................ (3,582) (3,582) --------- -------- December 31, 1994............................................. 51,260 51,260 Cancelled or expired........................................ (16,219) (16,219) --------- -------- December 31, 1995 ($8.375 to $12.625)......................... 35,041 35,041 ========= ========
61 62 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) NOTE L -- PREFERRED STOCK PURCHASE RIGHTS In November 1985, the Company's Board of Directors declared a distribution of one preferred stock purchase right for each share of the Company's Common Stock. Each right will entitle the holder to buy 1/100 of a share of a newly authorized Series A Participating Preferred Stock at an exercise price of $35 per right. The rights become exercisable on the tenth day after public announcement that a person or group has acquired 20% or more of the Company's Common Stock. The rights may be redeemed by the Company prior to becoming exercisable by action of the Board of Directors at a redemption price of $.05 per right. If the Company is acquired by any person after the rights become exercisable, each right will entitle its holder to purchase stock of the acquiring company having a market value of twice the exercise price of each right. In December 1995, the Company's Board of Directors extended the expiration date of the rights to the close of business on July 24, 1996. At December 31, 1995, there were 24,780,134 rights outstanding. NOTE M -- OPERATING LEASES The Company has various noncancellable operating leases related to convenience stores, equipment, property and other facilities. Lease terms range from one year to 35 years and generally contain multiple renewal options. In addition, the Company has long-term leases expiring in the year 2000 for two vessels which are used to transport crude oil and refined products to and from the Company's refinery. Future minimum annual payments for operating leases, existing at December 31, 1995, were as follows (in thousands):
CHARTERED VESSELS OTHER TOTAL --------- ------ ------- 1996.................................................. $ 25,771 4,734 30,505 1997.................................................. 27,354 4,051 31,405 1998.................................................. 28,128 3,844 31,972 1999.................................................. 28,705 1,436 30,141 2000.................................................. 16,581 1,286 17,867 Remainder............................................. -- 11,144 11,144 --------- ------ ------- Total Minimum Lease Payments................ $ 126,539 26,495 153,034 ======== ====== =======
In addition to the long-term lease commitments listed above, the Company enters into various month-to-month and other short-term rentals, including a six-month charter of a vessel used to primarily transport refined products from the Company's refinery to the Far East. Assuming exercise of renewal options, lease payments under this charter, which was entered into in May 1995 and includes three six-month renewal options, would be approximately $3.3 million for the year 1996. Total rental expense, including short-term leases in addition to rents paid and accrued under long-term lease commitments, amounted to approximately $35.6 million, $33.6 million and $32.5 million for 1995, 1994 and 1993, respectively. Rental expense included amounts related to chartered vessels of approximately $26.3 million, $24.6 million and $22.9 million for 1995, 1994 and 1993, respectively. NOTE N -- COMMITMENTS AND CONTINGENCIES GAS PURCHASE AND SALES CONTRACT The Company is selling a portion of the gas produced from its Bob West Field to Tennessee Gas Pipeline Company ("Tennessee Gas") under a Gas Purchase and Sales Agreement ("Tennessee Gas Contract") which provides that the price of gas shall be the maximum price as calculated in accordance with Section 102(b)(2) ("Contract Price") of the Natural Gas Policy Act of 1978 ("NGPA"). In August 1990, Tennessee Gas filed suit against the Company in the District Court of Bexar County, Texas, alleging that the 62 63 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Tennessee Gas Contract is not applicable to the Company's properties and that the gas sales price should be the price calculated under the provisions of Section 101 of the NGPA rather than the Contract Price. During the month of December 1995, the Contract Price was in excess of $8.60 per Mcf and the average spot market price was $1.84 per Mcf. For the year ended December 31, 1995, approximately 17% of the Company's net U.S. natural gas production was sold under the Tennessee Gas Contract. Tennessee Gas also claimed that the contract should be considered an "output contract" under Section 2.306 of the Texas Uniform Commercial Code ("UCC") and that the increases in volumes tendered under the contract exceeded those allowable for an output contract. The District Court judge returned a verdict in favor of the Company on all issues. On appeal by Tennessee Gas, the Court of Appeals for the Fourth Supreme Judicial District of Texas affirmed the validity of the Tennessee Gas Contract as to the Company's properties and held that the price payable by Tennessee Gas for the gas was the Contract Price. The Court of Appeals remanded the case to the trial court based on its determination (i) that the Tennessee Gas Contract was an output contract and (ii) that a fact issue existed as to whether the increases in the volumes of gas tendered to Tennessee Gas under the contract were made in bad faith or were unreasonably disproportionate to prior tenders. The Company sought review of the appellate court ruling on the output contract issue in the Supreme Court of Texas. Tennessee Gas also sought review of the appellate court ruling denying the remaining Tennessee Gas claims in the Supreme Court of Texas. The appellate court decision was the first decision reported in Texas holding that a take-or-pay contract was an output contract. The Supreme Court of Texas heard arguments in December 1994 regarding the output contract issue and certain of the issues raised by Tennessee Gas. On August 1, 1995, the Supreme Court of Texas, in a divided opinion, affirmed the decision of the appellate court on all issues, including that the price under the Tennessee Gas Contract is the Contract Price, and determined that the Tennessee Gas Contract was an output contract and remanded the case to the trial court for determination of whether gas volumes tendered by the Company to Tennessee Gas were tendered in good faith and were not unreasonably disproportionate to any normal or otherwise comparable prior output or stated estimates in accordance with the UCC. The Company filed a motion for rehearing before the Texas Supreme Court on the issue of whether the Tennessee Gas Contract is an output contract. The Company believes that, if this issue is tried, the gas volumes tendered to Tennessee Gas will be found to have been in good faith and otherwise in accordance with the requirements of the UCC. However, there can be no assurance as to the ultimate outcome at trial. In conjunction with the District Court judgment and on behalf of all sellers under the Tennessee Gas Contract, Tennessee Gas is presently required to post a supersedeas bond in the amount of $206 million. Under the terms of this bond, for the period September 17, 1994 through April 30, 1996, Tennessee Gas is required to take at least its entire monthly take-or-pay obligation and pay for gas taken at $3.00 per Mmbtu, which approximates $3.00 per Mcf ("Bond Price"). The $206 million bond represents an amount which together with anticipated sales of natural gas at the Bond Price will equal the anticipated value of the Tennessee Gas Contract from September 17, 1994 through April 30, 1996. Except for the period September 17, 1994 through August 13, 1995, the difference between the spot market price and the Bond Price is refundable in the event Tennessee Gas ultimately prevails in the litigation. The Company retains the right to receive the Contract Price for all gas sold to Tennessee Gas. Through December 31, 1995, under the Tennessee Gas Contract, the Company recognized cumulative net revenues in excess of spot market prices totaling approximately $117.3 million. Of the $117.3 million incremental net revenues, the Company has received $11.0 million that is nonrefundable and $55.6 million which the Company could be required to repay in the event of an adverse ruling. The remaining $50.7 million of incremental net revenues is classified in the Company's Consolidated Balance Sheet as a noncurrent receivable at December 31, 1995 and represents the unpaid difference between the Contract Price and the Bond Price as described above. An adverse outcome of this litigation could require the Company to reverse as much as $106.3 million of the incremental revenues and could require the Company to repay as much as 63 64 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) $55.6 million for amounts received above spot prices, plus interest if awarded by the court. For further information concerning the Tennessee Gas Contract, see Note Q. 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 is expected to be limited based upon the number of companies and the volumes of waste involved. The Company believes that its liability at the Abbeville, Louisiana site will be limited based upon the payment by the Company of a de minimis settlement amount of $2,500 at a similar site in Louisiana. The Company is also involved in remedial responses and has incurred cleanup expenditures associated with environmental matters at a number of sites, including certain of its own properties. In addition, the Company is holding discussions with the Department of Justice ("DOJ") concerning the assessment of penalties with respect to certain alleged violations of regulations promulgated under the Clean Air Act as discussed below. In March 1992, the Company received a Compliance Order and Notice of Violation from the EPA alleging violations by the Company of the New Source Performance Standards under the Clean Air Act at its Alaska refinery. These allegations include failure to install, maintain and operate monitoring equipment over a period of approximately six years, failure to perform accuracy testing on monitoring equipment, and failure to install certain pollution control equipment. From March 1992 to July 1993, the EPA and the Company exchanged information relevant to these allegations. In addition, the EPA conducted an environmental audit of the Company's refinery in May 1992. As a result of this audit, the EPA is also alleging violation of certain regulations related to asbestos materials. In October 1993, the EPA referred these matters to the DOJ. The DOJ contacted the Company to begin negotiating a resolution of these matters. The DOJ has indicated that it is willing to enter into a judicial consent decree with the Company and that this decree would include a penalty assessment. Negotiations on the penalty are in progress. The DOJ is currently considering a penalty assessment of approximately $1.5 million. The Company is continuing to negotiate with the DOJ but cannot predict the ultimate outcome of the negotiations. At December 31, 1995, the Company's accruals for environmental matters, including the alleged violations of the Clean Air Act, amounted to $9.9 million. Also included in this amount is a noncurrent liability of approximately $4 million for remediation of the KPL properties, which liability has been funded by the former owners through a restricted escrow deposit. Based on currently available information, including the participation of other parties or former owners in remediation actions, the Company believes these accruals are adequate. In addition, to comply with environmental laws and regulations, the Company anticipates that it will be required to make capital improvements in 1996 of approximately $3 million, primarily for the removal and upgrading of underground storage tanks, and starting in 1996 approximately $8 million for the installation of dike liners; however, the Company is applying for an alternate compliance schedule, allowed for under the Alaska regulations, regarding dike liner installation at the Company's Alaska facilities. This alternate schedule, if granted, will allow the Company additional time to assess an alternate remedy to the requirement, under Alaska environmental regulations. There can be no assurance that an alternate schedule will be granted. Conditions that require additional expenditures may exist for various Company sites, including, but not limited to, the Company's refinery, retail gasoline outlets (current and closed locations) and petroleum 64 65 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) product terminals, and for compliance with the Clean Air Act. The amount of such future expenditures cannot currently be determined by the Company. CRUDE OIL PURCHASE CONTRACT In 1995, the Company renegotiated a new three-year contract with the State for the purchase of royalty crude oil covering the period January 1, 1996 through December 31, 1998. The new contract provides for the purchase of approximately 40,000 barrels per day of Alaska North Slope ("ANS") royalty crude oil, the primary feedstock for the Company's refinery, and is priced at the weighted average price reported to the State by a major North Slope producer of ANS crude oil as valued at Pump Station No. 1 on the Trans Alaska Pipeline System. Under this agreement, the Company is required to utilize in its refinery operations volumes equal to at least 80% of the ANS crude oil to be purchased from the State. This contract contains provisions that, under certain conditions, allow the Company to temporarily or permanently reduce its purchase obligations. The Company's previous contract with the State, for the purchase of approximately 40,000 barrels per day of ANS, expired on December 31, 1995. REFUND CLAIM In July 1994, a former customer of the Company ("Customer") filed suit against the Company in the United States District Court for the District of New Mexico for a refund in the amount of approximately $1.2 million, plus interest of approximately $4.4 million and attorney's fees, related to a gasoline purchase from the Company in 1979. The Customer also alleges entitlement to treble damages and punitive damages in the aggregate amount of $16.8 million. The refund claim is based on allegations that the Company renegotiated the acquisition price of gasoline sold to the Customer and failed to pass on the benefit of the renegotiated price to the Customer in violation of DOE price and allocation controls then in effect. In May 1995, the court issued an order granting the Company's motion for summary judgment and dismissed with prejudice all the claims in the Customer's complaint. In June 1995, the Customer filed a notice of appeal with the U.S. Court of Appeals for the Federal Circuit. The Company cannot predict the ultimate resolution of this matter but believes the claim is without merit. SEVERANCE TAX EXEMPTION In February 1996, the Texas Railroad Commission certified substantially all of the Company's reserves in the Bob West Field as high cost gas from a tight formation. As a result of the certification, the Company anticipates that the Texas Comptroller's office will exempt the Company's gas production from the tight formations in the Bob West Field from Texas severance taxes. If the severance tax exemption is received from the Comptroller's office, the Company estimates that the pretax present value of proved reserves as of December 31, 1995 will increase by approximately $7.7 million and that the Company could be eligible for a refund and tax credits for prior taxes paid of approximately $6 million. The potential refund and tax credits have not been recorded in the Company's financial statements. There is no assurance that the Company will receive the exemption or related refund or tax credits. For further information on the Company's reserves and standardized measure, see Note Q. 65 66 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) NOTE O -- QUARTERLY FINANCIAL DATA (UNAUDITED)
QUARTERS -------------------------------------- FIRST SECOND THIRD FOURTH ------ ------ ----- ------ (IN MILLIONS EXCEPT PER SHARE AMOUNTS) 1995 Gross Operating Revenues*............................... $234.0 264.2 244.2 227.8 ====== ==== ==== ==== Operating Profit........................................ $ 12.4 19.1 53.8 20.6 ====== ==== ==== ==== Earnings Before Extraordinary Loss...................... $ 1.8 7.4 36.8 11.5 Extraordinary Loss...................................... -- -- -- (2.9) ------ ---- ---- ---- Net Earnings......................................... $ 1.8 7.4 36.8 8.6 ====== ==== ==== ==== Earnings Per Share: Earnings before extraordinary loss................... $ .07 .30 1.47 .46 Extraordinary loss................................... -- -- -- (.11) ------ ---- ---- ---- Net earnings......................................... $ .07 .30 1.47 .35 ====== ==== ==== ==== 1994 Gross Operating Revenues*............................... $188.8 210.0 251.1 218.8 ====== ==== ==== ==== Operating Profit........................................ $ 18.3 11.7 7.1 27.3 ====== ==== ==== ==== Earnings (Loss) Before Extraordinary Loss............... $ 7.2 1.3 (3.3) 15.3 Extraordinary Loss...................................... (4.8) -- -- -- ------ ---- ---- ---- Net Earnings (Loss).................................. $ 2.4 1.3 (3.3) 15.3 ====== ==== ==== ==== Earnings (Loss) Per Share: Earnings (loss) before extraordinary loss............ $ .27 .02 (.13) .61 Extraordinary loss................................... (.24) -- -- -- ------ ---- ---- ---- Net earnings (loss).................................. $ .03 .02 (.13) .61 ====== ==== ==== ====
- --------------- * Amounts previously reported have been restated for insignificant reclassifications between revenues and operating expenses. The 1995 third quarter included a gain of approximately $33 million from the sale of certain interests in the Bob West Field, partially offset by approximately $5 million for employee terminations and other restructuring costs (see Notes B and J). An extraordinary loss of $2.9 million was recognized in the 1995 fourth quarter for the early extinguishment of debt (see Note H). The 1994 first quarter included an extraordinary loss of $4.8 million on the early extinguishment of debt in connection with the Recapitalization (see Note H) and a gain of $2.8 million from the sale of assets. During the 1994 fourth quarter, a refund of $8.5 million was recognized for settlement of a tariff dispute, partially offset by charges of approximately $4 million related to environmental contingencies and other matters. NOTE P -- NATURAL GAS PRICE SWAP AGREEMENTS The Company enters into commodity price swap agreements to reduce the risk caused by fluctuations in the prices of natural gas in the spot market. During 1995 and 1994, the Company used such arrangements to set the price of 38% and 11%, respectively, of the natural gas production that it sold in the spot market. It is the Company's current policy to use such arrangements to set the price of not more than 50% of the annual volumes of natural gas production that are sold in the spot market. The agreements provide for the Company 66 67 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) to receive, or make, payments based upon the differential between a specified fixed price and the market price for natural gas. The market price is determined by reference to a published index for natural gas traded at the Houston Ship Channel. The Houston Ship Channel index is the price upon which the cash prices for substantially all of the Company's spot market gas sales are based and, accordingly, the risk of losses from large fluctuations in the basis differentials (normally approximating the cost of transporting gas between the Henry Hub and the Houston Ship Channel) is substantially eliminated. The Company includes the related gains or losses in gas revenues in the period in which the gas is produced. During each of the years 1995 and 1994, the Company realized net gains of approximately $.3 million from these price swap arrangements. These gains had the effect of adding $.01 per Mcf to the Company's average spot market sales price for 1995 and 1994. As of January 9, 1996, the Company had entered into such price swaps for 1996 production totaling 8.4 billion cubic feet for an average Houston Ship Channel price of $1.77 per Mcf. In 1995, the Company's average spot market wellhead price per Mcf for gas sales was $.25 less than the average Houston Ship Channel index, the difference representing transportation and marketing costs from the wellhead in South Texas. NOTE Q -- OIL AND GAS PRODUCING ACTIVITIES The information presented below represents the oil and gas producing activities of the Company's exploration and production segment. Amounts related to the U.S. natural gas transportation operations, as disclosed in Note C, have been excluded. For information related to the sale of certain interests in the Bob West Field, see Note B. CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES
DECEMBER 31, ------------------------------- 1995 1994 1993 -------- ------- ------ (IN THOUSANDS) Capitalized Costs: Proved properties........................................... $119,836 131,930 73,345 Unproved properties not being amortized(1).................. 5,118 3,758 1,959 -------- ------- ------ 124,954 135,688 75,304 Accumulated depreciation, depletion and amortization........ 51,549 50,261 26,118 -------- ------- ------ Net Capitalized Costs............................... $ 73,405 85,427 49,186 ======== ======= ======
- --------------- (1) The Company anticipates that the majority of the costs at December 31, 1995, incurred primarily in 1995, will be included in the amortization base during 1996. 67 68 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES
UNITED STATES BOLIVIA TOTAL ------- ----- ------ (IN THOUSANDS) Year Ended December 31, 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 ======= ===== ====== Year Ended December 31, 1994: Property acquisition, unproved................................. $ 438 -- 438 Exploration.................................................... 8,808 -- 8,808 Development.................................................... 51,133 -- 51,133 ------- ----- ------ $60,379 -- 60,379 ======= ===== ====== Year Ended December 31, 1993: Property acquisition, unproved................................. $ 887 -- 887 Exploration.................................................... 2,257 -- 2,257 Development.................................................... 25,496 -- 25,496 ------- ----- ------ $28,640 -- 28,640 ======= ===== ======
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.
UNITED STATES(1) BOLIVIA TOTAL --------- ------- ------- (IN THOUSANDS EXCEPT AS INDICATED) Year Ended December 31, 1995: Gross revenues -- sales to nonaffiliates.................... $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(2).................................. 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(3).......... $ 63,022 2,850 65,872 ======== ====== ======= Depletion rates per net equivalent Mcf...................... $ .69 .03 ======== ======
68 69 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
UNITED STATES(1) BOLIVIA TOTAL -------- ------ ------- (IN THOUSANDS EXCEPT AS INDICATED) Year Ended December 31, 1994: Gross revenues -- sales to nonaffiliates.................... $ 87,478 13,211 100,689 Production costs............................................ 8,945 619 9,564 Administrative support and other............................ 2,289 3,242 5,531 Depreciation, depletion and amortization.................... 24,143 -- 24,143 -------- ------ ------- Pretax results of operations................................ 52,101 9,350 61,451 Income tax expense.......................................... 19,104 5,605 24,709 -------- ------ ------- Results of operations from producing activities(3).......... $ 32,997 3,745 36,742 ======== ====== ======= Depletion rates per net equivalent Mcf...................... $ .79 -- ======== ====== Year Ended December 31, 1993: Gross revenues -- sales to nonaffiliates.................... $ 48,474 12,594 61,068 Production costs............................................ 4,752 1,152 5,904 Administrative support and other............................ 1,196 3,046 4,242 Depreciation, depletion and amortization.................... 11,111 -- 11,111 -------- ------ ------- Pretax results of operations................................ 31,415 8,396 39,811 Income tax expense.......................................... 6,647 5,160 11,807 -------- ------ ------- Results of operations from producing activities(3).......... $ 24,768 3,236 28,004 ======== ====== ======= Depletion rates per net equivalent Mcf...................... $ .78 -- ======== ======
- --------------- (1) See Note N regarding litigation involving a natural gas sales contract. (2) Represents gain on sale of certain interests in the Bob West Field (see Note B). (3) Excludes corporate general and administrative expenses and financing costs. 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. As indicated in Note N, certain of the Company's U.S. production activities are involved in litigation pertaining to a natural gas sales contract with Tennessee Gas. Although the outcome of any litigation is 69 70 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) uncertain, based upon advice from outside legal counsel, management believes that the Company will ultimately prevail in this dispute. Accordingly, the Company has based its calculation of the standardized measure of discounted future net cash flows on the Contract Price. However, if Tennessee Gas were to prevail, the impact on the Company's future revenues and cash flows would be significant. Based on the Contract Price, the discounted future net cash flows before income taxes relating to proved reserves in the United States at December 31, 1995 was $168.7 million, compared with $120.7 million at spot market prices. For information regarding a contingency related to a severance tax exemption and a potential increase of approximately $7.7 million to the Company's pretax discounted future net cash flows, see Note N. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED RESERVES (UNAUDITED)
UNITED STATES(1) BOLIVIA TOTAL --------- ------- ------- (IN THOUSANDS) 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....................... 45,939 25,897 71,836 -------- -------- -------- Standardized measure of discounted future net cash flows... $122,800 22,829 145,629 ======== ======== ======== December 31, 1994: Future cash inflows........................................ $292,620 120,886 413,506 Future production costs.................................... 52,534 30,873 83,407 Future development costs................................... 29,933 7,258 37,191 -------- -------- -------- Future net cash flows before income tax expense............ 210,153 82,755 292,908 10% annual discount factor................................. 30,706 34,674 65,380 -------- -------- -------- Discounted future net cash flows before income taxes....... 179,447 48,081 227,528 Discounted future income tax expense....................... 52,661 26,092 78,753 -------- -------- -------- Standardized measure of discounted future net cash flows... $126,786 21,989 148,775 ======== ======== ======== December 31, 1993: Future cash inflows........................................ $315,788 133,363 449,151 Future production costs.................................... 59,398 31,092 90,490 Future development costs................................... 48,020 2,981 51,001 -------- -------- -------- Future net cash flows before income tax expense............ 208,370 99,290 307,660 10% annual discount factor................................. 45,810 44,055 89,865 -------- -------- -------- Discounted future net cash flows before income taxes....... 162,560 55,235 217,795 Discounted future income tax expense....................... 59,808 28,795 88,603 -------- -------- -------- Standardized measure of discounted future net cash flows... $102,752 26,440 129,192 ======== ======== ========
- --------------- (1) See Note N regarding litigation involving a natural gas sales contract. 70 71 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)
YEARS ENDED DECEMBER 31, --------------------------------- 1995 1994 1993 --------- ------- ------- (IN THOUSANDS) Sales and transfers of oil and gas produced, net of production costs.......................................... $(106,378) (88,751) (52,766) Net changes in prices and production costs.................. (32,931) 12,834 (21,160) Extensions, discoveries and improved recovery............... 83,045 54,503 73,792 Development costs incurred.................................. 38,795 51,148 25,510 Revisions of estimated future development costs............. (19,574) (34,738) (24,052) Revisions of previous quantity estimates.................... 60,800 1,818 31,031 Sales of minerals in-place.................................. (48,698) -- -- Accretion of discount....................................... 14,878 12,919 11,071 Net changes in income taxes................................. 6,917 9,850 (24,945) --------- ------- ------- Net increase (decrease)..................................... (3,146) 19,583 18,481 Beginning of period......................................... 148,775 129,192 110,711 --------- ------- ------- End of period............................................... $ 145,629 148,775 129,192 ========= ======= =======
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. 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.
UNITED STATES(1) BOLIVIA TOTAL --------- ------- ------- (MILLIONS OF CUBIC FEET) NET PROVED GAS RESERVES(2) December 31, 1992............................................. 73,753 107,008 180,761 Revisions of previous estimates............................. 16,304 (693) 15,611 Extensions, discoveries and other additions................. 44,291 -- 44,291 Production.................................................. (14,150) (7,020) (21,170) ------- -------- -------- December 31, 1993............................................. 120,198 99,295 219,493 Revisions of previous estimates............................. 9,881 (9,678) 203 Extensions, discoveries and other additions................. 29,606 14,199 43,805 Production.................................................. (30,586) (8,060) (38,646) ------- -------- -------- 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(3).......................................... 106,377 88,396 194,773 ========= ======== ======== NET PROVED DEVELOPED GAS RESERVES (included above) December 31, 1992............................................. 34,160 91,376 125,536 December 31, 1993............................................. 65,652 99,295 164,947 December 31, 1994............................................. 110,071 81,558 191,629 December 31, 1995(3).......................................... 95,930 72,500 168,430
71 72 TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
UNITED STATES(1) BOLIVIA TOTAL --------- ------- ----- (THOUSANDS OF BARRELS) NET PROVED OIL RESERVES(2) December 31, 1992................................................. -- 2,263 2,263 Revisions of previous estimates................................. -- 152 152 Production...................................................... -- (242) (242) ---- ------ ----- December 31, 1993................................................. -- 2,173 2,173 Revisions of previous estimates................................. -- (280) (280) Extensions, discoveries and other additions..................... -- 168 168 Production...................................................... -- (268) (268) ---- ------- ----- 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(3).............................................. 8 1,596 1,604 ===== ======= ===== NET PROVED DEVELOPED OIL RESERVES (included above) December 31, 1992................................................. -- 2,098 2,098 December 31, 1993................................................. -- 2,173 2,173 December 31, 1994................................................. -- 1,627 1,627 December 31, 1995(3).............................................. 4 1,407 1,411
- --------------- (1) See Note N regarding litigation involving a natural gas sales contract. (2) The Company was not required to file reserve estimates with federal authorities or agencies during the periods presented. (3) No major discovery or adverse event has occurred since December 31, 1995 that would cause a significant change in net proved reserve volumes. 72 73 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 1996 Proxy Statement, incorporated herein by reference. See also Executive Officers of the Registrant under Business in Item 1. ITEM 11. EXECUTIVE COMPENSATION Information required under this Item will be contained in the Company's 1996 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 1996 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 1996 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.......................................................... 39 Statements of Consolidated Operations -- Years Ended December 31, 1995, 1994 and 1993................................................................................ 40 Consolidated Balance Sheets -- December 31, 1995 and 1994............................. 41 Statements of Consolidated Stockholders' Equity -- Years Ended December 31, 1995, 1994 and 1993....................................................................... 42 Statements of Consolidated Cash Flows -- Years Ended December 31, 1995, 1994 and 1993................................................................................ 43 Notes to Consolidated Financial Statements............................................ 44
2. FINANCIAL STATEMENT SCHEDULES All schedules are omitted 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. 73 74 3. EXHIBITS
EXHIBIT NUMBER DESCRIPTION OF EXHIBIT - ------ ------------------------------------------------------------------------------------ 2(a) 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(b) First Amendment to Agreement and Plan of Merger dated effective February 19, 1996 between the Company, Coastwide Energy Services, Inc. and CNRG Acquisition Corp. 2(c) Copy of the Purchase and Sale Agreement by and between Tesoro E&P Company, L.P., as Seller, and Coastal Oil & Gas of Texas, L.P., as Purchaser (incorporated by reference herein to Exhibit 2 to the Company's Current Report on Form 8-K dated September 26, 1995, File No. 1-3473). 3 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(a) Bylaws of the Company, as amended through September 27, 1995 (incorporated by reference herein to Exhibit 3 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1995, File No. 1-3473). 3(b) 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(c) 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(d) 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(e) 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(a) 12 3/4% Subordinated Debentures due March 15, 2001, Form of Indenture, dated March 15, 1983 (incorporated by reference herein to Exhibit 4(b) to Registration Statement No. 2-81960). 4(b) 13% Exchange Notes due December 1, 2000, Indenture, dated February 8, 1994 (incorporated by reference herein to Exhibit 2 to the Company's Registration Statement on Form 8-A filed March 2, 1994). 4(c) Copy of Indenture between the Company and Bankers Trust Company, a Trustee, pursuant to which the Exchange Notes Due December 1, 2000 were issued (incorporated by reference herein to Exhibit 2 to the Company's Registration Statement on Form 8-A filed March 2, 1994). 4(d) Rights Agreement dated December 16, 1985 between the Company and Chemical Bank, N.A. successor to InterFirst Bank Fort Worth, N.A. (incorporated by reference herein to Exhibit 4(i) to the Company's Annual Report on Form 10-K for the fiscal year ended September 30, 1985, File No. 1-3473). 4(e) Amendment to Rights Agreement dated December 16, 1985 between the Company and Chemical Bank, N.A. (incorporated by reference herein to Exhibit 4(c) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1992, File No. 1-3473). 4(f) Copy of resolution of the Company's Board of Directors extending the Expiration Date relating to the Company's Preferred Stock Purchase Rights (incorporated by reference herein to the Company's Current Report on Form 8-K dated December 15, 1995, File No. 1-3473).
74 75
EXHIBIT NUMBER DESCRIPTION OF EXHIBIT - ------ ------------------------------------------------------------------------------------ 4(g) Credit Agreement (the "Credit Agreement") dated as of April 20, 1994 among the Company and Texas Commerce Bank National Association ("TCB") as Issuing Bank and as Agent, and certain other banks named therein (incorporated by reference herein to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1994, File No. 1-3473). 4(h) Guaranty Agreement dated as of April 20, 1994 among various subsidiaries of the Company and TCB, as Issuing Bank and as Agent, and certain other banks named therein (incorporated by reference herein to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1994, File No. 1-3473). 4(i) Mortgage, Deed of Trust, Assignment of Production, Security Agreement and Financing Statement dated as of April 20, 1994 from Tesoro Exploration and Production Company, entered into in connection with the Credit Agreement (incorporated by reference herein to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1994, File No. 1-3473). 4(j) Deed of Trust, Security Agreement and Financing Statement dated as of April 20, 1994 among Tesoro Alaska Petroleum Company, TransAlaska Title Insurance Agency, Inc., as Trustee, and TCB, as Agent, entered into in connection with the Credit Agreement (incorporated by reference herein to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1994, File No. 1-3473). 4(k) Pledge Agreement dated as of April 20, 1994 by the Company in favor of TCB, entered into in connection with the Credit Agreement (incorporated by reference herein to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1994, File No. 1-3473). 4(l) Security Agreement (Accounts and Inventory) dated as of April 20, 1994 between the Company and TCB, entered into in connection with the Credit Agreement (incorporated by reference herein to Exhibit 10.6 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1994, File No. 1-3473). 4(m) Security Agreement (Accounts and Inventory) dated as of April 20, 1994 between Tesoro Alaska Petroleum Company and TCB, entered into in connection with the Credit Agreement (incorporated by reference herein to Exhibit 10.7 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1994, File No. 1-3473). 4(n) Security Agreement (Accounts) dated as of April 20, 1994 between Tesoro Petroleum Distributing Company and TCB, entered into in connection with the Credit Agreement (incorporated by reference herein to Exhibit 10.8 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1994, File No. 1-3473). 4(o) Security Agreement (Accounts and Inventory) dated as of April 20, 1994 between Tesoro Exploration and Production Company and TCB, entered into in connection with the Credit Agreement (incorporated by reference herein to Exhibit 10.9 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1994, File No. 1-3473). 4(p) Security Agreement (Accounts and Inventory) dated as of April 20, 1994 between Tesoro Refining, Marketing & Supply Company and TCB, entered into in connection with the Credit Agreement (incorporated by reference herein to Exhibit 10.10 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1994, File No. 1-3473). 4(q) Loan Agreement (the "Loan Agreement") dated as of May 26, 1994 among Tesoro Alaska Petroleum Company, as Borrower, the Company, as Guarantor, and National Bank of Alaska ("NBA"), as Lender (incorporated by reference herein to Exhibit 4.30 to Registration Statement No. 33-53587).
75 76
EXHIBIT NUMBER DESCRIPTION OF EXHIBIT - ------ ------------------------------------------------------------------------------------ 4(r) Guaranty Agreement dated as of May 26, 1994 between the Company and NBA, entered into in connection with the Loan Agreement (incorporated by reference herein to Exhibit 4.31 to Registration Statement No. 33-53587). 4(s) $15,000,000 Promissory Note dated as of May 26, 1994 of Tesoro Alaska Petroleum Company payable to the order of NBA, in connection with the Loan Agreement (incorporated by reference herein to Exhibit 4.32 to Registration Statement No. 33-53587). 4(t) Construction Loan Agreement dated as of May 26, 1994 between Tesoro Alaska Petroleum Company and NBA, entered into in connection with the Loan Agreement (incorporated by reference herein to Exhibit 4.33 to Registration Statement No. 33-53587). 4(u) Deed of Trust dated as of May 26, 1994 from Tesoro Alaska Petroleum Company, entered into in connection with the Loan Agreement (incorporated by reference herein to Exhibit 4.34 to Registration Statement No. 33-53587). 4(v) Security Agreement dated as of May 26, 1994 between Tesoro Alaska Petroleum Company and NBA, entered into in connection with the Loan Agreement (incorporated by reference herein to Exhibit 4.35 to Registration Statement No. 33-53587). 4(w) Consent and Intercreditor Agreement dated as of May 26, 1994 among NBA, TCB, as Agent, and the Company, entered into in connection with the Credit Agreement (incorporated by reference herein to Exhibit 4.36 to Registration Statement No. 33-53587). 4(x) Copy of Consent and Waiver No. 1 dated October 27, 1994 to the Company's Credit Agreement dated as of April 20, 1994 (incorporated by reference herein to Exhibit 4 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1994, File No. 1-3473). 4(y) Copy of First Amendment to Credit Agreement dated as of January 20, 1995 among the Company and TCB as Issuing Bank and as Agent, and certain other banks named therein (incorporated by reference herein to Exhibit 4(z) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473). 4(z) Copy of First Amendment to the Loan Agreement dated as of January 26, 1995 among Tesoro Alaska Petroleum Company, Tesoro Petroleum Corporation and NBA (incorporated by reference herein to Exhibit 4(aa) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473). 4(aa) Copy of Consent and Waiver No. 2 dated as of July 31, 1995 to the Company's Credit Agreement dated as of April 20, 1994 (incorporated by reference herein to Exhibit 4 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1995, File No. 1-3473). 4(bb) Copy of Second Amendment and Supplement to Credit Agreement effective as of September 1, 1995 among Tesoro and TCB as Issuing Bank and as Agent, and certain other banks named therein (incorporated by reference herein to Exhibit 4.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1995, File No. 1-3473). 4(cc) Copy of Third Amendment to Credit Agreement effective as of October 24, 1995 among Tesoro and TCB as Issuing Bank and as Agent, and certain other banks named therein (incorporated by reference herein to Exhibit 4.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1995, File No. 1-3473). 4(dd) Warrant Agreement dated effective as of October 29, 1993, between Coastwide Energy Services, Inc. and Chemical Shareholder Services Group, Inc., as Warrant Agent (incorporated by reference herein to Exhibit 4.1 to Post-Effective Amendment No. 1 to Registration No. 333-00229). 4(ee) Warrant Assumption and Conversion Agreement dated as of February 20, 1996, between the Company, Coastwide Energy Services, Inc. and Chemical Shareholder Services Group, Inc., as Warrant Agent (incorporated by reference herein to Exhibit 4.2 to Post-Effective Amendment No. 1 to Registration No. 333-00229).
76 77
EXHIBIT NUMBER DESCRIPTION OF EXHIBIT - ------ ------------------------------------------------------------------------------------ 4(ff) Form of 8% Convertible Subordinated Debenture (incorporated by reference herein to Exhibit 4.3 to Post-Effective Amendment No. 1 to Registration No. 333-00229). 4(gg) 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(hh) 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(ii) 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(a) 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). 10(b) 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(c) 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(d) Employment Agreement between the Company and Michael D. Burke dated July 27, 1992 (incorporated by reference herein to Exhibit 10(j) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1992, File No. 1-3473). 10(e) First Amendment and Extension to Employment Agreement between the Company and Michael D. Burke dated December 14, 1994 (incorporated by reference herein to Exhibit 10(h) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1992, File No. 1-3473). 10(f) Termination Agreement between the Company and Michael D. Burke, dated September 26, 1995 (incorporated by reference herein to Exhibit 10(i) to Registration Statement No. 333-00229). 10(g) Consulting Agreement between the Company and M.D. Burke & Company (formerly M.D. Burke Enterprises, Inc.) dated September 26, 1995 (incorporated by reference herein to Exhibit 10(j) to Registration Statement No. 333-00229). 10(h) Form of Executive Agreement providing for continuity of management between the Company and James W. Queen dated June 28, 1984 (incorporated by reference herein to Exhibit 10(b) to the Company's Annual Report on Form 10-K for the fiscal year ended September 30, 1984, File No. 1-3473). 10(i) Form of Amendment to Executive Agreement between the Company and James W. Queen dated September 30, 1987 (incorporated by reference herein to Exhibit 10(c) to the Company's Annual Report on Form 10-K for the fiscal year ended September 30, 1987, File No. 1-3473). 10(j) Form of Second Amendment to Executive Agreement between the Company and James W. Queen dated February 28, 1990 (incorporated by reference herein to Exhibit 10(e) to the Company's Annual Report on Form 10-K for the fiscal year ended September 30, 1990, File No. 1-3473).
77 78
EXHIBIT NUMBER DESCRIPTION OF EXHIBIT - ------ ------------------------------------------------------------------------------------ 10(k) Employment Agreement between the Company and Bruce A. Smith dated September 14, 1992 (incorporated by reference herein to Exhibit 10(k) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1992, File No. 1-3473). 10(l) First Amendment and Extension to Employment Agreement between the Company and Bruce A. Smith dated December 14, 1994 (incorporated by reference herein to Exhibit 10(j) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473). 10(m) Second Amendment to Employment Agreement between the Company and Bruce A. Smith dated September 29, 1995 (incorporated by reference herein to Exhibit 10(m) to Registration Statement No. 333-00229). 10(n) Letter Agreement extending the term of the Employment Agreement, as amended, between the Company and Bruce A. Smith dated December 14, 1995 (incorporated by reference herein to Exhibit 10(n) to Registration Statement No. 333-00229). 10(o) Amended and Restated Employment Agreement between the Company and Bruce A. Smith dated February 15, 1996. 10(p) Employment Agreement between the Company and Gaylon H. Simmons dated January 4, 1993 (incorporated by reference herein to Exhibit 10(l) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1992, File No. 1-3473). 10(q) First Amendment and Extension to Employment Agreement between the Company and Gaylon H. Simmons dated December 14, 1994 (incorporated by reference herein to Exhibit 10(l) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473). 10(r) Employment Agreement between the Company and James C. Reed, Jr. dated December 14, 1994 (incorporated by reference herein to Exhibit 10(m) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473). 10(s) First Amendment to Employment Agreement between the Company and James C. Reed, Jr. dated as of September 27, 1995 (incorporated by reference herein to Exhibit 10(r) to Registration Statement No. 333-00229). 10(t) Employment Agreement between the Company and William T. Van Kleef dated December 14, 1994 (incorporated by reference herein to Exhibit 10(n) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473). 10(u) First Amendment to Employment Agreement between the Company and William T. Van Kleef dated as of September 27, 1995 (incorporated by reference herein to Exhibit 10(t) to Registration Statement No. 333-00229). 10(v) 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(w) 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(x) 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(y) 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).
78 79
EXHIBIT NUMBER DESCRIPTION OF EXHIBIT - ------ ------------------------------------------------------------------------------------ 10(z) 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). 10(aa) Copy of the Company's Executive Long-Term Incentive Plan (incorporated by reference to Exhibit 10(k) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1993, File No. 1-3473). 10(bb) 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(cc) 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(dd) 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(ee) Agreement for the Sale and Purchase of Royalty Oil between Tesoro Alaska Petroleum Company and the State of Alaska (for the sale of Prudhoe Bay Royalty Oil), dated February 26, 1982 (incorporated by reference herein to Exhibit 10(p) to the Company's Annual Report on Form 10-K for the fiscal year ended September 30, 1984, File No.1-3473). 10(ff) Agreement for the Sale and Purchase of State Royalty Oil dated as of September 27, 1994 by and between Tesoro Alaska Petroleum Company and the State of Alaska (incorporated by reference herein to Exhibit 10(x) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-3473). 10(gg) 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(hh) 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(ii) 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(jj) Gas Purchase and Sales Agreement dated January 16, 1979 (incorporated by reference herein to Exhibit 10(p) to Registration Statement No. 33-68282). 11 Information Supporting Earnings Per Share Computations 21 Subsidiaries of the Company 23(a) Consent of Deloitte & Touche LLP 23(b) Consent of Netherland, Sewell & Associates, Inc. 27 Financial Data Schedule
79 80 (b) REPORTS ON FORM 8-K A Current Report on Form 8-K, dated September 26, 1995, was filed on October 11, 1995, reporting under Item 2, Acquisition or Disposition of Assets, that on September 26, 1995 the Company sold, effective April 1, 1995, certain interests in the Company's producing and non-producing oil and gas properties located in the Bob West Field, Zapata and Starr Counties, Texas. A Current Report on Form 8-K, dated December 15, 1995, was filed on December 18, 1995, reporting under Item 5, Other Events, that the Company's Board of Directors extended the expiration date of its Preferred Stock Purchase Rights to July 24, 1996. A Current Report on Form 8-K, dated January 30, 1996, was filed on January 31, 1996, reporting under Item 5, Other Events, that the Company announced earnings for the year ended December 31, 1995 and information regarding its natural gas reserves and 1996 capital budget. No financial statements were filed as part of the current reports listed above. 80 81 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 By: /s/ BRUCE A. SMITH -------------------------------- Bruce A. Smith President and Chief Executive Officer March 22, 1996 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 Director, President and Chief March 22, 1996 - --------------------------------------------- Executive Officer (Principal (Bruce A. Smith) Executive Officer) /s/ WILLIAM T. VAN KLEEF Senior Vice President and Chief March 22, 1996 - --------------------------------------------- Financial Officer (Principal (William T. Van Kleef) Financial Officer and Accounting Officer) /s/ ROBERT J. CAVERLY Chairman of the Board of March 22, 1996 - --------------------------------------------- Directors and Director (Robert J. Caverly) /s/ STEVEN H. GRAPSTEIN Vice Chairman of the Board of March 22, 1996 - --------------------------------------------- Directors and Director (Steven H. Grapstein) /s/ RAYMOND K. MASON, SR. Director March 22, 1996 - --------------------------------------------- (Raymond K. Mason, Sr.) /s/ JOHN J. MCKETTA, JR. Director March 22, 1996 - --------------------------------------------- (John J. McKetta, Jr.) Director March , 1996 - --------------------------------------------- (Patrick J. Ward) /s/ MURRAY L. WEIDENBAUM Director March 22, 1996 - --------------------------------------------- (Murray L. Weidenbaum)
81 82 INDEX TO EXHIBITS
EXHIBIT NUMBER DESCRIPTION OF EXHIBIT - ------ ------------------------------------------------------------------------------------ 2(b) First Amendment to Agreement and Plan of Merger dated effective February 19, 1996 between the Company, Coastwide Energy Services, Inc. and CNRG Acquisition Corp. 10(o) Amended and Restated Employment Agreement between the Company and Bruce A. Smith dated February 15, 1996. 11 Information Supporting Earnings Per Share Computations 21 Subsidiaries of the Company 23(a) Consent of Deloitte & Touche LLP 23(b) Consent of Netherland, Sewell & Associates, Inc. 27 Financial Data Schedule
EX-2.B 2 FIRST AMENDMENT TO AGREEMENT AND PLAN OF MERGER 1 ITEM 14(a)3,EXHIBIT 2(b) FIRST AMENDMENT TO AGREEMENT AND PLAN OF MERGER THIS FIRST AMENDMENT TO AGREEMENT AND PLAN OF MERGER ("Amendment") by and among Tesoro Petroleum Corporation, a Delaware corporation ("Parent"), CNRG Acquisition Corp., a Delaware corporation ("Sub") and Coastwide Energy Services, Inc., a Delaware corporation ("Company") is effective February 19, 1996, and amends that certain Agreement and Plan of Merger dated as of November 20, 1995, by and among Parent, Sub and Company (the "Agreement"). Unless defined in this Amendment, capitalized terms shall have the meaning ascribed thereto in the Agreement. RECITALS WHEREAS, Parent, Sub and Coastwide desire to clarify certain aspects of the Exchange of Certificates provisions of the Agreement to better reflect the intent of the parties: NOW THEREFORE, for good and valuable consideration, the receipt of sufficiency of which is hereby acknowledged by Parent, Sub and Company, Parent, Sub and Company agree as follows: AGREEMENT 1. Section 2.2.(b) of the Agreement is deleted in its entirety and replaced with the following: Payment of Merger Consideration. Parent shall take all steps necessary to enable and cause there to be provided to the Exchange Agent at the Effective Time of the Merger, certificates for the Parent Shares issued upon the conversion of the Shares pursuant to Section 2.1. Parent or the Surviving Corporation shall timely make available to the Exchange Agent the cash component of the Merger Consideration. 2. The last two sentences of Section 2.2(c) of the Agreement are deleted in their entirety and replaced with the following: 17 2 Until surrendered as contemplated by this Section 2.2, each Certificate shall be deemed from and after the Effective Time, for all corporate purposes, other than the payment of dividends and distributions declared prior to the Merger, to evidence the ownership of the number of full shares of Parent Common Stock into which the shares represented by such Certificate shall have been converted pursuant to this Section II. 3. The first sentence of Section 2.2(e) of the Agreement is deleted in its entirety and replaced with the following: All Parent Shares exchanged upon the surrender of Certificates in accordance with the terms of this Article II, together with any dividends payable thereon to the extent contemplated by this Section 2.2, shall be deemed to have been exchanged and paid in full satisfaction of all rights pertaining to the Shares theretofore represented by such Certificates and, at the Effective Time of the Merger, there shall be no further registration of transfers on the stock transfer books of the Surviving Corporation of the Shares that were outstanding immediately prior to the Effective Time of the Merger. 4. Except as specifically amended by this Amendment, the Agreement shall remain as originally written. The Agreement shall not be further amended, except by an instrument in writing signed by all parties to the Agreement. 18 3 TESORO PETROLEUM CORPORATION By: /s/ BRUCE A. SMITH ----------------------------------- Bruce A. Smith, President and Chief Executive Officer CNRG ACQUISITION CORP. By: /s/ BRUCE A. SMITH ----------------------------------- Bruce A. Smith, President and Chief Executive Officer COASTWIDE ENERGY SERVICES, INC. By: /s/ STEPHEN A. WELLS ----------------------------------- Stephen A. Wells, President 19 EX-10.O 3 AMENDED AND RESTATED EMPLOYMENT AGREEMENT 1 ITEM 14(a)3,EXHIBIT 10(o) AMENDED AND RESTATED EMPLOYMENT AGREEMENT This Amended and Restated Employment Agreement (the "Agreement") is entered into as of February 15, 1996 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 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 $500,000 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 2 downward adjustment in Employee's Base Salary may be made during the term of this Agreement. (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 $20,000 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 February 15, 1996, and if not terminated earlier as herein provided, shall terminate on December 14, 1997. On or prior to September 14, 1997, the Company shall be obligated to notify Employee of its intent to terminate, renew or renegotiate the terms of this Agreement at the expiration of its term. On or prior to October 14, 1997, Employee 2 3 shall be obligated to notify the Company of his intent to terminate, renew or renegotiate the terms of this Agreement at the expiration of its term (which obligation shall not be conditioned upon the Company giving notice as specified above). On or prior to November 14, 1997, the parties hereto shall have entered into a final written agreement with respect to Employee's continued employment with the Company following the expiration of the term of this Agreement or, in the event such agreement is not reached, Employee's employment with the Company shall terminate on December 14, 1997. If Employee's employment is so terminated and the Company shall not have offered Employee the opportunity to enter into a new employment agreement prior to November 14, 1997, with terms, in all respects, no less favorable to the Employee than the terms of this Agreement and with a term lasting until at least December 14, 1999, such termination shall be deemed to have been "without cause" in accordance with Section 5 (or Section 9, as applicable) and the Employee shall be entitled to all payments and benefits as if his employment had terminated without cause in accordance with Section 5 (or Section 9, as applicable) on December 13, 1997. 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) two 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 two 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 two times the stipulated flexible perquisites amount pursuant to Section 2(d), and (iii) 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. 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. 3 4 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 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 4 5 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 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 5 6 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. 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 6 7 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; (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 7 8 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; (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 8 9 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 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% 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, 9 10 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. (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. 10 11 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 If to the Employee: Bruce A. Smith 301 Morningside San Antonio, Texas 78209 11 12 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 12 13 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-11 4 INFORMATION SUPPORTING EARNINGS 1 ITEM 14(A)3, EXHIBIT 11 TESORO PETROLEUM CORPORATION AND SUBSIDIARIES INFORMATION SUPPORTING EARNINGS PER SHARE COMPUTATIONS (IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
YEARS ENDED DECEMBER 31, ----------------------------- 1995 1994 1993 ------- ------ ------ PRIMARY EARNINGS PER SHARE COMPUTATION: Earnings before extraordinary loss on extinguishment of debt.... $57,489 20,483 16,956 Extraordinary loss on extinguishment of debt.................... (2,857) (4,752) -- ------- ------ ------ Net earnings.................................................... 54,632 15,731 16,956 Dividend requirements on preferred stock........................ -- 2,680 9,207 ------- ------ ------ Net earnings applicable to common stock......................... $54,632 13,051 7,749 ======= ====== ====== Average outstanding common shares............................... 24,557 22,552 14,070 Average outstanding common equivalent shares.................... 550 644 220 ------- ------ ------ Average outstanding common and common equivalent shares....... 25,107 23,196 14,290 ======= ====== ====== Primary Earnings Per Share: Earnings before extraordinary loss on extinguishment of debt....................................................... $ 2.29 .77 .54 Extraordinary loss on extinguishment of debt.................. (.11) (.21) -- ------- ------ ------ Net earnings.................................................. $ 2.18 .56 .54 ======= ====== ====== FULLY DILUTED EARNINGS PER SHARE COMPUTATION: Net earnings applicable to common stock......................... $54,632 13,051 7,749 Add: Dividend requirements on preferred stock................... -- 2,680 9,207 ------- ------ ------ Net earnings applicable to common stock -- fully diluted........ $54,632 15,731 16,956 ======= ====== ====== Average outstanding common and common equivalent shares......... 25,107 23,196 14,290 Shares issuable on conversion of preferred shares............... -- 1,476 4,775 ------- ------ ------ 25,107 24,672 19,065 ======= ====== ====== Fully Diluted Earnings Per Share -- Anti-dilutive*.............. $ 2.18 .56 .54 ======= ====== ======
- --------------- * This calculation is submitted in accordance with paragraph 601(b)(11) of Regulation S-K, although it is not required by APB Opinion No. 15 because it produces an anti-dilutive result. EX-21 5 SUBSIDIARIES OF THE COMPANY 1 ITEM 14(A)3, EXHIBIT 21 SUBSIDIARIES OF THE REGISTRANT
INCORPORATED PERCENT OF VOTING OR ORGANIZED SECURITIES OWNED NAME OF COMPANY UNDER LAWS OF BY TESORO - ----------------------------------------------------------------- ------------- ----------------- Tesoro Alaska Petroleum Company.................................. Delaware 100% Tesoro Alaska Pipeline Company................................... Delaware 100% Tesoro Bolivia Petroleum Company................................. Texas 100% Tesoro Exploration and Production Company........................ Delaware 100% Tesoro Gas Resources Company, Inc................................ Delaware 100% Tesoro Natural Gas Company....................................... Delaware 100% Tesoro Northstore Company........................................ Alaska 100% Tesoro Petroleum Companies, Inc.................................. Delaware 100% Tesoro Petroleum Distributing Company*........................... Louisiana 100% Tesoro Refining, Marketing & Supply Company...................... Delaware 100%
- --------------- * Currently, Coastwide Marine Services, Inc. (see Note B of Notes to Consolidated Financial Statements in Item 8). Small or inactive subsidiaries are omitted from the above list. 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. EX-23.A 6 CONSENT OF DELOITTE & TOUCHE LLP 1 ITEM 14(a)3,EXHIBIT 23(a) INDEPENDENT AUDITORS' CONSENT Board of Directors and Stockholders Tesoro Petroleum Corporation We consent to the incorporation by reference in Registration Statement No. 33-53293 of Tesoro Petroleum Corporation on Form S-8 of our report dated February 2, 1996, (February 20, 1996 as to Notes B and N), appearing in this Annual Report on Form 10-K of Tesoro Petroleum Corporation for the year ended December 31, 1995. DELOITTE & TOUCHE LLP San Antonio, Texas March 22, 1996 EX-23.B 7 CONSENT OF NETHERLAND, SEWELL & ASSOCIATES, INC. 1 ITEM 14(a)3,EXHIBIT 23(b) 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, 1995, 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 12, 1996 EX-27 8 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, 1995, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 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 4,130 0 0 212,384 519,153 970,172 1,002,883 855,187 855,187 42,620 0 20,902 61,868 4,379 57,489 0 (2,857) 0 54,632 2.18 2.18 Earnings per share is after an extraodinary loss of $2.9 million ($.11 loss per share) on extinguishment of debt.
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