Annual Report (Form 10-K), fiscal year 1994

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 wholesale marketing of fuel and lubricants. 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 B of Notes to Consolidated Financial Statements in Item 8.
During 1994, the Company consummated a recapitalization plan and equity offering whereby a major portion of the Company's outstanding debt was restructured and all of its preferred stock and dividend arrearages were eliminated and which, among other matters, deferred $44 million of debt service requirements, increased stockholders' equity by approximately $82 million and eliminated $9.2 million of annual preferred dividend requirements. In addition, the recapitalization enabled the Company to enter into a $125 million corporate Revolving Credit Facility and obtain $15 million financing for a major addition to the Company's refinery. For further information concerning the recapitalization and offering, see Note C of Notes to Consolidated Financial Statements in Item 8.
REFINING AND MARKETING
OVERVIEW
The Company conducts petroleum refining operations in Alaska and sells refined products to a wide variety of customers in Alaska, in the area west of the Rocky Mountains and in certain Far Eastern markets. During 1994, 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.
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 product. The refinery is designed to process crude oil with a sulphur content of up to 1%. Alaska North Slope ("ANS") and Cook Inlet crude oils, the primary crude oils currently used as feedstock for the refinery, are below this limit. 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 1994, the refinery processed approximately 59% ANS crude oil, 32% Cook Inlet crude oil and 9% other refinery feedstocks, which yielded refined products consisting of approximately 25% gasoline, 43% middle distillates and refinery fuel and 32% of residual product.
During 1994, the Company continued its operational strategy to improve 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. The markets for residual fuel oil have generally been weak for the past several years due to a global oversupply of this product. During 1994, the Company reduced its average daily refinery throughput and production by 7% from the 1993 levels, resulting in a cumulative reduction from the 1992 levels of 25%. 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, particularly residual product, for which there is no significant market in Alaska.
The Company has installed a vacuum unit, which became operational in December 1994, that is expected to reduce the refinery's yield of residual product about 50% by further processing these volumes into higher-valued products. With the vacuum unit now operational, the Company is pursuing marketing initiatives to
increase demand for the refinery's production which would increase the refinery's capacity utilization and improve efficiencies.
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 1994, approximately 59% of the refinery's feedstock was ANS crude oil, of which approximately 28,700 barrels per day were purchased under a royalty crude oil purchase contract with the State, which expired at the end of 1994. The Company and the State have extended this contract through 1995. The agreement between the Company and the State requires 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. The Company does not currently anticipate increasing the percentage of ANS crude oil utilized as feedstock at the refinery. Under its agreement with the State, the Company has the right to sell or to exchange up to 20% of the ANS crude oil to be purchased from the State during 1995. The Company is currently negotiating with the State for a new three-year contract for the period January 1, 1996 through December 31, 1998. Based on preliminary discussions with the State, the Company believes that a new contract will provide for the purchase of approximately the same volumes of ANS royalty crude oil as the current contract and believes that such crude oil will be priced at the weighted average price reported to the State by a major North Slope producer for ANS crude oil as valued at Pump Station No. 1 on the Trans Alaska Pipeline System ("TAPS"). All ANS crude oil feedstock is delivered to the refinery by tanker through the Kenai Pipe Line Company ("KPL") marine terminal. The Company and KPL have entered into an agreement whereby the Company will purchase KPL, subject to regulatory approval. The Company expects that this purchase transaction will be consummated 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 32% of the refinery's feedstock supply in 1994. The Company obtains Cook Inlet crude from several producers on the Kenai Peninsula under short-term contracts. Cook Inlet crude oil is delivered by tanker or through an existing pipeline to the refinery.
OTHER SUPPLY. In 1994, the Company's refinery obtained approximately 9% of its feedstock supply from other sources. This feedstock supply was primarily heavy atmospheric gas oil ("HAGO") and was purchased from a local competitor's refineries 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.
From time to time, the Company evaluates the economic viability of processing foreign crude oil in its Alaska refinery and occasionally purchases spot quantities to supplement its normal crude oil supply. This foreign crude oil is also delivered to the refinery by tanker through the KPL marine terminal.
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 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 on a per barrel charge that is currently 16 cents and increases to 33 cents on the volume of feedstock processed at the Company's refinery. In 1994 and 1993, the Company's variable payments to the State totaled $2.8 million and $2.6 million, respectively. 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 December 2001 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 may be subordinated to current and future senior debt obligations (including, without limitation, principal, interest and related expenses) 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, 1994, 1993 and 1992:
ALASKA MARKETING
GASOLINE. In 1994, the Company distributed virtually all of the gasoline produced at the refinery 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 88 branded and 24 unbranded dealers and jobbers and by deliveries to two major oil companies for their retail operations in Alaska in exchange for gasoline delivered to the Company on the U.S. West Coast. During 1994, the Company's refinery production of gasoline was essentially balanced with the Alaskan market demand. 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 1994, these convenience stores sold an average of 71,100 gallons of gasoline per day.
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 the 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. Approximately 6% of the Company's diesel fuel production in 1994 was sold for on-highway use. 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. 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.
HEAVY OILS AND RESIDUAL PRODUCT. Since there is no significant demand for heavy oils and residual product in Alaska, substantially all of the Company's refinery production of such products is exported from Alaska. During 1994, the Company sold and transported a substantial volume of its residual product to the U.S. West Coast, where it was generally used as a refinery feedstock. Prior to 1993, the Company's primary market for residual product was the Far Eastern bunker fuel markets. Marketing the residual product as a
feedstock has reduced the Company's exposure to the pricing volatility that exists in the Far Eastern bunker fuel markets. In addition, the refinery's reduced throughput and reduction of ANS crude oil as a percentage of total feedstock during 1994 caused residual product output to decrease from approximately 17,600 barrels per day in 1993 to approximately 15,100 barrels per day during 1994. The Company has recently completed the installation of a vacuum unit at the refinery at a cost of $25 million. The vacuum unit, which uses residual product as a feedstock, is anticipated to reduce the refinery's yield of residual product by approximately 50% 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.
U.S. WEST COAST MARKETING
The Company conducts domestic wholesale marketing operations, primarily in California, Oregon and Washington with its principal office located in Long Beach, California. During 1994, these operations sold approximately 31,400 barrels per day of refined products, of which approximately 30% was received from major oil companies in exchange for products from the Company's refinery and 70% was purchased from other suppliers. The Company sells these refined products in the bulk market and through 27 terminal locations, of which four are owned by the Company.
TRANSPORTATION
In October 1994, the Company chartered an American flag vessel, the Potomac Trader, under a charter agreement expiring in September 1996 with two one-year renewal options. The Potomac Trader is used primarily to transport ANS crude oil from the TAPS terminal at Valdez, Alaska to the Company's refinery. The Potomac Trader is smaller and less expensive than the previous vessel utilized by the Company and better matches the Company's logistical requirements. The Company also has a charter for another American flag vessel, the Baltimore Trader, under a one-year agreement expiring in January 1996. The Baltimore Trader is used to transport residual product to the U.S. West Coast and occasionally to transport feedstocks to the Company's refinery. 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 1994, the pipeline transported an average of approximately 23,800 barrels of petroleum 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
UNITED STATES
During 1994, the Company concentrated its activities in the Bob West Field, which is located in the southern part of the Wilcox Trend in Starr and Zapata Counties, Texas. The Company, which does not operate the field, owns an average 50% revenue interest in approximately two-thirds of the field and a 28% revenue interest in the remainder. Pursuant to an agreement with the operator, the Company has an option with respect to the 50% revenue interest portion of the field to elect, subject to certain conditions, to assume operations of that portion of the field. The Wilcox Trend extends from Northern Mexico through South Texas into Western Louisiana. 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, discovered in 1990, has resulted in the Company's net proven natural gas reserves increasing from 120 billion cubic feet ("Bcf") at December 31, 1993 to 129 Bcf at December 31, 1994, reflecting a replacement of 129% of 1994 production. Two exploratory and 20 development wells were drilled and
completed in this field during 1994, bringing the number of producing wells to 46 at December 31, 1994 with an additional two wells being drilled and four wells awaiting completion at year-end. Of these six additional wells, two were subsequently completed as producing wells and the remainder are in the completion phase. Twenty-four additional well locations have been selected for further development of this 4,000-acre field, most of which are expected to be drilled during 1995 and 1996, the timing of which is dependent upon, among other factors, the price the Company receives for its natural gas production. During December 1994, the Company's net production from the Bob West Field wells averaged approximately 130 million cubic feet ("Mmcf") per day, which represented approximately 90% of the Company's year-end 1994 net deliverability. From time to time, the Company may increase or decrease its natural gas production in response to market conditions. Due to weakened spot market natural gas prices, beginning in January 1995, the Company and one of its partners initiated a voluntary reduction of natural gas production sold in the spot market. The Company's share of this reduction is estimated to be approximately 34 Mmcf per day, representing 33% of the Company's estimated current net deliverability of natural gas available for sale in the spot market. This voluntary reduction has continued through February 1995. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Exploration and Production".
In addition to the continued development of the Bob West Field, during 1994 the Company also participated in the drilling of five exploratory wells and one unsuccessful development well in other areas of South Texas. One of the exploratory wells was successful, two were dry holes and two were in progress at December 31, 1994. One of the wells in progress at year-end was subsequently abandoned and the other is in the process of being completed.
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 at escalating prices that are substantially above current spot market prices for natural gas. During 1994, for example, Tennessee Gas purchased approximately 21% of the Company's net gas production from the Bob West Field under the Tennessee Gas Contract pursuant to a contract price of $8.01 per thousand cubic feet ("Mcf") which was substantially above the 1994 average spot market price of $1.64 per Mcf. The Tennessee Gas Contract is presently the subject of litigation with Tennessee Gas. In June 1992, the trial court returned a verdict in favor of the Company upholding the terms of the Tennessee Gas Contract. The Court of Appeals upheld the validity of the Tennessee Gas Contract but remanded the case for further consideration of legal issues which might limit certain terms of the Tennessee Gas Contract. The ruling of the Court of Appeals is presently being reviewed by the Supreme Court of Texas. Pending the decision of the Supreme Court of Texas, the trial court, pursuant to a bond hearing, ordered that Tennessee Gas pay for gas at $3.00 per Mmbtu, which approximates $3.00 per Mcf ("Bond Price"), for the period September 17, 1994 through August 1, 1995 and post a bond which, together with the anticipated sales of natural gas to Tennessee Gas at the Bond Price, will equal the anticipated value of the Tennessee Gas Contract during this interim period. The Bond Price is nonrefundable by the Company, and the Company retains the right to receive the full contract price for all gas sold to Tennessee Gas. Prior to the bond hearing, the Company was receiving the contract price from Tennessee Gas for purchases of gas under the Tennessee Gas Contract. The Company continues to recognize revenues under the Tennessee Gas Contract based on the contract price. See Legal Proceedings in Item 3 and Notes L and P of Notes to Consolidated Financial Statements in Item 8.
GAS PROCESSING, GATHERING AND TRANSPORTATION. The Company owns a 70% interest in the Bob West Field's central gas processing facility which was expanded during 1994 to enable a processing capacity of 350 Mmcf per day. The Company owns a 70% interest in Starr County Gathering System which consists of two ten-inch diameter and one twenty-inch diameter pipelines that transport natural gas eight miles from the field to common carrier pipeline facilities. The Company does not operate either of such facilities. From February 1994 until May 1994, the pipeline facilities were at capacity and production subject to spot market prices was being curtailed. In 1994, the Company acquired a 50% interest in a twenty-inch diameter natural gas pipeline that was constructed during 1994 and which eliminated the curtailment of natural gas production subject to spot market sales prices. The Company believes that these expansions in pipeline capacity,
gathering systems and processing capacities have minimized the risk of significant marketing constraints for the foreseeable future.
BOLIVIA
The Company's Bolivian exploration and production operations are located in southern Bolivia near the border with Argentina, where, since 1976, the Company has discovered four significant natural gas fields. At December 31, 1994, Tesoro was the second largest holder of proved natural gas reserves in Bolivia, with estimated net proved natural gas reserves of 96 Bcf. The Company is the operator of a joint venture that holds two Contracts of Operation with YPFB, the Bolivian state-owned oil and gas company. The Company has a 75% interest in a Contract of Operation, which expires in 2007, covering approximately 93,000 acres in Block XVIII. The Company has drilled five exploratory wells and 12 development wells within three separate fields in Block XVIII. During 1994, the Company's net production from these fields averaged 22 Mmcf of gas per day and 733 barrels of condensate per day, a production level that exceeded that of the average of the prior three years, primarily due to the inability of another producer during 1994 to satisfy gas supply requirements. 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 XVIII to YPFB which in turn sells the natural gas to Yacimientos Petroliferos Fiscales, S.A.("YPF"), a publicly-held company based in Argentina. The contract between YPFB and YPF was recently extended through March 31, 1997. The contract extension maintained approximately the same volumes as their previous contract, but with a small decrease in price. The Company's contract for the sale of natural gas to YPFB has expired and is subject to renegotiation. The Company is currently selling its natural gas production to YPFB based on the pricing terms in the contract between YPFB and YPF. The Company anticipates that any renegotiation of its contract with YPFB will result in the Company receiving a lower price than it received under its previous contract with YPFB. Any renegotiation may result in a reduction of volumes purchased from the Company due to new supply sources that commenced production near the end of 1994.
The Company has a 72.6% interest in a Contract of Operation, which expires in 2008, covering approximately 1.2 million acres in Block XX. 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 XX is currently limited by a lack of access to major gas-consuming markets. Prior to 1993, one successful commercial gas discovery well, the Los Suris No. 1, was drilled on the block and is shut-in pending the approval by the Government of Bolivia of a commercialization agreement. A work plan for Block XX that included a three-well exploratory program was approved by YPFB and the Government of Bolivia. Under the plan, the Company drilled a well, the Los Suris No. 2, which was completed in February 1994 and tested gross production potential of approximately 9 Mmcf of gas per day and approximately 120 barrels of condensate per day from two producing intervals. The Los Suris No. 2 is also shut-in pending the approval of a commercialization agreement. The second exploratory well, San Antonio X-1, was abandoned in September 1994 and Palo Marcado X-3, the third exploratory well, was spudded in December 1994 and is currently being drilled to a proposed depth of 3,000 meters. To guarantee the drilling of the second and third exploratory wells, the Company submitted bank guarantees to YPFB in the aggregate amount of $4.0 million. Upon abandonment of the San Antonio X-1, YPFB released the Company from the first $2.0 million guarantee. The Company may postpone the relinquishment of inactive acreage until July 15, 1996 by submitting, no later than July 1, 1995, an additional two-well drilling program that is acceptable to YPFB.
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 gas fields in 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. A preliminary
financing proposal has been announced for the Brazilian pipeline project, although no final decision on the construction or the completion date of this pipeline has been made.
For further information regarding Tesoro's Bolivian operations, see Notes B and P of Notes to Consolidated Financial Statements in Item 8.
OPERATING STATISTICS
The following table summarizes the Company's exploration and production activities for the years ended December 31, 1994, 1993 and 1992. Effective May 1, 1992, the Company sold its Indonesian operations:
- --------------- (1) See Legal Proceedings in Item 3 and Note L of Notes to Consolidated Financial Statements in Item 8 regarding litigation concerning the Tennessee Gas contract.
(2) The Company's natural gas production from Bolivia as presented above represents the Company's net production before Bolivian taxes.
(3) Average lifting costs for the Company's U.S. operations include such items as severance taxes, property taxes, insurance, materials and supplies and transportation of natural gas production through Company-owned pipelines. Since severance taxes are based upon sales prices of natural gas, the average lifting costs presented above include the impact of above-market prices for sales under the Tennessee Gas Contract. Lifting costs per Mcf of natural gas sold in the spot market were approximately $.38, $.39 and $.63 for 1994, 1993 and 1992, respectively.
ACREAGE AND WELLS
The following table sets forth the Company's gross and net acreage and productive wells at December 31, 1994:
- --------------- * Included in total productive wells is 1 gross (.6 net) well in the United States and 8 gross (6.0 net) wells in Bolivia with multiple completions. At December 31, 1994, the Company was participating in the drilling of 8 gross (4.6 net) wells in the United States and 1 gross (.7 net) well in Bolivia.
For further information regarding the Company's exploration and production activities, see Notes B and P of Notes to Consolidated Financial Statements in Item 8.
OIL FIELD SUPPLY AND DISTRIBUTION
The Company sells lubricants, fuels and specialty petroleum products primarily to onshore and offshore drilling contractors. The Company's products are sold through six land terminals and 11 marine terminals in various Texas and Louisiana locations. These products are used to power and lubricate machinery on drilling and production locations. The Company also provides products for marine, commercial and industrial applications. Effective March 31, 1994, the Company discontinued its environmental remediation products and services operations and recorded charges of $1.9 million during 1994 in connection with such discontinuance. The Company is continuing its wholesale marketing of fuel and lubricants.
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, respectively, owned by Petro Star Inc. The Company estimates that such other refineries have a combined capacity to process approximately 172,000 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 the principal supplier for two major oil companies through product exchange agreements, 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 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 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 Orders No. 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 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 can only estimate when new standards will be imposed by the EPA or relevant state agencies, or what technologies or changes in processes the Company may have to install or undertake to achieve compliance with any 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 1995. 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 supported the State's position and formalities for obtaining the exemption were completed on September 27, 1993. The EPA, in a letter to the State dated September 30, 1993, stated that the EPA was completing the final documentation regarding the waiver and that Alaska would have a low priority for enforcement of the diesel fuel regulations, pending publication of a final decision, which has not yet occurred. 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 1994. 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 spot 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 by January 1997 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 1995 and 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 incurred capital expenditures of approximately $2.7 million for environmental control purposes during 1994 and anticipates incurring approximately $2 million for such purposes during 1995, primarily for the removal and upgrading of underground storage tanks, and approximately $8 million during 1996 for the installation of dike liners required under Alaska environmental regulations as discussed above. 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.
TAXES
UNITED STATES
The Revenue Reconciliation Act of 1993 will impose a tax of 4.3 cents per gallon on commercial aviation fuel effective October 1, 1995. The Company does not believe such tax will have a material adverse effect on the Company's future operations.
BOLIVIA
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. However, due to the Company's net operating loss carryforwards, the Company does not now, or in the near future, expect to use these taxes as credits 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.
In 1990, the Bolivian Government passed a General Law of Hydrocarbons containing provisions designed to ensure the creditability, for United States federal income tax purposes, of these hydrocarbon taxes if the Company makes an election that may subject it to a higher Bolivian tax rate in the future. Regulations under this law have not been issued; however, the Company does not anticipate that this law will have a material adverse effect on the Company's Bolivian operations.
EMPLOYEES
At December 31, 1994, the Company employed approximately 870 persons, of which approximately 40 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, 1995.
There are no family relationships among the officers listed, and there are no arrangements or understandings pursuant to which any of them were elected as officers. Officers are elected annually by the Board of Directors at its first meeting following the Annual Meeting of Stockholders, each to hold office until the corresponding meeting of the Board in the next year or until a successor shall have been elected or shall have qualified.
All of the Company's executive officers have been employed by the Company or its subsidiaries in an executive capacity for at least the past five years, except for those named below who have had the business experience indicated during that period. Positions, unless otherwise specified, are with the Company.
ITEM 2.



ITEM 2. PROPERTIES
See information appearing under Item 1, Business herein and Notes B, F and P of Notes to Consolidated Financial Statements in Item 8.
ITEM 3.

ITEM 3. LEGAL PROCEEDINGS
TENNESSEE GAS CONTRACT. The Company is selling a portion of the gas from its Bob West Field to Tennessee Gas Pipeline Company ("Tennessee Gas") under a Gas Purchase and Sales Agreement (the "Tennessee Gas Contract") which provides that the price of gas shall be the maximum price as calculated in accordance with Section 102(b)(2) ("Contract Price") of the Natural Gas Policy Act of 1978 ("NGPA"). Tennessee Gas filed suit against the Company in the District Court of Bexar County, Texas alleging that the Tennessee Gas Contract is not applicable to the Company's properties and that the gas sales price should be the price calculated under the provisions of Section 101 of the NGPA rather than the Contract Price. During December 1994, the Contract Price was in excess of $8.00 per Mcf, the Section 101 price was $4.81 per Mcf and the average spot market price was $1.56 per Mcf. Tennessee Gas also claimed that the contract should be considered an "output contract" under Section 2.306 of the Texas Business and Commerce Code and that the increases in volumes tendered under the contract exceeded those allowable for an output contract.
The District Court judge returned a verdict in favor of the Company on all issues. On appeal by Tennessee Gas, the Court of Appeals for the Fourth Supreme Judicial District of Texas affirmed the validity of the Tennessee Gas Contract as to the Company's properties and held that the price payable by Tennessee Gas for the gas was the Contract Price. The Court of Appeals remanded the case to the trial court based on its determination (i) that the Tennessee Gas Contract was an output contract and (ii) that a fact issue existed as to whether the increases in the volumes of gas tendered to Tennessee Gas under the contract were made in bad faith or were unreasonably disproportionate to prior tenders. The Company sought review of the appellate court ruling on the output contract issue in the Supreme Court of Texas. Tennessee Gas also sought review of the appellate court ruling denying the remaining Tennessee Gas claims in the Supreme Court of Texas. The Supreme Court of Texas heard arguments in December 1994 regarding the output contract issue and certain of the issues raised by Tennessee Gas but has not yet issued its opinion.
Although the outcome of any litigation is uncertain, management, based upon advice from outside legal counsel, is confident that the decision of the trial and appellate courts will ultimately be upheld as to the validity of the Tennessee Gas Contract and the Contract Price. If the Supreme Court of Texas were to affirm the appellate court ruling, the Company believes that the only issue for trial should be whether the increases in the volumes of gas tendered to Tennessee Gas from the Company's properties were made in bad faith or were unreasonably disproportionate. The appellate court decision was the first reported decision in Texas holding that a take-or-pay contract was an output contract. As a result, it is not clear what standard the trial court would be required to apply in determining whether the increases were in bad faith or unreasonably disproportionate. The appellate court acknowledged in its opinion that the standards used in evaluating other kinds of output contracts would not be appropriate in this context. The Company believes that the appropriate standard would be whether the development of the field was undertaken in a manner that a prudent operator would have undertaken in the absence of an above-market sales price. Under that standard, the Company believes that, if this issue is tried, the development of the Company's gas properties and the resulting increases in volumes tendered to Tennessee Gas will be found to have been reasonable and in good faith. Accordingly, the Company has recognized revenues, net of production taxes and marketing charges, for natural gas sales through December 31, 1994, under the Tennessee Gas Contract based on the Contract Price, which net revenues aggregated $36.9 million more than the Section 101 prices and $69.5 million in excess of the spot market prices. If Tennessee Gas were ultimately to prevail in this litigation, the Company could be required to return to Tennessee Gas $52.5 million, plus interest if awarded by the court, representing the difference between the spot market price and the Contract Price received by the Company through September 17, 1994 (the date on which the Company entered into a bond agreement discussed below). In addition, the Company's calculation of the standardized measure of discounted future net cash flows relating to proved reserves in the United States at December 31, 1994 of $127 million was determined in part using the Contract Price as
compared with $73 million at spot market prices. An adverse judgment in this case could have a material adverse effect on the Company.
On August 4, 1994, the trial court rejected a motion by Tennessee Gas to post a supersedeas bond in the form of monthly payments into the registry of the court representing the difference between the Contract Price and spot market price of gas sold to Tennessee Gas pursuant to the Tennessee Gas Contract. The court advised Tennessee Gas that should it wish to supersede the judgment, Tennessee Gas had the option to post a bond which would be effective only until August 1, 1995, in an amount equal to the anticipated value of the Tennessee Gas Contract during that period. In September 1994, the court ordered that, effective until August 1, 1995, Tennessee Gas (i) take at least its entire monthly take-or-pay obligation under the Tennessee Gas Contract, (ii) pay for gas at $3.00 per Mmbtu, which approximates $3.00 per Mcf ("Bond Price"), and (iii) post a $120 million bond with the court representing an amount which, together with anticipated sales of natural gas to Tennessee Gas at the Bond Price, will equal the anticipated value of the Tennessee Gas Contract during this interim period. The Bond Price is nonrefundable by the Company, and the Company retains the right to receive the full Contract Price for all gas sold to Tennessee Gas. The Company continues to recognize revenues under the Tennessee Gas Contract based on the Contract Price. At December 31, 1994, the Company had recognized cumulative revenues in excess of spot market prices (through September 17, 1994) and in excess of the Bond Price (subsequent to September 17, 1994) totaling $65.7 million. Receivables at December 31, 1994, included $17.7 million from Tennessee Gas, of which $13.2 million represented the difference between the Contract Price and the Bond Price. For further information regarding the Tennessee Gas Contract, see Notes L and P of Notes to Consolidated Financial Statements in Item 8.
MINERAL ESTATE CLAIM. In February 1995, a lawsuit was filed in the U.S. District Court for the Southern District of Texas, McAllen Division, by the Heirs of H.P. Guerra, Deceased ("Plaintiffs") against the United States and Tesoro and other working and overriding royalty interest owners to recover the oil and gas mineral estate under 2,706.34 acres situated in Starr County, Texas. The oil and gas mineral estate sought to be recovered underlies lands taken by the United States in connection with the construction of the Falcon Dam and Reservoir. In their lawsuit, the Plaintiffs allege that the original taking by the United States in 1948 was unlawful and void and the refusal of the United States to revest the mineral estate to H.P. Guerra or his heirs was arbitrary and capricious and unconstitutional. Plaintiffs seek (i) restoration of their oil and gas estate; (ii) restitution of all proceeds realized from the sale of oil and gas from their mineral estate, plus interest on the value thereof; and (iii) cancellation of all oil and gas leases issued by the United States to Tesoro and the other working interest owners covering their mineral estate. The lawsuit covers a significant portion of the mineral estate in the Bob West Field; however, none of the acreage covered is dedicated to the Tennessee Gas Contract. The Company cannot predict the ultimate resolution of this matter but, based upon advice from outside legal counsel, believes the lawsuit is without merit.
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. 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 ("ADEC") substantially similar to Consent Orders reached with the 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 Environmental Protection Agency (the "EPA") alleging violations by the Company of the New Source Performance Standards under the Clean Air Act at its Alaska refinery. These allegations include failure to install, maintain and operate monitoring equipment over a period of approximately six years, failure to perform accuracy testing on monitoring equipment, and failure to install certain pollution control equipment. From March 1992 to July 1993, the EPA and the Company exchanged information relevant to these allegations. In addition, the EPA conducted an environmental audit of the Company's refinery in May 1992. As a result of this audit, the EPA is also alleging violation of certain regulations related to asbestos materials. In October 1993, the EPA referred these matters to the Department of Justice ("DOJ"). The DOJ contacted the Company to begin negotiating a resolution of these matters. The DOJ has indicated that it is willing to enter into a judicial consent decree with the Company and that this decree would include a penalty assessment. Negotiations on the penalty are in progress. The DOJ has proposed a penalty assessment of approximately $3.7 million. The Company is continuing to negotiate with the DOJ but cannot predict the ultimate outcome of the negotiations.
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 Company arranged for the disposal of a minimal amount of materials at this location, but CERCLA imposes joint and several liability on each PRP. 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 this site; however, the extent of the Company's allocated financial contribution to the cleanup of this site is expected to be minimal based on the number of companies and the volumes of waste involved and the payment by the Company of a de minimus 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.
ITEM 4.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5.

ITEM 5. MARKET FOR THE 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 1994 and 1993 are summarized below:
At March 1, 1995, there were approximately 4,300 holders of record of the Company's 24,534,430 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.
ITEM 6.

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

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
CAPITAL RESOURCES AND LIQUIDITY
During 1994, the Company significantly strengthened its short-term and long-term liquidity and increased its equity capital and financial resources. These improvements were achieved by consummation of a recapitalization plan and equity offering whereby a major portion of the Company's outstanding debt was restructured and all of its preferred stock and dividend arrearages were eliminated and which, among other matters, deferred $44 million of debt service requirements, increased stockholders' equity by approximately $82 million and eliminated $9.2 million of annual preferred dividend requirements (see Note C of Notes to Consolidated Financial Statements in Item 8). In addition, the Company entered into a $125 million corporate Revolving Credit Facility and obtained $15 million financing for a major addition to the Company's refinery. These accomplishments, together with the Company's cash flows from operations, enabled the Company to invest $99.6 million in capital projects during 1994 and have better positioned the Company for future profitability and growth.
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 operating margins and liquidity are subject to fluctuation in response to changes in the supply of and demand for crude oil, natural gas and refined petroleum products, market uncertainty and a variety of additional factors that are beyond the control of the Company. These factors include, among others, the level of consumer product demand, weather conditions, the proximity of the Company's natural gas reserves to pipelines, the capacities of such pipelines, fluctuations in seasonal demand, governmental regulations, the price and availability of alternative fuels and overall economic conditions. The Company cannot predict the future markets and prices for the Company's natural gas or refined products and the resulting future impact on earnings and cash flows. Due to the effect of depressed market conditions (see "Results of Operations" below), the Company's operations will continue to be adversely affected for so long as these market conditions exist. The Company's future capital expenditures, borrowings under its credit arrangements and other sources of capital will be affected by these conditions.
CREDIT ARRANGEMENTS
During April 1994, the Company entered into a three-year, $125 million corporate Revolving Credit Facility with a consortium of ten banks, replacing certain interim financing arrangements. The Revolving Credit Facility, which is subject to a borrowing base, provides for (i) the issuance of letters of credit up to the full amount of the borrowing base as calculated and (ii) cash borrowings up to the amount of the borrowing base attributable to domestic oil and gas reserves. Outstanding obligations under the Revolving Credit Facility are secured by liens on substantially all of the Company's trade accounts receivable and product inventory and by mortgages on the Company's refinery and South Texas natural gas reserves. At December 31, 1994, the borrowing base of approximately $107 million included a domestic oil and gas reserve component of $45 million. At December 31, 1994, the Company had outstanding letters of credit under the Revolving Credit Facility of approximately $48 million with no cash borrowings outstanding. Although at December 31, 1994 there were no cash borrowings outstanding under the Revolving Credit Facility, the Company expects to incur short-term borrowings from time to time in 1995 under the Revolving Credit Facility to finance working capital requirements and, to a lesser extent, capital expenditures.
Under the terms of the Revolving Credit Facility, as amended, the Company is required to maintain specified levels of working capital, tangible net worth, consolidated cash flow and refinery cash flow, as defined in the Revolving Credit Facility. Among other matters, the Revolving Credit Facility has certain restrictions with respect to (i) capital expenditures, (ii) incurrence of additional indebtedness, and (iii) dividends on capital stock. The Revolving Credit Facility contains other covenants customary in credit arrangements of this kind. During the third and fourth quarters of 1994, the Company did not satisfy the refinery cash flow requirement which required a waiver and an amendment to the Revolving Credit Facility. Future compliance with financial covenants under the amended Revolving Credit Facility is primarily dependent on the
Company's cash flows from operations, capital expenditures, levels of borrowings under the Revolving Credit Facility and the value of the Company's domestic oil and gas reserves. Based on current market conditions, including the volatility in refinery margins and the recent downturn in the price of natural gas, continued compliance with such covenants is not assured. If the Company is not able to continue to comply with its financial covenants, it will be required to seek waivers or amendments from its banks. If such an event occurs, the Company believes it will be able to negotiate terms and conditions with its banks under the Revolving Credit Facility which will allow the Company to adequately finance its operations. For further information concerning such restrictions and covenants, see Note I of Notes to Consolidated Financial Statements in Item 8.


Item 8.
1994 COMPARED TO 1993. The Exploration and Production segment's U.S. operations, which are concentrated in the Bob West Field in South Texas, achieved a record level of operating profit in 1994. Successful development drilling in the Bob West Field increased the number of producing wells in which the Company has a working interest to 46 at year-end 1994, compared with 25 at the end of 1993, resulting in a 116% increase in the Company's U.S. natural gas production. Revenues from the U.S. operations increased by $42.6 million in 1994 primarily due to the increased production. However, revenues were adversely impacted by a 15% decline in the weighted average sales price, which included a 19% 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 lifting costs and depreciation, depletion and amortization were higher in 1994 due to the increased production level, but were relatively unchanged on a per Mcf basis.
Tennessee Gas may elect, and from time to time has elected, not to take gas under the Tennessee Gas Contract. The Company recognizes revenues under the Tennessee Gas Contract based on the quantity of natural gas actually taken by Tennessee Gas. While Tennessee Gas has the right to elect not to take gas during any contract year, this right is subject to an obligation to pay, within 60 days after the end of such contract year, for gas not taken. The contract year ends on January 31 of each year. Although the failure to take gas could adversely affect the Company's income and cash flows from operating activities within a contract year, the Company should recover reduced cash flows shortly after the end of the contract year under the take-or-pay provisions of the Tennessee Gas Contract, subject to the provisions of a bond posted by Tennessee Gas which is discussed in "Capital Resources and Liquidity -- Tennessee Gas Contract" and Notes L and P of Notes to Consolidated Financial Statements in Item 8.
From time to time, the Company may increase or decrease its natural gas production in response to market conditions. As a result of weakened spot market gas prices, beginning in January 1995, the Company and one of its partners initiated a voluntary reduction of natural gas production sold in the spot market. The Company's share of this reduction is estimated to be approximately 34 Mmcf per day. Primarily as a result of this voluntary reduction, the Company's share of spot natural gas production in South Texas averaged 77 Mmcf per day in January 1995 as compared to 104 Mmcf per day in December 1994. This voluntary reduction has continued through February 1995.
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. Natural gas production volumes in early 1995 have declined to approximately 19,400 average daily Mcf from the 22,100 average daily Mcf in 1994. 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. The contract between YPFB and YPF, which was recently extended through March 31, 1997, maintains approximately the same volumes as their previous contract, but with a small decrease in price. The Company's contract for the sale of natural gas to YPFB has expired and is subject to renegotiation. The Company is currently selling its natural gas production to YPFB based on the pricing terms in the contract between YPFB and YPF. The Company anticipates that any renegotiation of its contract with YPFB will result in the Company receiving a lower price than it received under the previous contract. Any renegotiation may also result in a reduction of volumes purchased from the Company due to new supply sources that commenced production near the end of 1994.
1993 COMPARED TO 1992. The number of producing wells in the United States in which the Company has an interest increased to 25 at year-end 1993 compared with ten at the end of 1992. The resulting increase in the Company's U.S. production levels contributed to higher revenues. However, the increase in production was partially offset by a decline in average sales prices to $3.55 per Mcf in 1993 from $3.68 per Mcf in 1992. Total lifting costs and depreciation, depletion and amortization increased in 1993 due to the higher production volumes; however, the depletion rate decreased due to a 63% increase in proved reserves.
The Bolivian operations experienced a decline in revenues in 1993 primarily due to reduced contractual sales prices for natural gas production. The 1992 operating results from the Indonesian operations, which were sold effective May 1, 1992, included a $5.8 million gain from the sale.
OIL FIELD SUPPLY AND DISTRIBUTION
1994 COMPARED TO 1993. Although sales volumes of refined products increased by 6% in 1994, sales prices and gross margins continued to be impacted by strong competition in an oversupplied market. By consolidating certain of the Company's terminals and discontinuing the environmental products marketing operations, operating expenses and other 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. The Company is continuing its wholesale marketing of fuel and lubricants.
1993 COMPARED TO 1992. Revenues and costs of sales in this segment decreased in 1993 due to the discontinuance of a wholesale distribution operation in Oklahoma during the second quarter of 1992. In addition, the decrease in crude oil prices during 1993 resulted in a corresponding decrease in refined product prices. Notwithstanding such decreases, margins on both refined product and merchandise sales improved in 1993 due to the consolidation of certain of the Company's locations and elimination of marginally profitable locations, including the facility in Oklahoma. Effective at year-end 1992, the Company acquired the remaining 50% interest in Tesoro-Leevac Petroleum Company, a joint venture, which allowed the Company to consolidate certain of its marine terminals; however, this acquisition did not have a material impact on the revenues and margins of this segment in 1993.
GENERAL AND ADMINISTRATIVE EXPENSES
General and administrative expenses of $14.7 million in 1994 compare with $16.7 million in 1993 and $25.9 million in 1992. The Company continues to closely monitor corporate activities in an effort to minimize costs. These efforts resulted in a 12% decrease in general and administrative expenses in 1994. The decrease in 1993, compared with 1992, was primarily due to the inclusion in 1992 of expenses for a cost reduction program and other employee terminations totaling $9.1 million, of which $1.3 million was charged to the operating segments. There were no significant comparable charges recorded in 1994 or 1993. The remaining decrease in 1993 was attributable to the effects of the cost reduction program.
GAIN ON SALES OF ASSETS
During 1994, the Company realized a gain of $2.4 million from the sale of assets, primarily a terminal facility in Valdez, Alaska. The sale of assets during 1993 was immaterial, whereas 1992 included a $5.8 million gain from the sale of the Company's Indonesian operations, partially offset by a $1.8 million loss from the sale of drilling rigs and costs related to the disposition of the Company's remaining oil field tool rental assets.
INTEREST EXPENSE
Interest expense of $18.7 million in 1994 compares with $14.5 million in 1993 and $21.1 million in 1992. The increase in 1994 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 capitalized interest in 1994 related to construction of the vacuum unit. When comparing 1993 with 1992, the change was also due to the reduction related to the resolution of state tax issues.
INCOME TAXES
Income taxes of $5.6 million in 1994 compare with $1.7 million in 1993 and $5.4 million in 1992. 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. The decrease in 1993, compared with 1992, was also due to the reduction related to state tax issues together with lower foreign income taxes resulting from the Company's reduced revenues from its Bolivian operations.
IMPACT OF CHANGING PRICES
The Company's operating results and cash flows are sensitive to the volatile changes in energy prices. Major shifts in the cost of crude oil and the price of refined products can result in a change in gross margin from the refining and marketing operations, as prices received for refined products may or may not keep pace with changes in crude oil costs. These energy prices, together with volume levels, also determine the carrying value of crude oil and refined product inventory.
Likewise, changes in natural gas prices impact revenues and the present value of estimated future net revenues and cash flows from the Company's exploration and production operations. The carrying value of oil and gas assets may also be subject to noncash write-downs based on changes in natural gas prices and other determining factors.
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, 1994 and 1993, and the related statements of consolidated operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 1994. 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, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles.
As discussed in Note A of Notes to Consolidated Financial Statements, in 1992 the Company changed its methods of accounting for postretirement benefits other than pensions and accounting for income taxes.
DELOITTE & TOUCHE LLP
San Antonio, Texas February 1, 1995
TESORO PETROLEUM CORPORATION
STATEMENTS OF CONSOLIDATED OPERATIONS (IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
- --------------- * Anti-dilutive
The accompanying notes are an integral part of these consolidated financial statements.
TESORO PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS (DOLLARS IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
The accompanying notes are an integral part of these consolidated financial statements.
TESORO PETROLEUM CORPORATION
STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY (IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
The accompanying notes are an integral part of these consolidated financial statements.
TESORO PETROLEUM CORPORATION
STATEMENTS OF CONSOLIDATED CASH FLOWS (IN THOUSANDS)
The accompanying notes are an integral part of these consolidated financial statements.
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 wholesale marketing of fuel and lubricants.
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. Certain previously reported amounts have been reclassified to conform with the 1994 presentation.
CASH AND CASH EQUIVALENTS AND SHORT-TERM INVESTMENTS
The Company considers all highly liquid investments purchased with a maturity of three months or less to be cash equivalents. Short-term debt securities with original maturities in excess of 90 days are classified as short-term investments on the Company's Consolidated Balance Sheets. Cash equivalents and short-term investments are stated at cost, which approximates market value. For information regarding restricted cash, see Note I.
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.
HEDGES
The Company, at times, enters into futures and other contracts in its refining and marketing and natural gas operations to hedge the price risks associated with inventories and anticipated transactions. The impact of changes in the market value of these contracts is deferred until the gain or loss is recognized on the hedged inventory or commitment. At December 31, 1994 and 1993, deferred gains and losses related to hedge transactions were not material. Amounts recognized in the Statements of Consolidated Operations related to these transactions for the years ended December 31, 1994, 1993 and 1992 were not material.
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:
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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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. No gain or loss is recognized on the sale of oil and gas properties except in the case of the sale of properties involving significant remaining reserves. Proceeds from the sale of insignificant reserves and undeveloped properties are applied to reduce the costs in the cost centers.
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.
RETIREE HEALTH CARE AND LIFE INSURANCE BENEFITS
The Company accounts for retiree health care and life insurance benefits in accordance with Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" ("SFAS No. 106"). The projected future cost of providing postretirement benefits other than pensions, such as health care and life insurance, are expensed as employees render service instead of when benefits are paid. Prior to the adoption of SFAS No. 106, the Company had expensed these benefits on a pay-as-you-go basis. The adoption of SFAS No. 106, effective January 1, 1992, resulted in a net charge of $21.6 million, or $1.54 per share, for the cumulative effect of the change in accounting principle for periods prior to 1992, which were not restated. In addition, the adoption of SFAS No. 106 resulted in an increase of $1.2 million, or $.09 per share, in the 1992 net loss before cumulative effect of accounting changes.
INCOME TAXES
The Company accounts for income taxes in accordance with Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" ("SFAS No. 109"). Deferred tax assets and liabilities are recognized for future 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. Under SFAS No. 109, 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. The Company adopted SFAS No. 109 effective January 1, 1992 by recognizing a net benefit of $1.0 million, or $.07 per share, for the cumulative effect of the accounting change. Periods prior to 1992 were not restated. The adoption of SFAS No. 109 did not have a significant effect on 1992 results of operations.
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
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
timing of these accruals coincides with completion of a feasibility study or the Company's commitment to a formal plan of action.
EARNINGS (LOSS) PER SHARE
Primary earnings (loss) per share is calculated on net earnings (loss) 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 (loss) per share was the same as primary earnings (loss) per share since the assumed conversion of preferred stocks to common shares would be anti-dilutive.
NOTE B -- BUSINESS SEGMENTS
The Company's revenues are derived from three business segments: Refining and Marketing, Exploration and Production, and Oil Field Supply and Distribution.
Refining and Marketing includes the operations of the Company's refinery in Kenai, Alaska, which produces gasoline, jet fuel, diesel fuel, and 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 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 $72.3 million, $62.1 million and $28.3 million in 1994, 1993 and 1992, respectively. From time to time, Refining and Marketing exports products to customers in Far Eastern markets. Revenues from such export sales amounted to $5.2 million, $20.5 million and $101.0 million in 1994, 1993 and 1992, respectively.
Exploration and Production is engaged in the exploration, development and production of natural gas, primarily in the Bob West Field in South Texas. In addition to natural gas producing activities, Exploration and Production activities include the transportation of natural gas to processing facilities and common carrier pipelines in the South Texas area. The Company also holds an interest in a joint venture agreement to explore for and produce hydrocarbons in Bolivia. These operations in Bolivia include natural gas and condensate reserves, the majority of which are shut-in awaiting access to gas-consuming markets. See Notes L and P for information regarding a natural gas sales contract that is the subject of litigation.
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 1994, the Company discontinued its environmental remediation products and services operations formerly associated with this segment.
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 general and administrative expenses are not included in determining operating profit. In 1992, the Company sold its Indonesian exploration and production operations, resulting in a $5.8 million gain that is included in operating profit presented below. Also in 1992, revenues and operating profit from the South Texas oil and gas producing activities include $5.4 million from a change in estimate of the Company's revenues from its natural gas production. 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.
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.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE C -- RECAPITALIZATION AND OFFERING
RECAPITALIZATION
In February 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 the applicable accounting effects, were as follows:
(i) The Company 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 satisfied the 1994 sinking fund requirement and, except for $.9 million, will satisfy sinking fund requirements for the Subordinated Debentures through 1997.
The exchange of the Subordinated Debentures was accounted for as an early extinguishment of debt in the first quarter of 1994, resulting in a charge of $4.8 million as an extraordinary loss on this transaction, which represented the excess of the estimated market value of the Exchange Notes over the carrying value of the Subordinated Debentures. The carrying value of the Subordinated Debentures exchanged was reduced by applicable unamortized debt issue costs. No tax benefit was available to offset the extraordinary loss 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 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.
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.
If the Recapitalization and Offering had been completed at the beginning of the year, the pro forma earnings per share before extraordinary loss would have increased from $.77 to $.82 on both a primary and fully diluted basis for the year ended December 31, 1994, reflecting the elimination of all preferred stock dividend requirements and the issuance of additional shares of Common Stock associated with the Recapitalization and Offering reduced by shares of Common Stock acquired and retired upon exercise of the MetLife Louisiana Option.
See Note I for information on the Company's long-term debt, including restrictions on dividend payments.
NOTE D -- RECEIVABLES
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):
Receivables at December 31, 1994 included $17.7 million relating to sales under a natural gas sales contract that is the subject of litigation. Of this amount, $13.2 million represented the difference between the contract price and the price currently being received by the Company under the terms of a court-ordered bonding arrangement. For further information on this litigation, see Notes L and P.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE E -- INVENTORIES
Components of inventories at December 31, 1994 and 1993 were as follows (in thousands):
At December 31, 1994, inventories valued using LIFO were lower than replacement cost by approximately $1.8 million. At December 31, 1993, inventories valued using LIFO approximated replacement cost.
NOTE F -- PROPERTY, PLANT AND EQUIPMENT
Components of property, plant and equipment at December 31, 1994 and 1993 were as follows (in thousands):
NOTE G -- ACCRUED LIABILITIES
The Company's current accrued liabilities as shown in the Consolidated Balance Sheets included the following (in thousands):
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Other liabilities classified as noncurrent in the Consolidated Balance Sheets consisted of the following (in thousands):
NOTE H -- INCOME TAXES
The income tax provision included the following (in thousands):
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.
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):
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table sets 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):
At December 31, 1994, the Company's net operating loss carryforwards were approximately $48.3 million for regular tax and approximately $26.2 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 2004. Also at December 31, 1994, 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.
NOTE I -- LONG-TERM DEBT AND OTHER OBLIGATIONS
Long-term debt and other obligations consisted of the following (in thousands):
Based on closing market prices, at December 31, 1994, the Company estimated that the fair value of the Subordinated Debentures, exclusive of accrued interest, was approximately $65.0 million and the fair value of the Exchange Notes, exclusive of accrued interest, approximated $44.7 million. The carrying value of the other long-term debt and obligations approximated the Company's estimate of the fair value of such items.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
As discussed in Note C, approximately four years of sinking fund requirements on the Subordinated Debentures were satisfied by the exchange offer included in the Recapitalization. After giving effect to the Recapitalization, sinking fund requirements and aggregate maturities of long-term debt and obligations for each of the five years following December 31, 1994 are as follows (in thousands):
REVOLVING CREDIT FACILITY
During April 1994, the Company entered into a three-year, $125 million corporate revolving credit facility ("Revolving Credit Facility") with a consortium of ten banks. The Revolving Credit Facility, which is subject to a borrowing base, provides for (i) the issuance of letters of credit up to the full amount of the borrowing base as calculated, but not to exceed $125 million, and (ii) cash borrowings up to the amount of the borrowing base attributable to domestic oil and gas reserves. The Company currently has $100 million in available commitments under the Revolving Credit Facility. The Company may at any time designate all or a portion of the remaining $25 million under the Revolving Credit Facility as available commitments. Outstanding obligations under the Revolving Credit Facility are secured by liens on substantially all of the Company's trade accounts receivable and product inventory and by mortgages on the Company's refinery and South Texas natural gas reserves.
At December 31, 1994, the borrowing base, which is comprised of eligible accounts receivable, inventory and domestic oil and gas reserves, was approximately $107 million. At December 31, 1994, the Company had outstanding letters of credit under the Revolving Credit Facility of approximately $48 million, with remaining unused available commitments of approximately $52 million. 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 $45 million. Under the terms of the Revolving Credit Facility, 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 cash flow coverage ratio, as defined, while the excess of total available commitments over cash borrowings and outstanding letters of credit incur fees of .5% per annum. The Company pays a fee equal to 1/4 of 1% per annum on amounts that have not been designated as available commitments. Cash borrowings under the Revolving Credit 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 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%, depending upon the Company's cash flow coverage ratio, as defined. At December 31, 1994, there were no cash borrowings under the Revolving Credit Facility.
Under the terms of the Revolving Credit Facility, as amended, the Company is required to maintain specified levels of working capital, tangible net worth, consolidated cash flow and refinery cash flow, as defined in the Revolving Credit Facility. Among other matters, the Revolving Credit Facility has certain restrictions with respect to (i) capital expenditures, (ii) incurrence of additional indebtedness, and (iii) dividends on capital stock. The Revolving Credit Facility contains other covenants customary in credit arrangements of this
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
kind. During the third and fourth quarters of 1994, the Company did not satisfy the refinery cash flow requirement which required a waiver and an amendment to the Revolving Credit Facility. Future compliance with financial covenants under the amended Revolving Credit Facility is primarily dependent on the Company's cash flows from operations, capital expenditures, levels of borrowings under the Revolving Credit Facility and the value of the Company's domestic oil and gas reserves. Based on current market conditions, including the volatility in refinery margins and the recent downturn in the price of natural gas, continued compliance with such covenants is not assured. If the Company is not able to continue to comply with its financial covenants, it will be required to seek waivers or amendments from its banks. If such an event occurs, the Company believes it will be able to negotiate terms and conditions with its banks under the Revolving Credit Facility which will allow the Company to adequately finance its operations.
The Revolving Credit Facility replaced certain interim financing arrangements that the Company had been using since the termination of its prior letter of credit facility in October 1993. The interim financing arrangements that were cancelled in conjunction with the completion of the Revolving Credit Facility included a waiver and substitution of collateral agreement with the State of Alaska and a $30 million reducing revolving exploration and production credit facility. The completion of the Revolving Credit Facility provides the Company significant flexibility in the investment of excess cash balances, as the Company is no longer required to maintain minimum cash balances or to secure letters of credit with cash. At December 31, 1993, the Company had arranged for the issuance of $25.4 million of outstanding letters of credit which were secured by restricted cash deposits.
VACUUM UNIT LOAN
During May 1994, the National Bank of Alaska and the Alaska Industrial Development & Export Authority agreed to provide 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 28 equal quarterly payments beginning April 1995 and bears interest at the unsecured 90-day commercial paper rate, adjusted quarterly, plus 2.6% per annum (7.8% at December 31, 1994) for two-thirds of the amount borrowed and at the National Bank of Alaska floating prime rate plus 1/4 of 1% per annum (8.75% at December 31, 1994) for the remainder. The Vacuum Unit Loan is secured by a first lien on the Company's refinery. At December 31, 1994, the Company had borrowed $15 million under the Vacuum Unit Loan. The Vacuum Unit Loan contains covenants and restrictions similar to those under the Revolving Credit Facility. At December 31, 1994, the Company satisfied all of its covenants except for an annual refinery cash flow requirement, as defined in the Vacuum Unit Loan. The lenders waived this refinery cash flow requirement for the year ended December 31, 1994.
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 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 on January 26, 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, will satisfy sinking fund requirements for the Subordinated Debentures through 1997 (see Note C). At December 31, 1994 and 1993, subordinated debt amounted to $59.1 million (net of discount of $5.5 million) and $98.2 million (net of discount of $10.6 million), respectively. The indenture contains restrictions on payment of dividends on the Company's common stock and purchases or redemptions of common or preferred stocks. Due to losses incurred, as of December 31, 1994 the Company must generate approximately $113 million of future net earnings applicable to common stock or from the issuance of capital stock before future dividends
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
can be paid on common stock or before purchases or redemptions can be made of common or preferred stocks. 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 January 1993, the Company and its subsidiary, Tesoro Alaska Petroleum Company ("Tesoro Alaska"), entered into an agreement ("Agreement") with the State of Alaska ("State") that settled Tesoro Alaska's contractual dispute with the State. In addition to $62 million accrued through September 30, 1992, a charge of $10.5 million for the settlement was included in the Company's operations during the fourth quarter of 1992.
Under the Agreement, Tesoro Alaska 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 that is currently 16 cents and increases to 33 cents on the volume of feedstock processed at the Company's refinery. In 1994 and 1993, the Company's variable payments to the State totaled $2.8 million and $2.6 million, respectively. In January 2002, Tesoro Alaska 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 December 2001 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. Tesoro Alaska'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.
The State's claim against Tesoro Alaska arose out of certain provisions in present and past contracts with the State that required Tesoro Alaska to pay the State additional retroactive amounts if the State prevailed in litigation against the producers of North Slope crude oil ("Producers"). As a result of settlements between the State and the Producers, the State claimed that the royalty oil it sold Tesoro Alaska and others was undervalued to the extent that the Producers undervalued their oil.
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, 1994, the Company had paid $42.1 million to the DOE since 1989. The Company's remaining obligation is to pay $13.2 million, exclusive of interest at 6%, over the next eight 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, 1994), 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 $6.5 million at December 31, 1994.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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, 1994 included assets held under capital leases of $6.2 million with a net book value of $2.1 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. It is the Company's policy to fund costs accrued to the extent such costs are tax deductible. The components of net pension expense for the Company's retirement plan are presented below (in thousands):
In addition to the retirement plan pension expense above, during 1992 the Company recognized a curtailment gain of $1.0 million for employee terminations in conjunction with a cost reduction program.
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):
Retirement plan assets are primarily comprised of common stock and bond funds. Actuarial assumptions used to measure the projected benefit obligations at December 31, 1994, 1993 and 1992 included a discount rate of 8 1/2%, 7% and 9%, respectively, and a compensation increase rate of 6%, 4 1/2% and 6%, respectively. The expected long-term rate of return on assets was 9% for 1994, 1993 and 1992.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
EXECUTIVE SECURITY PLAN
The Company's executive security plan ("ESP") provides executive officers and other key personnel with supplemental death or retirement benefits in addition to those benefits available under the Company's group life insurance and retirement plans. These supplemental retirement benefits are provided by a nonqualified, noncontributory plan and are based on years of service and compensation. Funding is provided based upon the estimated requirements of the plan. The components of net pension expense for the ESP are presented below (in thousands):
During 1994, 1993 and 1992, the Company incurred additional ESP expense of $.4 million, $.5 million and $3.5 million, respectively, for settlement losses and other benefits resulting from a cost reduction program, other employee terminations and sales of assets.
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):
Assets of the ESP consist of a group annuity contract. Actuarial assumptions used to measure the projected benefit obligation at December 31, 1994, 1993 and 1992 included a discount rate of 8 1/2%, 7% and 9%, respectively, and a compensation increase rate of 5%, 4 1/2% and 5%, respectively. The expected long-term rate of return on assets was 9% for 1994, 1993 and 1992.
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
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
insurance plan is noncontributory. The Company continues to fund the cost of postretirement health care and life insurance benefits on a pay-as-you-go basis.
As discussed in Note A, the Company adopted SFAS No. 106 effective January 1, 1992 and incurred a net charge of $21.6 million ($16.1 million for health care benefits and $5.5 million for life insurance benefits) for the cumulative effect of the change in accounting principle. The components of net periodic postretirement benefits expense, other than pensions, for 1994, 1993 and 1992 included the following (in thousands):
The following tables show the status of the plans reconciled with the amounts in the Company's Consolidated Balance Sheets (in thousands):
The weighted average annual assumed rate of increase in the per capita cost of covered health care benefits was assumed to be 8% for 1995, 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,
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
1994 by $3.3 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, 1994, 1993 and 1992 included a discount rate of 8 1/2%, 7% and 8 1/2%, respectively, and a compensation rate increase of 6%, 4 1/2% and 6%, respectively.
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 $547,000, $482,000 and $474,000 during 1994, 1993 and 1992, respectively.
COST REDUCTION PROGRAM AND OTHER EMPLOYEE TERMINATIONS
In addition to the ESP settlement losses and other benefits and the retirement plan curtailment gain discussed above, during 1992 the Company incurred charges of $6.6 million for expenses to implement a cost reduction program and other employee terminations.
NOTE K -- OPERATING LEASES
The Company has various noncancellable operating leases related to convenience stores, equipment, property, vessels and other facilities. Lease terms range from one year to 38 years and generally contain multiple renewal options. Future minimum annual payments for operating leases, existing at December 31, 1994, were as follows (in thousands):
Total rental expense was approximately $33.6 million, $32.5 million and $24.3 million for 1994, 1993 and 1992, respectively. Rental expense for 1994, 1993 and 1992 included $24.6 million, $22.9 million and $12.0 million, respectively, related to the lease of vessels used to transport crude oil and refined products to and from the Company's refinery. The lease on one vessel expired in October 1994 and was replaced with a charter agreement for another vessel. This charter agreement expires in September 1996 and contains two one-year renewal options. The Company has a charter for another vessel under a one-year agreement expiring in January 1996.
NOTE L -- COMMITMENTS AND CONTINGENCIES
GAS PURCHASE AND SALES CONTRACT
The Company is selling a portion of the gas from its Bob West Field to Tennessee Gas Pipeline Company ("Tennessee Gas") under a Gas Purchase and Sales Agreement (the "Tennessee Gas Contract") which provides that the price of gas shall be the maximum price as calculated in accordance with Section 102(b)(2) (the "Contract Price") of the Natural Gas Policy Act of 1978 (the "NGPA"). Tennessee Gas filed suit against the Company in the District Court of Bexar County, Texas alleging that the Tennessee Gas Contract is not applicable to the Company's properties and that the gas sales price should be the price calculated under the provisions of Section 101 of the NGPA rather than the Contract Price. During December 1994, the
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Contract Price was in excess of $8.00 per Mcf, the Section 101 price was $4.81 per Mcf and the average spot market price was $1.56 per Mcf. Tennessee Gas also claimed that the contract should be considered an "output contract" under Section 2.306 of the Texas Business and Commerce Code and that the increases in volumes tendered under the contract exceeded those allowable for an output contract.
The District Court judge returned a verdict in favor of the Company on all issues. On appeal by Tennessee Gas, the Court of Appeals for the Fourth Supreme Judicial District of Texas affirmed the validity of the Tennessee Gas Contract as to the Company's properties and held that the price payable by Tennessee Gas for the gas was the Contract Price. The Court of Appeals remanded the case to the trial court based on its determination (i) that the Tennessee Gas Contract was an output contract and (ii) that a fact issue existed as to whether the increases in the volumes of gas tendered to Tennessee Gas under the contract were made in bad faith or were unreasonably disproportionate to prior tenders. The Company sought review of the appellate court ruling on the output contract issue in the Supreme Court of Texas. Tennessee Gas also sought review of the appellate court ruling denying the remaining Tennessee Gas claims in the Supreme Court of Texas. The Supreme Court of Texas heard arguments in December 1994 regarding the output contract issue and certain of the issues raised by Tennessee Gas but has not yet issued its opinion.
Although the outcome of any litigation is uncertain, management, based upon advice from outside legal counsel, is confident that the decision of the trial and appellate courts will ultimately be upheld as to the validity of the Tennessee Gas Contract and the Contract Price. If the Supreme Court of Texas were to affirm the appellate court ruling, the Company believes that the only issue for trial should be whether the increases in the volumes of gas tendered to Tennessee Gas from the Company's properties were made in bad faith or were unreasonably disproportionate. The appellate court decision was the first reported decision in Texas holding that a take-or-pay contract was an output contract. As a result, it is not clear what standard the trial court would be required to apply in determining whether the increases were in bad faith or unreasonably disproportionate. The appellate court acknowledged in its opinion that the standards used in evaluating other kinds of output contracts would not be appropriate in this context. The Company believes that the appropriate standard would be whether the development of the field was undertaken in a manner that a prudent operator would have undertaken in the absence of an above-market sales price. Under that standard, the Company believes that, if this issue is tried, the development of the Company's gas properties and the resulting increases in volumes tendered to Tennessee Gas will be found to have been reasonable and in good faith. Accordingly, the Company has recognized revenues, net of production taxes and marketing charges, for natural gas sales through December 31, 1994, under the Tennessee Gas Contract based on the Contract Price, which net revenues aggregated $36.9 million more than the Section 101 prices and $69.5 million in excess of the spot market prices. If Tennessee Gas were ultimately to prevail in this litigation, the Company could be required to return to Tennessee Gas $52.5 million, plus interest if awarded by the court, representing the difference between the spot market price and the Contract Price received by the Company through September 17, 1994 (the date on which the Company entered into a bond agreement discussed below). An adverse judgment in this case could have a material adverse effect on the Company.
On August 4, 1994, the trial court rejected a motion by Tennessee Gas to post a supersedeas bond in the form of monthly payments into the registry of the court representing the difference between the Contract Price and spot market price of gas sold to Tennessee Gas pursuant to the Tennessee Gas Contract. The court advised Tennessee Gas that should it wish to supersede the judgment, Tennessee Gas had the option to post a bond which would be effective only until August 1, 1995, in an amount equal to the anticipated value of the Tennessee Gas Contract during that period. In September 1994, the court ordered that, effective until August 1, 1995, Tennessee Gas (i) take at least its entire monthly take-or-pay obligation under the Tennessee Gas Contract, (ii) pay for gas at $3.00 per Mmbtu, which approximates $3.00 per Mcf (the "Bond Price"), and (iii) post a $120 million bond with the court representing an amount which, together with anticipated sales of natural gas to Tennessee Gas at the Bond Price, will equal the anticipated value of the Tennessee Gas Contract during this interim period. The Bond Price is nonrefundable by the Company, and the Company
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
retains the right to receive the full Contract Price for all gas sold to Tennessee Gas. The Company continues to recognize revenues under the Tennessee Gas Contract based on the Contract Price. At December 31, 1994, the Company had recognized cumulative revenues in excess of spot market prices (through September 17, 1994) and in excess of the Bond Price (subsequent to September 17, 1994) totaling $65.7 million. Receivables at December 31, 1994 included $17.7 million from Tennessee Gas, of which $13.2 million represented the difference between the Contract Price and the Bond Price. For further information concerning the effect of the Tennessee Gas Contract on certain of the Company's revenues and cash flows, see Note P.
ENVIRONMENTAL
The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, which change frequently, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites or install additional controls or other modifications or changes in use for certain emission sources. The Company is currently involved with a waste disposal site in Louisiana at which it has been named a potentially responsible party under the Federal Superfund law. Although this law might impose joint and several liability upon each party at the site, the extent of the Company's allocated financial contribution to the cleanup of this site is expected to be limited based upon the number of companies and the volumes of waste involved and the payment by the Company of a de minimus settlement amount of $2,500 at a similar site in Louisiana. The Company is also involved in remedial responses and has incurred cleanup expenditures associated with environmental matters at a number of sites, including certain of its own properties. In addition, the Company is holding discussions with the Department of Justice ("DOJ") concerning the assessment of penalties with respect to certain alleged violations of regulations promulgated under the Clean Air Act as discussed below.
In March 1992, the Company received a Compliance Order and Notice of Violation from the Environmental Protection Agency (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 has proposed a penalty assessment of approximately $3.7 million. The Company is continuing to negotiate with the DOJ but cannot predict the ultimate outcome of the negotiations.
At December 31, 1994, the Company's accruals for environmental matters, including the alleged violations of the Clean Air Act, amounted to $10.8 million. Based on currently available information, including the participation of other parties or former owners in remediation actions, the Company believes these accruals are adequate. In addition, to comply with environmental laws and regulations, the Company anticipates that it will be required to make capital improvements in 1995 of approximately $2 million, primarily for the removal and upgrading of underground storage tanks, and approximately $8 million during 1996 for the installation of dike liners required under Alaska environmental regulations. Conditions that require additional expenditures may exist for various Company sites, including, but not limited to, the Company's refinery, retail gasoline outlets (current and closed locations) and petroleum product terminals, and for compliance with the Clean Air Act. The amount of such future expenditures cannot currently be determined by the Company.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
OTHER
The Company transports its crude oil and a substantial portion of its refined products utilizing Kenai Pipe Line Company's ("KPL") pipeline and marine terminal facilities in Kenai, Alaska. In March 1994, KPL filed a revised tariff with the Federal Energy Regulatory Commission ("FERC") for dock loading services, which would have increased the Company's annual cost of transporting products through KPL's facilities from $1.2 million to $11.2 million. Following FERC's rejection of KPL's tariff filing and the commencement of negotiations for the purchase by the Company of the dock facilities, KPL filed a temporary tariff that has increased the Company's annual cost by approximately $1.5 million. The Company and KPL have entered into an agreement for the purchase by the Company of KPL, subject to regulatory approval. The Company expects that this purchase transaction will be consummated in early 1995.
In July 1994, a former customer of the Company ("Customer") filed suit against the Company in the United States District Court for the District of New Mexico for a refund in the amount of approximately $1.2 million, plus interest of approximately $4.4 million and attorney's fees, related to a gasoline purchase from the Company in 1979. The Customer also alleges entitlement to treble damages and punitive damages in the aggregate amount of $16.8 million. The refund claim is based on allegations that the Company renegotiated the acquisition price of gasoline sold to the Customer and failed to pass on the benefit of the renegotiated price to the Customer in violation of Department of Energy price and allocation controls then in effect. The Company cannot predict the ultimate resolution of this matter but believes the claim is without merit.
In February 1995, a lawsuit was filed in the U.S. District Court for the Southern District of Texas, McAllen Division, by the Heirs of H.P. Guerra, Deceased ("Plaintiffs") against the United States and Tesoro and other working and overriding royalty interest owners to recover the oil and gas mineral estate under 2,706.34 acres situated in Starr County, Texas. The oil and gas mineral estate sought to be recovered underlies lands taken by the United States in connection with the construction of the Falcon Dam and Reservoir. In their lawsuit, the Plaintiffs allege that the original taking by the United States in 1948 was unlawful and void and the refusal of the United States to revest the mineral estate to H.P. Guerra or his heirs was arbitrary and capricious and unconstitutional. Plaintiffs seek (i) restoration of their oil and gas estate; (ii) restitution of all proceeds realized from the sale of oil and gas from their mineral estate, plus interest on the value thereof; and (iii) cancellation of all oil and gas leases issued by the United States to Tesoro and the other working interest owners covering their mineral estate. The lawsuit covers a significant portion of the mineral estate in the Bob West Field; however, none of the acreage covered is dedicated to the Tennessee Gas Contract. The Company cannot predict the ultimate resolution of this matter but, based upon advice from outside legal counsel, believes the lawsuit is without merit.
NOTE M -- 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") (collectively, the "Plans"). 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, 1994, the Company had 588,147 shares available for future grants under the 1993 Plan. Shares of unissued Common Stock reserved for the Plans totaled 2,381,603 at December 31, 1994, which included 245,903 shares representing awards granted under the Plans that had not yet been issued.
Stock appreciation rights 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
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 1993 and 1992, no compensation expense was recognized since the market value of the Company's Common Stock remained below the exercise price.
Stock options 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 Plans amounted to 137,253, 83,015 and 100,000 common shares in 1994, 1993 and 1992, respectively. 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, $572,000 and $142,000 in 1994, 1993 and 1992, respectively.
A summary of the activity in the Plans is set forth below:
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE N -- 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. At December 31, 1994, there were 24,389,801 rights outstanding, which will expire in December 1995.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE O -- QUARTERLY FINANCIAL DATA (UNAUDITED)
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 C) 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. The 1993 second and fourth quarters included benefits of $3.0 million and $5.2 million, respectively, for resolution of several state tax issues. A $5.0 million charge for an inventory erosion was recorded in the 1993 third quarter. Included in the 1993 fourth quarter, however, was a $5.7 million offset to the inventory adjustment taken earlier in the year. Inventory levels at year-end 1993 were greater than projected earlier in the year due to changing market conditions. The 1993 fourth quarter benefited from the decline in crude oil prices, while the Company's refined product margins held steady or improved.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE P -- 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 B, have been excluded.
CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES
COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES
The Company's investment in oil and gas properties included $3.8 million in unevaluated properties, which have been excluded from the amortization base as of December 31, 1994. The Company anticipates that the majority of these costs, substantially all of which were incurred in 1994, will be included in the amortization base during 1995.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES
The following table sets forth the results of operations for oil and gas producing activities, in the aggregate by geographic area, with income tax expense computed using the statutory tax rate for the period adjusted for permanent differences, tax credits and allowances.
- --------------- (1) See Note L regarding litigation involving a natural gas sales contract.
(2) Excludes corporate general and administrative and financing costs.
(3) Represents gain from the sale of the Company's Indonesian operations effective May 1, 1992.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 Statement of Financial Accounting Standards No. 69 ("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 after income taxes.
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 L, 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 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 standardized measure of discounted future net cash flows relating to proved reserves in the United States at December 31, 1994 was $127 million, compared with $73 million at spot market prices.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED RESERVES (UNAUDITED)
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)
- --------------- (1) See Note L regarding litigation involving a natural gas sales contract.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
RESERVE INFORMATION (UNAUDITED)
The following estimates of the Company's proved oil and gas reserves are based on evaluations prepared by Netherland, Sewell & Associates, Inc. (except for estimates of reserves at December 31, 1991 for properties in Bolivia and Indonesia, which estimates were prepared by the Company's in-house engineers). 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.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
- --------------- (1) The Company was not required to file reserve estimates with federal authorities or agencies during the periods presented.
(2) See Note L regarding litigation involving a natural gas sales contract.
(3) No major discovery or adverse event has occurred since December 31, 1994 that would cause a significant change in proved reserves.
ITEM 9.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.



ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information required under this Item will be contained in the Company's 1995 Proxy Statement, incorporated herein by reference.
See also Executive Officers of the Registrant under Business in Item 1.
ITEM 11.

ITEM 11. EXECUTIVE COMPENSATION
Information required under this Item will be contained in the Company's 1995 Proxy Statement, incorporated herein by reference.
ITEM 12.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information required under this Item will be contained in the Company's 1995 Proxy Statement, incorporated herein by reference.
ITEM 13.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information required under this Item will be contained in the Company's 1995 Proxy Statement, incorporated herein by reference.
PART IV
ITEM 14.

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:
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.
3. EXHIBITS
(b) REPORTS ON FORM 8-K
No reports on Form 8-K were filed by the Company during the quarter ended December 31, 1994.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
TESORO PETROLEUM CORPORATION
March 16, 1995 By: /s/ MICHAEL D. BURKE ------------------------------------ Michael D. Burke President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
EXHIBIT INDEX