ITEM 1. BUSINESS
Tesoro Petroleum Corporation, together with its subsidiaries ("Tesoro" or the "Company"), is a natural resource company engaged primarily in petroleum refining and marketing, natural gas exploration and production, marketing and distributing of petroleum products and providing marine logistics services. The Company was incorporated in Delaware in 1968 (a successor by merger to a California corporation incorporated in 1939). For financial information relating to industry segments, see Management's Discussion and Analysis of Financial Condition and Results of Operations in Item 7 and Note B of Notes to Consolidated Financial Statements in Item 8.
REFINING AND MARKETING
OVERVIEW
The Company conducts petroleum refining operations in Alaska and sells refined products to a wide variety of customers in Alaska, along the U.S. West Coast, in the Pacific Northwest and in certain Far Eastern markets, including Russia. During 1996, products from the Company's refinery accounted for approximately 79% of these sale volumes, including products received on exchange in the U.S. West Coast market, with the remaining 21% being purchased from other refiners and suppliers. The Company's purchases from other refiners and suppliers declined in 1996 as the Company withdrew from certain California markets which is further discussed below.
The Company's refinery, which is located in Kenai, Alaska, has a rated throughput capacity of 72,000 barrels per day and is capable of producing liquefied petroleum gas, gasoline, jet fuel, diesel fuel, heating oil, heavy oils and residual products. Alaska North Slope ("ANS") and Cook Inlet crude oils are the primary feedstocks for the refinery. To assure the availability of crude oil to the refinery, the Company has a royalty crude oil purchase contract with the State of Alaska ("State") (see "Crude Oil Supply" discussed below). During 1996, the refinery processed approximately 72% ANS crude oil, 25% Cook Inlet crude oil and 3% other refinery feedstocks, which yielded refined products consisting of approximately 26% gasoline, 41% middle distillates, 28% heavy oils and residual products and 5% other products.
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 1996, approximately 72% of the refinery's feedstock was ANS crude oil, of which approximately 39,200 barrels per day were purchased under a royalty crude oil purchase contract with the State. The contract with the State, which covers the period January 1, 1996 through December 31, 1998, provides for the purchase of approximately 40,000 barrels per day of ANS royalty crude oil and is priced based on royalty values computed by the State. Under the contract, the Company is required to utilize in its refinery operations volumes equal to at least 80% of the ANS crude oil to be purchased from the State. This contract contains provisions that, under certain conditions, allow the Company to temporarily or permanently reduce its purchase obligation.
All ANS crude oil feedstock is delivered to the refinery by tanker through the Kenai Pipe Line Company ("KPL") marine terminal which the Company purchased in early 1995.
For information related to settlement of a contractual dispute with the State in 1993, see Note I of Notes to Consolidated Financial Statements in Item 8.
Cook Inlet Crude Oil. Cook Inlet crude oil, a lighter crude oil that contains an average of .1% sulphur, accounted for approximately 25% of the refinery's feedstock supply in 1996. The Company obtains Cook Inlet crude oil from several producers on the Kenai Peninsula under short-term contracts. Cook Inlet crude oil is
delivered by tanker through the Company's KPL marine terminal or through an existing pipeline to the refinery.
Other Supply. In 1996, the Company's refinery obtained approximately 3% of its feedstock supply from other sources. The other supply consisted of heavy atmospheric gas oil ("HAGO") and foreign crude oil. The HAGO feedstock was purchased from a local competitor's refinery and from a U.S. West Coast refinery under short-term contracts. HAGO is a refinery by-product which generates various light refined products with no residual fuel oil. Foreign crude oil, purchased in spot quantities, is delivered to the refinery by tanker through the Company's KPL marine terminal. The Company evaluates the economic viability of processing foreign crude oil in its refinery and will occasionally purchase spot quantities to supplement its normal crude oil supply. During 1996, the Company imported its first cargo of crude oil from Russia.
REFINING AND MARKETING ACTIVITIES
The following table summarizes the Company's refining and marketing operations:
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(1) Branded gasoline outlets sell the Company's gasoline under the "Tesoro Alaska" name. Outlets that sell the Company's gasoline under a different name are considered unbranded.
The Company's refinery production was reduced in September 1996 for a scheduled 30-day maintenance downtime. During the maintenance period, the hydrocracker catalyst was replaced and, beginning in the fourth quarter of 1996, the Company was able to produce higher volumes of jet fuel, which better matches the Company's production with demand in Alaska. To further improve the refinery's feedstock and product slate, the Company intends to modify the refinery hydrocracker during 1997 at an estimated cost of $17 million. In conjunction with the modification and other initiatives, a refinery downtime of approximately 30 days is anticipated during 1997.
ALASKA MARKETING
Gasoline. The Company distributes gasoline to end users in Alaska, either by retail sales through its 7-Eleven convenience store locations, by wholesale sales through 126 branded and 29 unbranded dealers and jobbers or by deliveries to major oil companies for their retail operations in Alaska in exchange for gasoline delivered to the Company on the U.S. West Coast. In 1996, the Company continued implementing initiatives to increase the Company's share of gasoline sales in Alaska and added 31 stations to its marketing network, including its initial expansion into Southeast Alaska with nine locations. Two uneconomic outlets were closed in 1996. The Company holds an exclusive license agreement for all 7-Eleven convenience stores in Alaska and operates such stores in 36 locations, 33 of which sell Company-branded gasoline. During 1996, these convenience stores sold an average of 53,000 gallons of gasoline per day. Gasoline produced in excess of Alaska's market demand is shipped to the U.S. West Coast or exported to the Far East by chartered vessel.
Middle Distillates. The Company is a major supplier of commercial jet fuel into the Alaskan marketplace, with all of its production being marketed in Alaska to passenger and cargo airlines. The demand for jet fuel in Alaska currently exceeds the production of all refiners in Alaska, and several marketers, including the Company, import jet fuel into Alaska to meet excess demand. Substantially all of the Company's diesel fuel production is sold on a wholesale basis in Alaska primarily for marine and industrial purposes. Generally, the production of diesel fuel by refiners in Alaska is in balance with demand; however, because of the high variability of the demand, there are occasions when diesel fuel is imported into or exported from Alaska. See "Government Regulation and Legislation -- Environmental Controls" for a discussion of the effect of governmental regulations on the production of low-sulphur diesel fuel for on-highway use in Alaska.
Heavy Oils and Residual Products. The refinery's vacuum unit uses residual fuel oil as a feedstock 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.
In 1996, the Company began producing liquid asphalt, a heavy product left after petroleum is refined into gasoline and other products. Liquid asphalt, which is used in the manufacturing of concrete asphalt for paving, was sold to customers in Alaska and California. This product is seasonal in the Alaska market due to mild weather conditions needed for highway construction.
U.S. WEST COAST AND PACIFIC NORTHWEST MARKETING
In 1996, the Company conducted wholesale marketing operations, primarily in Oregon and Washington, selling refined products in the bulk market and through nine terminal facilities, including four owned by the Company during the year. To a lesser extent, the Company sold refined products through numerous other terminals to facilitate disposal of inventories in California. In 1996, these operations sold approximately 14,000 barrels per day of refined products, primarily gasoline and diesel fuel, of which approximately 19% was received from major oil companies in exchange for products from the Company's refinery, approximately 13% was received directly from the refinery and 68% was purchased from other suppliers.
In 1996, the Company expanded its retail presence in the Pacific Northwest by adding eight branded stations. At year-end 1996, the Company had 18 branded gasoline distributors in Oregon and Washington. The Company will continue to sell refined products in the Pacific Northwest through branded stations in addition to six terminal facilities, one of which is owned by the Company.
Due to market conditions, the Company withdrew from certain West Coast markets and initiated a plan to sell its three Company-owned facilities in California. One of these facilities was sold in December 1996 and two facilities remain for sale at year-end.
TRANSPORTATION
The Company charters an American flag vessel, the Potomac Trader, whose primary use is to transport ANS crude oil from the Trans Alaska Pipeline System ("TAPS") terminal at Valdez, Alaska to the Company's refinery. The Company charters another American flag vessel, the Chesapeake Trader, which is used primarily to transport heavy oils and residual products to the U.S. West Coast and occasionally to transport feedstocks to the Company's refinery. The Potomac Trader and Chesapeake Trader are chartered under five-year agreements expiring in 2000. Under an agreement expiring in June 1997, the Company charters a Russian flag vessel, the Igrim, which is used primarily to transport refined products from the Company's refinery to the Far East. The Company plans to continue marketing its products in the Far East and is evaluating transportation alternatives. From time to time, the Company also charters tankers and ocean-going barges to transport petroleum products to its customers within Alaska, on the U.S. West Coast and in the Far East.
The Company operates a common carrier petroleum products pipeline from the 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 1996, the pipeline transported an average of approximately 22,000 barrels of petroleum products per day, all of which were transported for the Company.
The Company's subsidiary, KPL, is a common carrier pipeline and marine dock facility. By owning this facility, the Company is assured of uninterrupted use of the dock and pipeline for unloading crude oil feedstocks and loading product inventory on tankers and barges. During 1996, KPL transported approximately 47,200 barrels of crude oil per day and 34,100 barrels of refined products per day, all of which were transported for the Company.
For further information on transportation in Alaska, see "Government Regulation and Legislation -- Environmental Controls."
EXPLORATION AND PRODUCTION
OVERVIEW
The Exploration and Production segment is engaged in the exploration, development and production of natural gas and oil, primarily in the Wilcox Trend in South Texas and the Chaco Basin in Bolivia. In the U.S., the Company's focus has recently shifted outside of the maturing Bob West Field in South Texas to other areas. During 1996 and early 1997, the Exploration and Production segment purchased interests in the Frio/Vicksburg Trend adjacent to the Wilcox Trend in South Texas, the Cotton Valley Pinnacle Reef Play in East Texas and the Val Verde Basin in Southwest Texas. This segment also includes the transportation of natural gas, including the Company's production, to common carrier pipelines in the South Texas area. In Bolivia, the Company operates through two contracts with the Bolivian government to explore for and produce hydrocarbons. The Company's Bolivian gas production is sold under contract to the Bolivian government for export to Argentina. The majority of the Company's Bolivian natural gas and oil reserves are shut-in awaiting access to gas-consuming markets which is expected to be provided by a 1,900-mile pipeline from Bolivia to Brazil. The pipeline is scheduled to begin construction in late 1997, with first gas deliveries expected in 1999.
UNITED STATES
Bob West Field. The Bob West Field, which was discovered by the Company in 1990, is located in the southern part of the Wilcox Trend in Starr and Zapata counties, Texas. The Wilcox Trend extends from Northern Mexico through South Texas into the other Gulf Coast states. Multiple pay sands exist within the Wilcox Trend, where extensive faulting has trapped hydrocarbons in numerous producing zones. Continued successful development of the Bob West Field led to the completion of 12 gross development wells during 1996. One well was being drilled at year-end and three additional well locations, all of which are expected to be drilled during 1997, have been selected for further development of this 4,000-acre field. During 1996, the
Company's net production from the Bob West Field averaged approximately 82 million cubic feet ("Mmcf") per day.
The Company's revenue interests in the Bob West Field range from 28% to 57% and its working interests range from 33% to 70%. In addition, the Company owns a 70% interest in the field's central gas processing facility which has a capacity of 350 Mmcf per day. The Company also owns 25% of a central compression facility, rated at 10,000 horsepower with an estimated capacity of 150 Mmcf per day, that was installed in the Bob West Field in late 1996. During the first two months of operation, the Company's production in the Bob West Field increased by approximately 9 Mmcf per day primarily as a result of the new compression facility.
Other Areas. In addition to the continued development of the Bob West Field, during 1996 the Company also participated in the drilling of six exploratory wells in other portions of the Wilcox Trend in South Texas, four of which were successfully completed as producing wells.
In December 1996, the Company purchased 25% to 50% interests in portions of the Los Indios and La Reforma Fields, located in Hidalgo and Starr counties of South Texas, for $15 million. The two fields are located in the Frio/Vicksburg Trend, which lies immediately adjacent to the Wilcox Trend. The Company's working interest covers 11,700 acres and the acquisition is over 90% natural gas. The area is believed to have significant further development potential beyond the current net production of 6 Mmcf equivalents ("Mmcfe") per day and net proved reserves acquired of 20 billion cubic feet equivalents ("Bcfe"). The acquisition includes recent three-dimensional seismic data covering nearly 50 square miles which will be used to exploit the remaining reserve potential of the properties. Tesoro will jointly operate the fields with a private producer.
During 1996, the Company also acquired interests in the Berry R. Cox and the West Goliad Fields for a total of $5.4 million. Both fields are located in South Texas in the Wilcox Trend. The acquisitions consisted of ten wells producing at initial rates totaling 6.7 Mmcfe per day. Workovers and recompletions have increased production to a total of 9.3 Mmcfe per day at year-end. In January 1997, one exploratory well and one development well were drilled and completed on these prospects and these wells are producing at a combined rate of 5.5 Mmcfe per day.
Also, in 1996, the Company purchased approximately 35,000 net undeveloped acres for a total of $5.3 million. The acquired acreage is located in four areas, the Cotton Valley Pinnacle Reef Play in East Texas, the Val Verde Basin in Southwest Texas, the Frio/Vicksburg Trend in South Texas and the Wilcox Trend in South Texas.
Reserves. The following table shows the estimated net proved reserves, based on evaluations prepared by Netherland, Sewell & Associates, Inc., and gross producing wells for each of the Company's U.S. fields as of December 31, 1996, compared with certain data at December 31, 1995:
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(1) Represents the discounted future net cash flows before income taxes. See Note O of Notes to Consolidated Financial Statements in Item 8 for additional information regarding the Company's proved reserves and standardized measure.
Tennessee Gas Contract. In August 1996, the Supreme Court of Texas denied a motion for rehearing by Tennessee Gas Pipeline Company ("Tennessee Gas") and upheld all aspects of a Gas Purchase and Sales Agreement ("Tennessee Gas Contract") which had been the subject of litigation since 1990. As provided for in the Tennessee Gas Contract, the Company was selling a portion of the gas produced from two 352-acre producing units in the Bob West Field pursuant to a contract price ("Contract Price"). In 1996, approximately 12% of the Company's total U.S. production was sold under the Tennessee Gas Contract at a Contract Price that averaged $8.41 per thousand cubic feet ("Mcf"), representing 38% of the Company's U.S. natural gas revenues for the year. In December 1996, the Tennessee Gas Contract, which was to expire in January 1999, was terminated by the parties effective October 1, 1996, and the Company began selling this gas on the spot market. See Management's Discussion and Analysis of Financial Condition and Results of Operations in Item 7 and Note D of Notes to Consolidated Financial Statements in Item 8.
Gas Gathering and Transportation. The Company owns a 70% interest in the Starr County Gathering System which consists of two ten-inch diameter pipelines and one twenty-inch diameter pipeline that transport natural gas eight miles from the Bob West Field to common carrier pipeline facilities. In addition, the Company owns a 50% interest in the twenty-inch diameter Starr-Zapata natural gas pipeline that was constructed during 1994 to transport gas 26 miles from the Starr County Gathering System to a market hub at Fandango, Texas. The Company does not operate either facility. During 1996, the gross average daily throughput was 205 Mmcf per day for the Starr County Gathering System and 173 Mmcf per day for the Starr-Zapata pipeline, with approximately 50% of the throughput consisting of the Company's working interest share of Bob West Field production. The Starr County Gathering System receives a transportation fee of $.06 per Mcf and the Starr-Zapata Pipeline receives a fee of $.07 per Mcf for volumes transported.
For further information regarding the Company's U.S. operations, see Notes B, C, N and O of Notes to Consolidated Financial Statements in Item 8.
U.S. Operating Statistics
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(1) Includes effects of the Company's natural gas price agreements which amounted to a loss of $.11 per Mcf in 1996 and a gain of $.01 per Mcf in 1995 and 1994 (see Note N of Notes to Consolidated Financial Statements in Item 8).
(2) See Note D of Notes to Consolidated Financial Statements in Item 8 related to the Tennessee Gas Contract.
(3) Included in total productive wells are 8 gross (.4 net) wells with multiple completions. At January 31, 1997, the Company was participating in the drilling of 8 gross (3.7 net) wells.
(4) Mcfe is defined as net equivalent one thousand cubic feet.
BOLIVIA
The Company's Bolivian exploration and production operations are located in southern Bolivia near the border of Argentina, where the Company has discovered six fields since 1976 with estimated net proved natural gas reserves of 253 Bcfe at December 31, 1996. With gross average production of 55 Mmcfe per day in 1996, Tesoro is one of the largest operators in Bolivia. The Company is the operator of a joint venture that holds two Shared Risk Contracts with Yacimientos Petroliferos Fiscales Bolivianos ("YPFB"), the Bolivian state-owned oil and gas company.
Bolivian Hydrocarbons Law. In 1996, a new Hydrocarbons Law was passed by the Bolivian government that significantly impacts the Company's operations in Bolivia. The new law, among other matters, granted the Company the option to convert its Contracts of Operation to new Shared Risk Contracts. During 1996, the Company signed agreements to convert its Contracts of Operation to Shared Risk Contracts subject to recision at the option of the Company if the Company is not satisfied with modifications to the Bolivian fiscal law. The Company expects to complete this conversion during the first half of 1997. The new contracts extend the Company's term of operation, provide more favorable acreage relinquishment terms and provide for a more favorable fiscal regime of royalties and taxes. The new contracts will extend the term of the Company's operations for Block 18 ten additional years to the year 2017. For Block 20, the new contract extends the Company's term 21 additional years to the year 2029 for acreage that is in the exploration phase of the contract, and 10 additional years to the year 2018 for an area within Block 20 that is designated as being in the development phase of the new contract. The new contract provisions, along with a substantial discovery during 1996, significantly increased the Company's reserves (see Note O of Notes to Consolidated Financial Statements in Item 8).
Access To New Markets. A lack of market access has constrained natural gas production in Bolivia. With little internal gas demand, all of the Company's Bolivian natural gas production is sold under contract to the Bolivian government for export to Argentina. Major developments in South America indicate that new markets may open for the Company's production in the near future. Progress has been made toward construction of a new 1,900-mile pipeline that will link Bolivia's extensive gas reserves with markets in Brazil. In early 1997, a contract to supply pipe for the project was awarded. Construction is scheduled to start in late 1997, with first gas deliveries expected in 1999.
Block 18. The Company has a 75% interest in a Shared Risk Contract, subject to final conversion, expiring in 2017 and covering 92,625 acres in Block 18. During 1996, the Company's net production from this block averaged 20.3 Mmcf of gas per day and 584 barrels of condensate per day.
The new contract for Block 18 provides that the Company and its joint venture participant will continue to be subject to a 29% participation that was stipulated in YPFB's favor in the old contract. In addition, income taxes and taxes on gross revenues will be paid which are expected to equal 31% of Block 18 gross revenues, leaving the Company and its joint venture participant with 40% of Block 18 revenues, after royalties and taxes. The aftertax effect of the new contract is essentially the same as the old contract. The Company is currently selling all of its natural gas production from the La Vertiente, Escondido and Taiguati Fields in Block 18 to YPFB which in turn sells the natural gas to Yacimientos Petroliferos Fiscales, S.A. ("YPF"), a publicly-held company based in Argentina. During 1994, the contract between YPFB and YPF was extended through March 31, 1997, maintaining approximately the same volumes as the previous contract. YPFB and YPF are currently negotiating a two-year contract extension through March 1999. Currently, the Company is selling its natural gas production to YPFB based on the volume and pricing terms in the contract between YPFB and YPF.
Block 20. The Company has a 72.6% interest in a Shared Risk Contract, subject to final conversion, expiring in 2029 and covering 787,313 acres in Block 20. For Block 20, the Company and its joint venture participant will no longer be required to pay a 19% royalty that had been required under the old contract. Under the old contract, taxes on gross revenues were paid to the national and local governments totaling 31% of gross revenues. Under the new contract, a combination of income taxes and taxes on gross revenues are expected to approximate the amount of taxes paid under the old contract. The Company is investigating whether the Bolivian taxes can be treated as creditable for U.S. tax purposes.
During 1996, the Company drilled two discovery wells in Bolivia. The Palo Marcado X-4 found gas in four zones and had a combined test flow rate of 19.1 Mmcf per day. The well will be reentered in 1997 to test a fifth, deeper zone that may also bear hydrocarbons. The discovery added 65 Bcfe of net proved reserves for Tesoro. In 1997, a three-dimensional seismic survey is planned for the Palo Marcado structure, as well as the shut-in Los Suris Field. A second discovery well, the Ibibobo X-2, found hydrocarbons in two zones and was the Company's first oil discovery in the country. Additional three-dimensional seismic work is required to
identify appraisal drilling sites on this structure. Both discoveries, which are shut-in due to a lack of market, are expected to be placed on production following completion of the Bolivia-Brazil pipeline.
Reserves. The table below shows the estimated net proved reserves, based on evaluations prepared by Netherland, Sewell & Associates, Inc., and gross productive wells for each of the Company's Bolivian fields as of December 31, 1996, compared with certain data at December 31, 1995. Each of the following fields is operated by the Company:
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(1) Represents the after Bolivian tax discounted future net cash flows, which included an increase of $23 million at December 31, 1996 due to the anticipated completion of the Bolivia-Brazil pipeline. See Notes B and O of Notes to Consolidated Financial Statements in Item 8 for additional information regarding the Company's proved reserves and standardized measure.
For further information regarding the Company's Bolivian operations, see Notes B and O of Notes to Consolidated Financial Statements in Item 8.
Bolivia Operating Statistics
Bolivia Operating Statistics (Continued)
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(1) Represents the Company's net production before Bolivian taxes, which were payable in-kind for the years presented.
(2) Included in total productive wells are 4 gross (3.0 net) wells with multiple completions. At December 31, 1996, the Company was participating in the drilling of 2 gross (1.5 net) wells.
WORLDWIDE RESERVE REPLACEMENT AND COSTS OF ADDING RESERVES
In 1996, the Company's worldwide proved reserve additions included 113 Bcfe from discoveries, extensions and domestic purchases of proved properties (65 Bcfe from Bolivia and 48 Bcfe domestically); 36 Bcfe from extensions in the terms of the Company's Bolivian contracts and 62 Bcfe from other changes in the Bolivian Hydrocarbons Law; less 4 Bcfe from revisions of previous estimates. Excluding revisions, 211 Bcfe were added for a 517% replacement of 41 Bcfe of production. Additions were realized with an 87.5% drilling success rate during 1996, reflecting a 94% success rate on 16 development wells and a 75% success rate on 8 exploratory wells. The Company's three-year worldwide average cost of adding these reserves was $.53 per Mcfe. Domestically, 48 Bcfe were added for a 151% replacement of 32 Bcfe of production. The three-year average cost of adding domestic reserves was $.94 per Mcfe. See Note O of Notes to Consolidated Financial Statements in Item 8.
MARINE SERVICES
OVERVIEW
The Company's Marine Services segment markets and distributes a broad range of products, including diesel fuel, lubricants, chemicals and supplies, and provides logistical support services to the marine and offshore exploration and production industries operating in the Gulf of Mexico through a network of 20 terminals. These deep water marine terminals are located on the Texas Gulf Coast in Galveston, Freeport, Harbor Island, Port O'Connor, Ingleside and Sabine Pass. The Company also operates along the Louisiana Gulf Coast with terminals in Cameron, Intracoastal City, Morgan City, Venice, Eunice, Amelia and Harahan. These terminals are bulkheaded and dredged to provide easy access to vessels receiving products for delivery to customers. Products are delivered offshore aboard vessels owned or chartered by customers, which include companies engaged in oil and gas exploration and production, seismic evaluation, offshore construction and other drilling-related businesses.
The Marine Services segment achieved profitability in 1996 after a merger and restructuring that established the Company as a major marine terminal operator in the Gulf of Mexico. In February 1996, the Company purchased 100% of the capital stock of Coastwide Energy Services, Inc. ("Coastwide"), a company that provided shore-based services for the offshore exploration and production industry, for approximately 1.4 million shares of Tesoro's Common Stock and $7.7 million in cash. These operations were combined with the Company's marine petroleum distribution operation, forming a Marine Services segment. See Note C of Notes to Consolidated Financial Statements in Item 8.
DIESEL FUEL AND LUBRICANTS
Diesel fuel and lubricants, which are used in operations such as offshore drilling rigs, offshore production and transmission platforms and various ships and equipment engaged in seismic surveys, are marketed and distributed from all 20 of the Company's terminals. Through these terminals and a fleet of six tugboats (including three owned by the Company) and 14 barges (including ten owned by the Company), the Company serves offshore workboats, tugboats and barges using the Intracoastal Canal System, as well as ships
entering the ports of Houston, New Orleans, Lake Charles, Corpus Christi and Port Arthur. Tesoro obtains its supply of diesel fuel from refiners in the Gulf Coast area. Total gallons of diesel fuel and other refined products sold by Marine Services amounted to 142.7 million, 112.5 million and 119.2 million in 1996, 1995 and 1994, respectively. The Company is a distributor of lubricants and cylinder oil produced by certain major oil companies, which are delivered to customers by trucks or barges.
SERVICES
Through nine of its terminals, the Company provides full-service shore-based support for offshore drilling rigs and production platforms. These quayside services include loading docks and slips for offshore supply boats. In addition, the Company provides dispatchers and stevedores, cranes, forklifts, warehouses, office and dormitory accommodations, helicopter landing pads and car parking for offshore workers. Tesoro also serves as delivery points for drilling products, primarily mud, by providing warehousing, inventory control and delivery services. Tesoro's bunkering services operate in major ports along the Texas and Louisiana Gulf Coast. In 1996, 1995 and 1994, revenues from services amounted to $10.9 million, $3.1 million and $2.7 million, respectively.
COMPETITION AND OTHER
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 and other products to the United States, thereby further increasing competition for domestic sales.
The refining and marketing businesses are highly competitive, with price being the principal factor in competition. In the refining market, the Company's refinery competes primarily with other refineries in Alaska and on the U.S. West Coast. The Company's refining competition in Alaska includes a refinery situated near Fairbanks owned by MAPCO, Inc. and two refineries situated near Valdez and Fairbanks owned by Petro Star Inc. The Company estimates that such other refineries have a combined capacity to process approximately 176,000 barrels per day of crude oil. ANS crude oil is the only feedstock used in these competing refineries. After processing the crude oil and removing the lighter-end products, which represent approximately 30% of each barrel processed, these refiners are permitted, because of their direct connection to the TAPS, to return the remainder of the processed crude back into the pipeline system as "return oil" in consideration for a fee, thereby eliminating their need to market residual products. The Company's refinery is not directly connected to the TAPS, and the Company, therefore, cannot return its residual products to the TAPS. The Company's refining competition from the U.S. West Coast includes many large, integrated oil companies that do substantial business in Alaska and have materially greater financial and other resources. A growing number of foreign sources also compete with the Company.
The Company's marketing business in Alaska is segmented by product line. The Company is a substantial producer and distributor of gasoline in Alaska, with the largest network of branded and unbranded dealers and jobbers. The Company is a supplier to a major oil company through a product exchange agreement, whereby gasoline in Alaska is provided in exchange for gasoline delivered to the Company on the U.S. West Coast. Jet fuel sales are concentrated in Anchorage, where the Company is one of the principal suppliers to 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 Pacific Northwest marketing business is primarily a distribution business selling to independent dealers and jobbers outside major urban areas. In addition, the Company sells to 18 branded gasoline distributors in the Pacific Northwest who obtain the majority of their supply from the Company's refinery in Alaska. The Company competes against independent marketing companies and integrated oil companies when engaging in these marketing operations.
Demand for services and products offered by the Company's Marine Services segment is closely related to the level of oil and gas exploration, development and production in the Gulf of Mexico. Various factors, including general economic conditions, demand for and prices of natural gas, availability of equipment and materials and government regulations and energy policies cause exploration and development activity to fluctuate and directly impact the revenues of the Marine Services segment. Management believes that the principal competitive factors affecting the Marine Services operations are location of facilities, availability of logistical support services, experience of personnel and dependability of service. The market for the Marine Services segment's products and services, particularly diesel fuel, is price sensitive. The Company competes with several independent operations, and in certain locations with one or more major mud companies who maintain their own marine terminals.
A portion of the Company's operations are conducted in foreign countries where the Company is also subject to risks of a political nature and other risks inherent in foreign operations. The Company's operations outside the United States in recent years have been, and in the future may be, materially affected by host governments through increases or variations in taxes, royalty payments, export taxes and export restrictions and adverse economic conditions in the foreign countries, the future effects of which the Company is unable to predict.
GOVERNMENT REGULATION AND LEGISLATION
UNITED STATES
Natural Gas 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.
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 was implemented largely 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. The result of the FERC initiatives has brought to an end the interstate pipelines' traditional role as wholesalers of natural gas in favor of providing
only gathering, transportation and storage services for others which will buy and sell natural gas. 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.
In addition, the FERC has announced its intention to reexamine certain of its transportation related policies, including the appropriate manner in which interstate pipelines release transportation capacity under Order No. 636 and, more recently, the price which shippers can charge for released capacity. The FERC has also issued a new policy regarding the use of nontraditional methods of setting rates for interstate gas pipelines in certain circumstances as alternatives to cost-of service based rates. A number of pipelines have obtained FERC authorization to charge negotiated rates as one such alternative.
Although Order No. 636 does not regulate gas producers, such as the Company, 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. The U.S. Court of Appeals for the District of Columbia Circuit has affirmed the Commission's Order No. 636 restructuring rule and remanded certain issues for further explanation or clarification. Numerous petitions seeking judicial review of the individual pipeline restructuring orders are currently pending in the United States Court of Appeals for the District of Columbia Circuit. It is not possible to predict what, if any, effect the order on remand or the Court's decision in the individual pipeline cases will have on the Company. The Company does not believe, however, that it will be affected any differently than other gas producers or marketers with which it competes.
In 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. The proceeding did not result in a proposed rulemaking. In 1994, the FERC granted a number of interstate pipeline applications to abandon certificated gathering facilities to non-jurisdictional entities. Under those orders, the rates charged by these entities, which may or may not be affiliated with the interstate pipeline, are not regulated by the FERC. Under the individual orders, gathering services must be continued to existing customers under "default" contracts and be provided in an open-access and non-discriminatory manner. The District of Columbia Court of Appeals upheld the Commission's decision to not regulate gathering rates but found that the Commission's "default" contract requirement was unlawful as outside the Commission's jurisdiction. The court remanded the case to the Commission and the agency has not yet acted on remand. The U.S. Supreme Court declined to review the D.C. Circuit's decision.
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 ("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. Specifics as to the cost of these requirements, at certain facilities, are still being determined. As part of these requirements, the Company's refinery as well as some other Company facilities will be required to submit an application for a Clean Air Act Amendment Title V permit; dates of submittal of these applications vary upon the implementation of the State's Title V permit program. The Company believes it can comply with these new requirements, and in some cases already has done so, without adversely affecting operations.
The passage of the Federal Clean Air Act Amendments of 1990 prompted adoption of regulations by the State of Alaska obligating the Company to produce oxygenated gasoline for delivery to the Anchorage and Fairbanks, Alaska markets starting on November 1, 1992. Controversies surrounding the potential health effects in Arctic regions of oxygenated gasoline containing methyl tertiary butyl ether ("MTBE") prompted early discontinuance of the program in Fairbanks. 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. The State of Alaska mandated the use of oxygenated fuels containing ethanol in the Anchorage area from 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. On March 14, 1994, the EPA granted the State of Alaska a waiver from the requirements of the EPA's low sulphur diesel fuel program, permanently exempting Alaska's remote areas and providing a temporary exemption for areas served by the Federal Aid Highway System until October 1, 1996. On August 19, 1996, the EPA extended the temporary exemption until October 1, 1998. The Company estimates that substantial capital expenditures would be required to enable the Company to produce low-sulphur diesel fuel to meet these federal regulations. If the State is unable to obtain a permanent waiver from the federal regulations, the Company would discontinue sales of diesel fuel for on-highway use after October 1, 1998. The Company estimates that such sales accounted for less than 1% of its refined product sales in Alaska during 1996. While the Company is unable to predict the outcome of these matters, their ultimate resolution should not have a material impact on its operations.
Oil Spill Prevention and Response. The Federal Oil Pollution Act of 1990 ("OPA 90") and related state regulations require most refining, transportation and oil storage facilities to prepare oil spill prevention contingency plans for use during an oil spill response. The Company has prepared and submitted these plans for approval and, in most cases, has received federal and state approvals necessary to meet various regulations and to avoid the potential of negative impacts on the operation of its facilities.
The Company currently charters a tanker to transport crude oil from the Valdez, Alaska pipeline terminal through Prince William Sound and Cook Inlet to its refinery. In addition, the Company routinely charters, on a long-term and short-term basis, additional tankers and barges for shipment of crude oil and refined products through Cook Inlet, as well as other locations. OPA 90 requires, as a condition of operation, that the Company demonstrate the capability to respond to the "worst case discharge" to the maximum extent practicable. Alaska law requires the Company to provide spill-response capability to contain or control, and clean-up within 72 hours, an amount equal to 50,000 barrels for a tanker carrying fewer than 500,000 barrels of crude oil or equal to 300,000 barrels for a tanker carrying more than 500,000 barrels. To meet these requirements, the Company has entered into a contract with Alyeska Pipeline Service Company ("Alyeska") to provide initial spill response services in Prince William Sound, with the Company later to assume those responsibilities after mutual agreement with Alyeska and State and Federal On-Scene Coordinators. The Company has also entered into an agreement with Cook Inlet Spill Prevention and Response, Incorporated for oil spill response
services in Cook Inlet. The Company believes these contracts provide for the additional services necessary to meet spill response requirements established by Alaska and federal law.
Transportation, storage, and refining of crude oil in Alaska result in the greatest regulatory impact, with respect to oil spill prevention and response. Oil transportation and terminaling operations at other Company facilities also result in compliance mandates for oil spill prevention and response. The Company contracts with various oil spill response cooperatives or local contractors to provide necessary oil spill response capabilities which may be required on a location by location basis.
Regulations promulgated by the Alaska Department of Environmental Conservation ("ADEC") would have required the installation of dike liners in secondary containment systems for petroleum storage tanks by January 1997. Such installation would have required the Company to make capital improvements starting in 1996 of approximately $9.5 million. However, on December 18, 1996, ADEC approved the Company's alternative compliance schedule which allows the Company until the year 2002 to implement alternative secondary containment systems for the Company's existing petroleum storage tank facilities in the State of Alaska at a reduced cost of approximately $6 million.
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 is required to make expenditures for removal or upgrading of underground storage tanks at several of its current and former service station locations by December 22, 1998; the Company expects that such expenditures during 1997 will cost approximately $2 million.
Environmental Expenditures. The Company's capital expenditures for environmental control purposes totaled $.7 million during 1996. The Company anticipates that it will incur total capital expenditures for such purposes of approximately $6 million in 1997 and $3 million in 1998. The Company also expects to spend approximately $6 million by the year 2002 for secondary containment systems for existing storage tanks in Alaska. 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 Hydrocarbons Law and various other laws and regulations. The Hydrocarbons Law imposes certain requirements on the Company's ability to conduct its operations in Bolivia. In the Company's opinion, neither the Hydrocarbons Law nor other requirements currently imposed by Bolivian laws, regulations and practices will have a material adverse effect upon its Bolivian operations. In 1996, a new Hydrocarbons Law was passed by the Bolivian government that significantly impacts the Company's operation in Bolivia. For information on the Bolivian Hydrocarbons Law and Bolivian taxation, see "Exploration and Production -- Bolivia" discussed above.
EMPLOYEES
At December 31, 1996, the Company employed approximately 1,000 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 February 28, 1997.
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.
The business experience of the Company's executive officers for the past five years is described below. Positions, unless otherwise specified, are with the Company.
Bruce A. Smith -- Chairman of the Board of Directors, President and Chief Executive Officer since June 1996. President and Chief Executive Officer from September 1995 to June 1996. Executive Vice President, Chief Financial Officer and Chief Operating Officer from July 1995 through September 1995. Executive Vice President responsible for Exploration and Production Operations and Chief Financial Officer from September 1993 to July 1995. Vice President and Chief Financial Officer from September 1992 to September 1993. Vice President and Treasurer of Valero Energy Corporation from 1986 to 1992.
James C. Reed, Jr. -- Executive Vice President, General Counsel and Secretary since September 1995. Senior Vice President, General Counsel and Secretary from August 1994 to September 1995. Vice President, General Counsel and Secretary from September 1993 to August 1994. Vice President, Secretary from December 1992 to September 1993. Vice President, Secretary of Tesoro Petroleum Companies, Inc., from February 1992 to December 1992. Vice President, Assistant Secretary of Tesoro Petroleum Companies, Inc., from 1990 to 1992.
William T. Van Kleef -- Executive Vice President, Operations since September 1996. Senior Vice President and Chief Financial Officer from September 1995 to September 1996. Vice President, Treasurer from March 1993 to September 1995. Financial Consultant from January 1992 to February 1993.
Don E. Beere -- Vice President, Controller since April 1992. Vice President, Controller of Tesoro Petroleum Companies, Inc. from February 1992 to April 1992. Vice President, Internal Audit and Management Systems of Tesoro Petroleum Companies, Inc. from 1990 to 1992.
Thomas E. Reardon -- Vice President, Human Resources and Environmental since September 1995. Vice President, Human Resources and Environmental Services of Tesoro Petroleum Companies, Inc. from October 1994 to September 1995. Vice President, Human Resources of Tesoro Petroleum Companies, Inc. from February 1990 to October 1994.
Gregory A. Wright -- Vice President and Treasurer since September 1995. Vice President, Corporate Communications from February 1995 to September 1995. Vice President, Corporate Communications of Tesoro Petroleum Companies, Inc. from January 1995 to February 1995. Vice President, Business Develop-
ment of Valero Energy Corporation from 1994 to January 1995. Vice President, Corporate Planning of Valero Energy Corporation from 1992 to 1994. Vice President, Investor Relations of Valero Energy Corporation from 1989 to 1992.
ITEM 2.
ITEM 2. PROPERTIES
See information appearing under Item 1, Business herein and Notes B, C and O of Notes to Consolidated Financial Statements in Item 8.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
The Company, along with numerous other parties, has been identified by the Environmental Protection Agency ("EPA") as a potentially responsible party ("PRP") pursuant to the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA") for the Mud Superfund site in Abbeville, Louisiana ("Site"). The Company arranged for the disposal of a minimal amount of materials at the Site, but CERCLA might impose joint and several liability on each PRP at the Site. The EPA is seeking reimbursement for its response costs incurred to date at the Site, as well as a commitment from the PRPs either to conduct future remedial activities or to finance such activities. The extent of the Company's allocated financial contributions to the cleanup of the site is expected to be limited based upon the number of companies, volumes of waste involved, and an estimated total cost of approximately $500,000 among all of the parties to close the Site. The Company is currently involved in settlement discussions with the EPA and other PRP's involved at the Site. The Company expects, based on these discussions, that its liability at the Site will not exceed $25,000.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The principal markets on which the Company's Common Stock is traded are the New York Stock Exchange and the Pacific Stock Exchange. The per share market price ranges for the Company's Common Stock during 1996 and 1995 are summarized below:
At February 28, 1997, there were approximately 3,700 holders of record of the Company's 26,426,333 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
RESULTS OF OPERATIONS
SUMMARY
Net earnings of $74.5 million ($2.81 per share) in 1996 compare to $54.6 million ($2.18 per share) in 1995 and $15.7 million ($.56 per share) in 1994. Noncash extraordinary losses for early extinguishment of debt amounted to $2.3 million in 1996, $2.9 million in 1995 and $4.8 million in 1994. Earnings before extraordinary losses amounted to $76.8 million ($2.90 per share), $57.5 million ($2.29 per share) and $20.5 million ($.77 per share) in 1996, 1995 and 1994, respectively. Comparability between the results for these years was impacted by significant items which are highlighted in the table below (in millions except per share amounts):
As shown above, excluding the significant items, the Company's net earnings would have been $31.7 million ($1.20 per share) in 1996, as compared to $29.2 million ($1.16 per share) in 1995 and $16.7 million ($.61 per share) in 1994. The resulting increase in net earnings in 1996, compared to 1995, was primarily attributable to improvements within the Company's Refining and Marketing and Marine Services segments, each of which reported significant improvements from the prior year. Results from the Company's Exploration and Production segment increased, even when excluding the above items and removing the incremental value of an above-market pricing contract (see Note D of Notes to Consolidated Financial Statements in Item 8) from both 1996 and 1995. Additionally, at the corporate level, initiatives implemented in the fourth quarter of 1995 helped reduce general and administrative expenses and interest expense. These improvements were partially offset by an increase in the Company's total effective tax rate in 1996 as earnings subject to U.S. taxes exceeded available net operating loss and tax credit carryforwards. When comparing 1995 to 1994, the improvement in net earnings of approximately $12 million was primarily attributable to increased natural gas production from the Company's exploration and production operations in South Texas
and improvements in the Company's refining and marketing operations. In 1994, dividend requirements on preferred stock amounted to $2.7 million (see Note K of Notes to Consolidated Financial Statements in Item 8).
A discussion and analysis of the factors contributing to these results are presented below. The accompanying consolidated financial statements and related footnotes, together with the following information, are intended to provide shareholders and other investors with a reasonable basis for assessing the Company's operations, but should not serve as the sole criterion for predicting the future performance of the Company. The Company conducts its operations in the following business segments: Refining and Marketing, Exploration and Production, and Marine Services.
REFINING AND MARKETING
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(1) Refinery product spread represents the excess of yield value of the products manufactured at the refinery over the cost of raw materials used to manufacture such products.
(2) Sources of total product sales include products manufactured at the refinery, products drawn from inventory balances and products purchased from third parties. The Company's purchases of refined products for resale were approximately 11,600; 25,500; and 27,200 average daily barrels for 1996, 1995 and 1994, respectively.
(3) Margins on sales of purchased products, together with the effect of changes in inventories, are included in the gross margin on total product sales. Computations of average costs of sales per barrel in 1994 exclude the benefits of an $8.5 million tariff refund and $1.5 million favorable feedstock cost adjustments.
1996 Compared to 1995. Results from the Company's Refining and Marketing segment improved during 1996 with operating profit of $6.0 million, compared to operating profit of $.7 million in 1995. This improvement was achieved during a year when the industry was facing rapidly rising prices in the crude oil market. In addition, the Company's production level at the refinery was reduced in September 1996 for a scheduled 30-day maintenance downtime. Despite these factors, the Company was able to achieve a refinery product spread of $4.81 per barrel for 1996, compared to $3.47 per barrel in 1995. The Company's results were helped by its initiatives to control costs, improve its refinery product slate and expand the marketing program for its refined products. The Company's refined product yield values increased by 21% to $24.61 per barrel in 1996, from $20.35 per barrel in 1995, while the Company's feedstock costs increased by 17% to $19.80 per barrel in 1996 from $16.88 per barrel in 1995.
During 1996, the Company's production of refined products declined in total by 6%, which included the impact of the scheduled maintenance period. Of this decline, gasoline production decreased by 11% and middle distillates, consisting of jet fuel and diesel fuel, decreased by only 3%. These reductions reflected the change of a hydrocracker catalyst, during the maintenance period, which allows for increased production of jet fuel and reduced production of gasoline, beginning in the fourth quarter of 1996, which better matches the Company's product supply with demand in Alaska. To further improve the refinery's feedstock and product slate, the Company intends to modify the refinery hydrocracker during 1997, at an estimated cost of $17 million. In conjunction with the modification and other initiatives, a refinery downtime of approximately 30 days is anticipated during 1997.
The Company continued its marketing efforts during 1996, adding 31 locations in Alaska and 8 locations in the Pacific Northwest, bringing the total to 188 branded, unbranded and Company-owned retail outlets in Alaska and 18 branded stations in the Pacific Northwest. Two uneconomic outlets in these areas were closed in 1996. In addition, the Company began producing and marketing liquid asphalt, a heavy product remaining after the refining process, which is a seasonal product in Alaska. Export sales of refined products, including sales to the Russian Far East, amounted to $22.0 million in 1996 and $18.5 million in 1995.
Revenues from sales of refined products in the Company's Refining and Marketing segment decreased in 1996 due primarily to a 20% decline in sales volumes, partially offset by a 16% increase in average sales prices. Total refined product sales averaged 62,167 barrels per day in 1996 as compared to 77,301 barrels per day in 1995. This decline reflected the lower production volumes and the Company's withdrawal from certain West Coast markets during 1996, which also reduced the Company's purchases from other refiners and suppliers to 11,600 barrels per day in 1996 as compared to 25,500 barrels per day in 1995. The Company plans to sell its Company-owned facilities in California. One of these facilities was sold in 1996 resulting in a loss of
$.8 million; two facilities remain for sale at year-end 1996. The Company at times resells previously purchased crude oil, sales of which increased to $93.8 million in 1996, compared to $75.8 million in 1995, due primarily to higher crude oil prices and in part due to sales of excess crude supply volumes during the maintenance period. Costs of sales decreased in 1996 due to lower volumes of refined products, partially offset by higher prices for crude oil and refined products. Operating expenses were higher in 1996 due primarily to higher environmental and employee costs partially offset by lower insurance costs.
Although results from the Company's Refining and Marketing segment for 1996 improved over 1995 levels, future profitability of this segment will continue to be significantly influenced by market conditions, particularly as these conditions influence costs of crude oil relative to prices received for sales of refined products, and other additional factors that are beyond the control of the Company.
1995 Compared to 1994. The Refining and Marketing's segment operating profit of $.7 million in 1995 decreased $1.7 million from operating profit of $2.4 million in 1994. Results for 1994 benefited from an $8.5 million refund received in settlement of a tariff dispute, a gain of $2.4 million from the sale of assets and favorable feedstock cost adjustments of $1.5 million, partially offset by $6.6 million for environmental contingencies and other matters. Excluding these items from 1994, operating profit in 1995 reflected an improvement of $4.1 million from the 1994 operating results.
The Company's average feedstock costs increased by 8%, to $16.88 per barrel in 1995 from $15.65 per barrel in 1994, while the average yield value of the Company's refinery production increased by only 4%, to $20.35 per barrel in 1995 from $19.48 per barrel in 1994. Increased demand for Alaska North Slope ("ANS") crude oil for use as a feedstock in West Coast refineries and declining production volumes of ANS, combined with an oversupply of products in Alaska and on the West Coast, resulted in higher feedstock costs for the Company relative to increases in refined product sales prices. As a result, the Company's refined product margins were depressed in 1995.
The start-up in December 1994 of a vacuum unit at the Company's refinery increased the yield of higher-valued products during 1995 and lessened the impact of these industry conditions on the Company's refinery spread. The Company's refinery yield of residual products was reduced to 18% of total production in 1995 from 32% of total production in 1994. In addition, margins on sales of inventories and purchased volumes combined to improve the segment's gross margins on total product sales to $3.02 per barrel in 1995, compared to $2.92 per barrel in 1994.
The Company's total refinery production increased by 10%, including a 22% increase in gasoline volumes and a 12% increase in middle distillates volumes. Accordingly, in 1995, the Company implemented initiatives that increased the demand for the refinery's production and improved the refinery's capacity utilization and efficiencies. In these regards, the Company expanded its marketing efforts by branding and rebranding sales outlets in Alaska and the Pacific Northwest and by exporting refined products to the Far East, including Russia. Revenues from export sales totaled $18.5 million in 1995 compared to $5.2 million in 1994. The Company's total product sales increased to 77,301 average barrels per day in 1995 from 70,675 average barrels per day in 1994.
Revenues from sales of refined products in 1995 were higher than in 1994 due to higher sales prices and the increase in sales volumes. Resales of crude oil aggregated $75.8 million in 1995 and $72.3 million in 1994. Costs of sales were higher in 1995 due to higher volumes and prices. Operating expenses decreased by $3.5 million in 1995 primarily due to lower environmental costs, partly offset by increased employee costs and fuels and utilities expense. Depreciation and amortization increased by $1.5 million in 1995 due to capital additions, primarily the vacuum unit, completed in late 1994. Included in 1994 was a $2.4 million gain from the sale of assets.
EXPLORATION AND PRODUCTION
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(1) See Note D of Notes to Consolidated Financial Statements in Item 8
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, 1996 and 1995, and the related statements of consolidated operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 1996. 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, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
San Antonio, Texas January 23, 1997
TESORO PETROLEUM CORPORATION
STATEMENTS OF CONSOLIDATED OPERATIONS (IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
The accompanying notes are an integral part of these consolidated financial statements.
TESORO PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS (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)
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
Principles of Consolidation
The Consolidated Financial Statements include the accounts of Tesoro Petroleum Corporation and its subsidiaries (collectively, the "Company" or "Tesoro"). Tesoro is a natural resource company primarily engaged in petroleum refining and marketing, natural gas exploration and production, marketing and distributing of petroleum products and providing marine logistics services. All significant intercompany accounts and transactions have been eliminated.
Use of Estimates and Presentation
The preparation of the Company's Consolidated Financial Statements required the use of management's best estimates and judgment that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the year. Actual results could differ from those estimates.
Certain previously reported amounts have been reclassified to conform with the 1996 presentation.
Cash and Cash Equivalents
Cash equivalents consist of highly-liquid debt instruments such as commercial paper and certificates of deposit purchased with an original maturity date of three months or less. Cash equivalents are stated at cost, which approximates market value. The Company's policy is to invest cash in conservative, highly-rated instruments and to invest in various institutions to limit the amount of credit exposure in any one institution. The Company performs ongoing evaluations of the credit standing of these financial institutions.
Inventories
Inventories are stated at the lower of cost or market. The last-in, first-out ("LIFO") method was used to determine the cost of the Company's inventories of crude oil and U.S. wholesale refined products. The cost of remaining inventories was determined principally on the first-in, first-out ("FIFO") or weighted average basis. See Note F.
Property, Plant and Equipment
Additions to property, plant and equipment and major renewals and improvements are capitalized at cost. Maintenance and repairs are charged to operations when incurred. Depletion of oil and gas producing properties is determined principally by the unit-of-production method and is based on estimated recoverable reserves. Depreciation of other property, plant and equipment is generally computed on the straight-line method based upon the estimated useful lives of the assets, ranging from 3 years to 33 years for refining and marketing assets and 3 years to 25 years for other assets. Salvage values are estimated at 20% for refinery assets and 10% for other assets. Assets recorded under capital leases and leasehold improvements are amortized on the straight-line method over the shorter of the term of the lease or the useful life of the related asset.
Oil and gas properties are accounted for using the full-cost method of accounting. Under this method, all costs associated with property acquisition and exploration and development activities are capitalized into cost centers that are established on a country-by-country basis. For each cost center, the capitalized costs are subject to a limitation so as not to exceed the present value of future net revenues from estimated production of proved oil and gas reserves net of income tax effect plus the lower of cost or estimated fair value of unproved properties included in the cost center. Capitalized costs within a cost center, together with estimates of costs for future development, dismantlement and abandonment, are amortized on a unit-of-production method
TESORO PETROLEUM CORPORATION
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. Gain or loss is recognized only on the sale of oil and gas properties involving significant reserves. Proceeds from the sale of insignificant reserves and undeveloped properties are applied to reduce the costs in the cost centers.
Income Taxes
Deferred tax assets and liabilities are recognized for future income tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax bases. Measurement of deferred tax assets and liabilities is based on enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period that includes the enactment date.
Environmental Expenditures
Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that extend the life, increase the capacity, or mitigate or prevent environmental contamination, are capitalized. Expenditures that relate to an existing condition caused by past operations, and which do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or remedial efforts are probable and the cost can be reasonably estimated. Such amounts are based on the estimated timing and extent of remedial actions required by applicable governing agencies, experience gained from similar sites on which environmental assessments or remediation has been completed, and the amount of the Company's anticipated liability considering the proportional liability and financial abilities of other responsible parties. Estimated liabilities are not discounted to present value. Generally, the timing of these accruals coincides with completion of a feasibility study or the Company's commitment to a formal plan of action.
Financial Instruments
The carrying amount of financial instruments including cash and cash equivalents, accounts receivable, accounts payable and certain accrued liabilities approximates fair value because of the short maturity of these instruments. The carrying amount of the Company's long-term debt and other obligations approximated the Company's estimates of the fair value of such items.
Earnings Per Share
Earnings per share is based on the weighted average number of common shares outstanding during the year, including the dilutive effect of common stock equivalents, principally stock options. For 1994, the assumed conversion of preferred stocks to common shares was anti-dilutive.
Stock-Based Compensation
The Company accounts for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board ("APB") No. 25, "Accounting for Stock Issued to Employees," and related Interpretations. Accordingly, compensation cost for stock options is measured as the excess, if any, of the quoted market price of the Company's Common Stock at the date of grant over the amount an employee must pay to acquire the stock. The Company has adopted the disclosure requirements of Statement of Financial Accounting Standards ("SFAS") No. 123, "Accounting for Stock-Based Compensation," as included in Note K.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE B -- BUSINESS SEGMENTS
The Company's revenues are derived from three business segments: Refining and Marketing, Exploration and Production, and Marine Services.
Refining and Marketing operates a petroleum refinery at Kenai, Alaska, which manufactures gasoline, jet fuel, diesel fuel, heavy oils and residual products. These products, together with products purchased from third parties, are sold at wholesale through terminal facilities and other locations in Alaska and the Pacific Northwest. In addition, Refining and Marketing markets gasoline, other petroleum products and convenience store items at retail through a chain of 7-Eleven convenience stores in Alaska. Refining and Marketing also markets petroleum products through other branded and unbranded stations in Alaska and the Pacific Northwest. Revenues from export sales, primarily to Far East markets, amounted to $22.0 million, $18.5 million and $5.2 million in 1996, 1995 and 1994, respectively. The Company at times resells previously purchased crude oil, sales of which amounted to $93.8 million, $75.8 million and $72.3 million in 1996, 1995 and 1994, respectively.
The Exploration and Production segment is engaged in the exploration, development and production of natural gas and oil, primarily in the Wilcox Trend in South Texas and the Chaco Basin in Bolivia. In the U.S., the Company's focus has recently shifted outside of the maturing Bob West Field in South Texas to other areas. During 1996 and early 1997, the Exploration and Production segment purchased interests in the Frio/Vicksburg Trend adjacent to the Wilcox Trend in South Texas, the Cotton Valley Pinnacle Reef Play in East Texas and the Val Verde Basin in Southwest Texas (see Note C). This segment also includes the transportation of natural gas, including the Company's production, to common carrier pipelines in the South Texas area. In Bolivia, the Company operates through two contracts with the Bolivian government to explore for and produce hydrocarbons. The Company's Bolivian gas production is sold under contract to the Bolivian government for export to Argentina. The majority of the Company's Bolivian natural gas and oil reserves are shut-in awaiting access to gas-consuming markets. Major developments in South America indicate that new markets may open for the Company's production in the near future, particularly with the construction of a Bolivia-Brazil pipeline scheduled to start in late 1997, with first gas deliveries expected in 1999.
Marine Services markets and distributes petroleum products and provides logistics services, primarily to the marine and offshore exploration and production industries operating in the Gulf of Mexico. This segment currently operates 20 terminals along the Texas and Louisiana Gulf Coast. For information regarding an acquisition in this segment, see Note C. During 1995, the Company consolidated certain operations in this segment by exiting the land-based portion of its petroleum product distribution business, and in 1994 the Company discontinued an environmental remediation products and services operation formerly included in this segment.
Segment operating profit is gross operating revenues, gains and losses on asset sales and other income less applicable segment costs of sales, operating expenses, depreciation, depletion and other items. Income taxes, interest expense, interest income and corporate general and administrative expenses are not included in determining operating profit. In the Exploration and Production segment, operating profit in 1996 included $60 million of income from termination of a natural gas contract and $5 million for retroactive severance tax refunds, and 1995 included a gain of $33 million from the sale of certain interests in the Bob West Field. In 1996, 1995 and 1994, the Exploration and Production segment's operating profit included $24.6 million, $47.1 million and $38.9 million, respectively, from the excess of Tennessee Gas Contract prices over spot market prices (see Note D). 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.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Identifiable assets are those assets utilized by the segment. Corporate assets are principally cash, investments and other assets that cannot be directly associated with the operations of a business segment. Segment information for the years ended December 31, 1996, 1995 and 1994 is as follows (in millions):
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE C -- ACQUISITIONS AND DIVESTITURES
During 1996, the Company's Exploration and Production segment recorded acquisitions of proved and unproved properties totaling $25.7 million. The most significant of these was the purchase in December 1996 of interests in the Los Indios and La Reforma Fields, located in Hidalgo and Starr counties of South Texas, for $15 million. These two fields are in the Frio/Vicksburg Trend, which lies immediately adjacent to the Wilcox Trend. Other acquisitions in 1996 included the purchase of interests in the Berry R. Cox and the West Goliad Fields, both located in the Wilcox Trend, for $5.4 million and the purchase of approximately 35,000 net undeveloped acres in four areas of Texas for $5.3 million.
In September 1995, the Company sold, effective April 1, 1995, certain interests in its producing and non-producing oil and gas properties located in the Bob West Field in South Texas. The interests sold included the Company's approximate 55% net revenue interest and 70% working interest in Units C, D and E and a convertible override in Unit F of the Bob West Field. Excluded from the sale were the Company's interests in the State Park and Sanchez-O'Brien leases and the Ramirez USA E-6 well within the Bob West Field. In total, the sale included interests in 14 gross producing wells amounting to 77 Bcf, or 40%, of the Company's total net proved domestic reserves at the time of the sale (see Note O). For 1995, natural gas production from the interests sold had contributed approximately $11.7 million to revenues and $4 million to operating profit in the Company's Exploration and Production segment. Consideration for the sale was $74 million, which was adjusted for production, capital expenditures and certain other items after the effective date to approximately $68 million in cash received at closing, resulting in a gain of approximately $33 million in the 1995 third quarter. The consideration received by the Company was used to redeem $34.6 million of the Company's outstanding 12 3/4% Subordinated Debentures in 1995, reduce borrowings under the Company's revolving credit facility and improve corporate liquidity (see Note I).
In February 1996, the Company purchased 100% of the capital stock of Coastwide Energy Services, Inc. ("Coastwide"). The consideration included approximately 1.4 million shares of Tesoro's Common Stock and $7.7 million in cash. The market price of Tesoro's Common Stock was $9.00 per share at closing of this transaction. In addition, Tesoro repaid approximately $4.5 million of Coastwide's outstanding debt. Coastwide
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
was primarily a provider of logistical support services and a distributor of diesel fuel and lubricants to the offshore oil and gas industry in the Gulf of Mexico. The Company combined the Coastwide operation with its marine petroleum distribution operations, forming a Marine Services segment. The acquisition was accounted for as a purchase whereby the purchase price was allocated to the assets acquired and liabilities assumed based upon their estimated fair values.
In March 1995, the Company acquired all of the outstanding stock of Kenai Pipe Line Company ("KPL") for approximately $3 million cash. The Company's Refining and Marketing segment transports crude oil and a substantial portion of refined products utilizing KPL's pipeline and marine terminal facilities in Kenai, Alaska. The acquisition was accounted for using the purchase method.
NOTE D -- GAS PURCHASE AND SALES CONTRACT
Resolution of Litigation in 1996 Third Quarter
On August 16, 1996, the Supreme Court of Texas issued a mandate that denied a motion for rehearing by Tennessee Gas Pipeline Company ("Tennessee Gas") and upheld all aspects of a Gas Purchase and Sales Agreement ("Tennessee Gas Contract") which had been the subject of litigation since 1990. As provided for in the Tennessee Gas Contract, the Company was selling a portion of the gas produced from the Bob West Field to Tennessee Gas at a maximum price as calculated in accordance with Section 102(b)(2) ("Contract Price") of the Natural Gas Policy Act of 1978 ("NGPA"). Subsequent to the mandate, the Company received cash of $67.7 million from Tennessee Gas, which included collection of a $59.6 million bonded receivable for underpayment for natural gas sold in prior periods. The remaining $8.1 million received was for interest and reimbursement of legal fees and court costs, which had not previously been recorded by the Company and resulted in income during the 1996 third quarter. Tennessee Gas resumed paying the Contract Price to the Company for gas taken beginning with May 1996 volumes up until termination of the Tennessee Gas Contract discussed below.
Settlement and Termination of Contract in 1996 Fourth Quarter
On December 24, 1996, the Company settled all other claims and disputes with Tennessee Gas, including litigation in Zapata County, Texas filed by Tennessee Gas, and agreed to terminate the Tennessee Gas Contract effective October 1, 1996. The Tennessee Gas Contract would have extended through January 1999. Under the settlement, the Company received $51.8 million and the right to recover severance taxes paid by Tennessee Gas of approximately $8.2 million, which resulted in income of $60 million to the Company during the 1996 fourth quarter.
NOTE E -- RECEIVABLES
Concentrations of credit risk with respect to accounts receivable are limited, due to the large number of customers comprising the Company's customer base and their dispersion across the Company's industry segments and geographic areas of operations. The Company performs ongoing credit evaluations of its customers' financial condition and in certain circumstances requires letters of credit or other collateral arrangements. The Company's allowance for doubtful accounts is reflected as a reduction of receivables in the
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Consolidated Balance Sheets. The following table reconciles the change in the Company's allowance for doubtful accounts for the years ended December 31, 1996, 1995 and 1994 (in thousands):
NOTE F -- INVENTORIES
Components of inventories at December 31, 1996 and 1995 were as follows (in thousands):
At December 31, 1996 and 1995, inventories valued using LIFO were lower than replacement cost by approximately $17.7 million and $3.8 million, respectively.
NOTE G -- ACCRUED LIABILITIES
The Company's current accrued liabilities and noncurrent other liabilities as shown in the Consolidated Balance Sheets at December 31, 1996 and 1995 included the following (in thousands):
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE H -- INCOME TAXES
The income tax provision for the years ended December 31, 1996, 1995 and 1994 included the following (in thousands):
Deferred income taxes and benefits are provided for differences between financial statement carrying amounts of assets and liabilities and their respective tax bases. Temporary differences and the resulting deferred tax assets and liabilities at December 31, 1996 and 1995 are summarized as follows (in thousands):
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following tables set forth the components of the Company's results of operations (in thousands) and a reconciliation of the normal statutory federal income tax rate with the Company's effective tax rate:
At December 31, 1996, the Company had approximately $8.2 million of investment tax credits and employee stock ownership credits available for carryover to subsequent years, which, if not used, will expire in the years 1997 through 2006. Additionally, at December 31, 1996, the Company had approximately $3.8 million of alternative minimum tax credit carryforwards, with no expiration dates, to offset future regular tax liabilities.
NOTE I -- LONG-TERM DEBT AND OTHER OBLIGATIONS
Long-term debt and other obligations at December 31, 1996 and 1995 consisted of the following (in thousands):
Aggregate maturities of long-term debt and obligations for each of the five years following December 31, 1996 are as follows: 1997 - $10.0 million; 1998 - $9.7 million; 1999 - $9.6 million; 2000 - $10.7 million; and 2001 - $11.3 million.
Revolving Credit Lines
In June 1996, the Company amended and restated its corporate revolving credit agreement ("Credit Facility"), expiring in April 2000, which provides total commitments of $150 million from a consortium of nine banks. The Company, at its option, has currently activated $100 million of these commitments. The
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Credit Facility provides for cash borrowings up to $100 million and issuance of letters of credit up to a borrowing base (which was approximately $141 million at December 31, 1996). Outstanding obligations under the 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, 1996, the Company had outstanding letters of credit of $33 million with no cash borrowings outstanding.
Cash borrowings under the Credit Facility bear interest at the prime rate plus .50% per annum or the London Interbank Offered Rate ("LIBOR") plus 1.5% per annum. Fees on outstanding letters of credit under the Credit Facility are 1.5% per annum. Under the terms of the Credit Facility, the Company is required to maintain specified levels of consolidated working capital, tangible net worth, cash flow and interest coverage. Among other matters, the Credit Facility contains covenants which limit the incurrence of additional indebtedness and restricted payments. Under the Credit Facility, dividends up to $5 million per year are allowed, subject to the restricted payment limit.
During 1996 and 1995, the Company's gross borrowings and repayments under its corporate revolving credit line totaled $166 million and $262 million, respectively, which were used on a short-term basis to finance working capital requirements and capital expenditures.
In November 1996, a subsidiary of the Company entered into a loan facility with a bank which provides a three-year line of credit up to $10 million to the Marine Services segment for the purchase of real estate and equipment at the bank's prime rate. The loan facility, which is subject to a borrowing base, is not guaranteed by the Company and is secured only by such real estate and equipment that are financed. Beginning in March 1998, credit availability is reduced quarterly by 6.667%. At December 31, 1996, $.9 million was outstanding under the loan facility.
Vacuum Unit Loan
In 1994, the National Bank of Alaska and the Alaska Industrial Development & Export Authority provided a $15 million loan to the Company towards the cost of the Company's refinery vacuum unit ("Vacuum Unit Loan"). The Vacuum Unit Loan matures January 1, 2002, requires equal quarterly payments of approximately $536,000 and bears interest at the unsecured 90-day commercial paper rate, adjusted quarterly, plus 2.6% per annum (8.23% at December 31, 1996) for two-thirds of the amount borrowed and at the National Bank of Alaska floating prime rate plus one-fourth of 1% per annum (8.5% at December 31, 1996) for the remainder. The Vacuum Unit Loan is secured by a first lien on the Company's refinery. Under the terms of the Vacuum Unit Loan, the Company is required to maintain specified levels of working capital, tangible net worth and cash flow, as defined. For 1996, the Company satisfied all of its covenants except for working capital and refinery cash flow requirements, which were waived by the lenders.
12 3/4% Subordinated Debentures and 13% Exchange Notes
In November 1996, the Company fully redeemed its two public debt issues, totaling approximately $74 million, at a price equal to 100% of the principal amount, plus accrued interest to the redemption date. The redemption of debt was comprised of $44.1 million of outstanding 13% Exchange Notes ("Exchange Notes"), due December 1, 2000, and $30 million of outstanding 12 3/4% Subordinated Debentures ("Subordinated Debentures"), due March 15, 2001. The redemption was accounted for as an early extinguishment of debt in the 1996 third quarter, resulting in a pretax charge of $3.2 million ($2.3 million aftertax) which represented a write-off of unamortized bond discount and issue costs. The extraordinary losses on debt extinguishments of $2.9 million and $4.8 million in 1995 and 1994, respectively, related to the redemption of $34.6 million principal amount of Subordinated Debentures in December 1995 and the exchange of $44.1 million principal amount of Subordinated Debentures for Exchange Notes in February 1994 (see Note K).
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
State of Alaska
In 1993, the Company entered into an agreement ("Agreement") with the State of Alaska ("State") that settled a contractual dispute with the State. Under the Agreement, the Company is obligated to make variable monthly payments to the State through December 2001 based on a per barrel charge on the volume of feedstock processed at the Company's refinery. In 1995 and 1994, based on a per barrel throughput charge of 16 cents, the Company's variable payments to the State totaled $2.9 million and $2.8 million, respectively. The per barrel charge increased to 24 cents in 1996 with the Company's variable payment to the State totaling $4.0 million in the year. The per barrel charge of 24 cents in 1997 increases to 30 cents in 1998 with one cent annual incremental increases thereafter through 2001. In January 2002, the Company is obligated to pay the State $60 million; provided, however, that such payment may be deferred indefinitely by continuing the variable monthly payments to the State beginning at 34 cents per barrel for 2002 and increasing one cent per barrel annually thereafter. Variable monthly payments made after January 2002 will not reduce the $60 million obligation to the State. The imputed rate of interest used by the Company on the $60 million obligation was 13%. The $60 million obligation is evidenced by a security bond, and the bond and the throughput barrel obligations are secured by a mortgage on the Company's refinery. The Company's obligations under the Agreement and the mortgage are subordinated to current and future senior debt of up to $175 million plus any indebtedness incurred subsequent to the date of the Agreement to improve the Company's refinery.
Department of Energy
A Consent Order entered into by the Company with the Department of Energy ("DOE") in 1989 settled all issues relating to the Company's compliance with federal petroleum price and allocation regulations from 1973 through decontrol in 1981. At December 31, 1996, the Company's remaining obligation is to pay the DOE $10.6 million, exclusive of interest at 6%, over the next six 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 (6.1875% at December 31, 1996), 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 $5.6 million at December 31, 1996.
NOTE J -- BENEFIT PLANS
Retirement Plan
For all eligible employees, the Company provides a qualified noncontributory retirement plan. Plan benefits are based on years of service and compensation. The Company's funding policy is to make contributions at a minimum in accordance with the requirements of applicable laws and regulations, but no more than the amount deductible for income tax purposes. The components of net pension expense for the Company's retirement plan for the years ended December 31, 1996, 1995 and 1994 are presented below (in thousands):
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The funded status of the Company's retirement plan and amounts included in the Company's Consolidated Balance Sheets at December 31, 1996 and 1995 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, 1996, 1995 and 1994 included a discount rate of 7 1/2%, 7 1/2% and 8 1/2%, respectively, and a compensation increase rate of 5%, 5% and 6%, respectively. The expected long-term rate of return on assets was 8 1/2%, 8 1/2% and 9% for 1996, 1995 and 1994, respectively.
Executive Security Plan
The Company's executive security plan ("ESP") provides executive officers and other key personnel with supplemental death or retirement benefits in addition to those benefits available under the Company's group life insurance and retirement plans. These supplemental retirement benefits are provided by a nonqualified, noncontributory plan and are based on years of service and compensation. Contributions are made based upon the estimated requirements of the plan. The components of net pension expense for the ESP for the years ended December 31, 1996, 1995 and 1994 are presented below (in thousands):
During 1996, 1995 and 1994, the Company incurred additional ESP expense of $.9 million, $1.5 million and $.4 million, respectively, for settlements, curtailments and other benefits resulting from employee terminations.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The funded status of the ESP and amounts included in the Company's Consolidated Balance Sheets at December 31, 1996 and 1995 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, 1996, 1995 and 1994 included a discount rate of 7 1/2%, 7 1/2% and 8 1/2%, respectively, and a compensation increase rate of 5%. The expected long-term rate of return on assets was 8%, 8% and 9% for 1996, 1995 and 1994, respectively.
Retiree Health Care and Life Insurance Benefits
The Company provides health care and life insurance benefits to retirees who were participating in the Company's group insurance program at retirement. Health care is also provided to qualified dependents of participating retirees. These benefits are provided through unfunded, defined benefit plans. The health care plans are contributory, with retiree contributions adjusted periodically, and contain other cost-sharing features such as deductibles and coinsurance. The life insurance plan is noncontributory. The Company funds its share of the cost of postretirement health care and life insurance benefits on a pay-as-you-go basis. The components of net periodic postretirement benefits expense, other than pensions, for the years ended December 31, 1996, 1995 and 1994 included the following (in thousands):
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following tables show the status of the plans reconciled with the amounts in the Company's Consolidated Balance Sheets at December 31, 1996 and 1995 (in thousands):
The weighted average annual rate of increase in the per capita cost of covered health care benefits is assumed to be 8% for 1997, decreasing gradually to 6% by the year 2005 and remaining at that level thereafter. This health care cost trend rate assumption has a significant effect on the amount of the obligation and periodic cost reported. For example, an increase in the assumed health care cost trend rates by one percentage point in each year would increase the accumulated postretirement obligation at December 31, 1996 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 $.5 million. Actuarial assumptions used to measure the accumulated postretirement benefit obligation at December 31, 1996, 1995 and 1994 included a discount rate of 7 1/2%, 7 1/2% and 8 1/2%, respectively, and a compensation rate increase of 5%, 5% and 6%, respectively.
Thrift Plan
The Company sponsors an employee thrift plan which provides for contributions by eligible employees into designated investment funds with a matching contribution by the Company. Employees may contribute up to 10% of their compensation, subject to certain limitations, and may elect tax deferred treatment in accordance with the provisions of Section 401(k) of the Internal Revenue Code. Effective October 1, 1996, the thrift plan was amended to change the Company's matching contribution from 50% (of up to 6% of the employee's eligible contribution) to 100% (of up to 4% of the employee's eligible contributions), with 50% of the Company's match invested in Common Stock of the Company. The Company's contributions amounted to $754,000, $400,000 and $547,000 during 1996, 1995 and 1994, respectively.
Employee Terminations and Other Costs
In 1996 and 1995, the Company incurred charges of $2.9 million and $5.2 million, respectively, primarily for employee termination costs and other restructuring costs. Other expense in 1996 and 1995 included $2.0 million and $3.8 million of these charges, representing primarily severance and related benefits resulting from a reduction in administrative workforce and other employee terminations together with settlements and curtailments under the Company's executive security plan. Operating expenses and other included the remaining amounts of these charges which were related to employee terminations and exit costs in the Company's operating segments. At December 31, 1995, the Company's Consolidated Balance Sheet included
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
an accrual of approximately $.9 million relating to the costs incurred in 1995, all of which were subsequently paid in 1996. Costs incurred in 1996 were paid and settled during the year.
Non-Employee Director Retirement Plan
The Company has an unfunded Non-Employee Director Retirement Plan ("Director Retirement Plan") which provides that any eligible non-employee director who elects to participate in the Director Retirement Plan and who has served on the Company's Board of Directors for at least three full years will be entitled to a retirement payment beginning the later of the director's sixty-fifth birthday or such later date that the individual's service as a director ends. In 1995, the Company recognized expense of $.8 million related to the Director Retirement Plan, substantially all attributable to nonrecurring prior service costs. At December 31, 1996 and 1995, the Director Retirement Plan's projected benefit obligation and present value of the vested and accumulated benefit obligation discounted at 7 1/2% were estimated to be $.8 million. The Company's Consolidated Balance Sheet at December 31, 1996 and 1995 included $.7 million in other liabilities related to the Director Retirement Plan. The Compensation Committee of the Board of Directors is considering the termination of the Director Retirement Plan and the conversion of the lump-sum present value of each director's benefit into an unfunded deferred phantom stock plan.
NOTE K -- STOCKHOLDERS' EQUITY
Stock Plans and Incentive Compensation Strategy
The Company has two employee incentive stock plans, the Executive Long-Term Incentive Plan ("1993 Plan") and Amended Incentive Stock Plan of 1982 ("1982 Plan"), and the 1995 Non-Employee Director Stock Option Plan ("1995 Plan") (collectively, the "Plans"). Shares of unissued Common Stock reserved for the Plans totaled 2,775,191 at December 31, 1996.
The 1993 Plan provides for the grant of up to 2,650,000 shares of the Company's Common Stock in a variety of forms, including restricted stock, incentive stock options, nonqualified stock options, stock appreciation rights and performance share and performance unit awards. Stock options may be granted at exercise prices equal to the market value on the date the options are granted. The options granted generally become exercisable after one year in 20% or 33% increments per year and expire ten years from date of grant. The 1993 Plan will expire, unless earlier terminated, as to the issuance of awards in the year 2003. At December 31, 1996, the Company had 461,807 shares available for future grants under the 1993 Plan. The 1982 Plan expired in 1994 as to issuance of stock appreciation rights, stock options and stock awards; however, grants made before the expiration date that have not been fully exercised remain outstanding pursuant to their terms.
The 1995 Plan provides for the grant of up to an aggregate of 150,000 nonqualified stock options to eligible non-employee directors of the Company. The option price per share is equal to the fair market value per share of the Company's Common Stock on the date of grant. The term of each option is ten years, and an option first becomes exercisable six months after the date of grant. Under the 1995 Plan, each person serving as a non-employee director on February 23, 1995 or appointed thereafter, received an option to purchase 5,000 shares of Common Stock. In addition, each non-employee director, while the 1995 Plan is in effect and shares are available to grant, will be granted an option to purchase 1,000 shares of Common Stock on the next day after each annual meeting of the Company's stockholders but not later than June 1. At December 31, 1996, the Company had 67,000 options outstanding and 83,000 shares available for future grants under the 1995 Plan.
In June 1996, the Company's Board of Directors unanimously approved an incentive compensation strategy in order to encourage a longer-term focus for all employees to perform at an outstanding level. The strategy provides eligible employees with incentives to achieve a significant increase in the market price of the
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Company's Common Stock. Under the strategy, awards would be earned only if the market price of the Company's Common Stock reaches an average price per share of $20 or higher over any 20 consecutive trading days after June 30, 1997 and before December 31, 1998 (the "Performance Target"). In connection with this strategy, non-executive employees will be able to earn cash bonuses equal to 25% of their individual payroll amounts for the previous twelve complete months and certain executives have been granted, from the 1993 Plan, a total of 340,000 stock options at an exercise price of $11.375 per share, the fair market value (as defined in the 1993 Plan) of a share of the Company's Common Stock on the date of grant, and 350,000 shares of restricted Common Stock, all of which vest only upon achieving the Performance Target.
A summary of stock option activity in the Plans is set forth below:
Options exercisable amounted to 380,230; 360,779; and 478,879 at December 31, 1996, 1995 and 1994, respectively.
The following table summarizes information about stock options outstanding under the Plans at December 31, 1996:
Performance shares granted to officers and key employees under the 1993 Plan amounted to 137,253 common shares in 1994. 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 $1.3 million in 1994. No performance shares were granted in 1996 and 1995.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company applies APB No. 25 and related Interpretations in accounting for its stock plans. Accordingly, no compensation expense has been recognized for stock option transactions or the incentive compensation strategy discussed above. Had compensation cost for the Plans been determined based on the fair value at the grant dates for awards (granted after January 1, 1995) in accordance with SFAS No. 123, "Accounting for Stock-Based Compensation," the Company's net earnings in 1996 would have been reduced from $74.5 million ($2.81 per share) to pro forma net earnings of approximately $72.6 million ($2.74 per share). Net earnings in 1995 of $54.6 million ($2.18 per share) would have been reduced to pro forma net earnings of approximately $53.8 million ($2.15 per share). The fair value of each option grant was estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions used for grants in 1996 and 1995, respectively: no dividend yield; expected volatility of 45% and 30%; risk free interest rates of 7% for both periods; and expected lives of 7 years for both periods. The estimated fair values of options granted during 1996 and 1995 were $4.26 per share and $3.65 per share, respectively, and the fair value of restricted stock awards in 1996 was $.95 per share.
1994 Recapitalization and Equity Offering
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 were as follows:
(i) The Company exchanged $44.1 million principal amount of Subordinated Debentures for a like principal amount of Exchange Notes, both of which were fully redeemed in 1996 (see Note I).
(ii) The 1.3 million 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 of $9.5 million, were reclassified into 6.6 million shares of Common Stock.
(iii) The Company and the holder ("Holder") of all of the Company's $2.20 Cumulative Convertible Preferred Stock ("$2.20 Preferred Stock") entered into an agreement pursuant to which the Holder 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 million) to be paid and to grant to the Company an option to purchase all of the Holder's $2.20 Preferred Stock and Common Stock for approximately $53 million, all in consideration for, among other things, the issuance by the Company of 1.9 million shares of Common Stock.
In June 1994, the Company completed a public offering of 5.9 million shares of its Common Stock, receiving net proceeds of $57 million. These proceeds were used by the Company in part to pay the Holder $53 million, reacquiring 2.9 million shares of $2.20 Preferred Stock and 4.1 million shares of Common Stock.
In total, the transactions related to the Recapitalization and equity offering in 1994 resulted in the reclassification of the $2.16 Preferred Stock, the retirement of the $2.20 Preferred Stock and net increases in Common Stock of $1.7 million (10.3 million shares) and additional paid-in capital of $88.5 million.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE L -- COMMITMENTS AND CONTINGENCIES
Operating Leases
The Company has various noncancellable operating leases related to convenience stores, equipment, property and other facilities. Lease terms range from one year to 35 years and generally contain multiple renewal options. Future minimum annual payments for operating leases existing at December 31, 1996, excluding marine charters, were as follows (in thousands):
In addition to the long-term lease commitments above, the Company has leases for two vessels that are used to transport crude oil and refined products to and from the Company's refinery. At December 31, 1996, future minimum annual lease payments remaining for these two vessels, which include operating costs, are approximately $28 million for each of the years 1997 through 1999 and $16 million for the year 2000. Operating costs related to these vessels, which may vary from year to year, comprised approximately 30% of the total minimum payments in 1996. The Company also enters into various month-to-month and other short-term rentals, including a six-month charter of a vessel used to primarily transport refined products from the Company's refinery to the Far East.
Total rental expense, including short-term leases in addition to rents paid and accrued under long-term lease commitments, amounted to approximately $42 million, $36 million and $34 million for 1996, 1995 and 1994, respectively. Rental expense included amounts related to the lease of chartered vessels totaling approximately $30 million, $26 million and $25 million for 1996, 1995 and 1994, respectively.
Environmental
The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, which change frequently, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites or install additional controls or other modifications or changes in use for certain emission sources. The Company is currently involved with a waste disposal site near Abbeville, Louisiana, at which it has been named a potentially responsible party under the Federal Superfund law. Although this law might impose joint and several liability upon each party at the site, the extent of the Company's allocated financial contributions to the cleanup of the site is expected to be limited based upon the number of companies, volumes of waste involved, and an estimated total cost of approximately $500,000 among all of the parties to close the site. The Company is currently involved in settlement discussions with the Environmental Protection Agency ("EPA") and other potentially responsible parties at the Abbeville, Louisiana site. The Company expects, based on these discussions, that its liability will not exceed $25,000. The Company is also involved in remedial responses and has incurred cleanup expenditures associated with environmental matters at a number of sites, including certain of its own properties.
At December 31, 1996, the Company's accruals for environmental expenses amounted to $8.9 million, which included a noncurrent liability of $3.5 million for remediation of the KPL properties that has been funded by the former owners through a restricted escrow deposit. Based on currently available information, including the participation of other parties or former owners in remediation actions, the Company believes
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
these accruals are adequate. In addition, to comply with environmental laws and regulations, the Company anticipates that it will make capital improvements of approximately $6 million in 1997 and $3 million in 1998. The Company also expects to spend approximately $6 million by the year 2002 for secondary containment systems for existing storage tanks in Alaska.
Conditions that require additional expenditures may exist for various Company sites, including, but not limited to, the Company's refinery, retail gasoline outlets (current and closed locations) and petroleum product terminals, and for compliance with the Clean Air Act. The amount of such future expenditures cannot currently be determined by the Company.
Crude Oil Purchase Contract
The Company has a three-year contract with the State of Alaska for the purchase of royalty crude oil covering the period January 1, 1996 through December 31, 1998. The contract provides for the purchase of approximately 40,000 barrels per day of Alaska North Slope ("ANS") royalty crude oil, the primary feedstock for the Company's refinery, and is priced based on royalty values computed by the State. Under this agreement, the Company is required to utilize in its refinery operations volumes equal to at least 80% of the ANS crude oil to be purchased from the State. This contract contains provisions that, under certain conditions, allow the Company to temporarily or permanently reduce its purchase obligations.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE M -- QUARTERLY FINANCIAL DATA (UNAUDITED)
The 1996 first quarter included pretax income of $5 million related to a retroactive severance tax refund. The 1996 third quarter included pretax income of $8 million for interest and reimbursement of costs from Tennessee Gas (see Note D) and an aftertax extraordinary loss of $2.3 million for the early extinguishment of debt (see Note I). The contract with Tennessee Gas was terminated during the 1996 fourth quarter resulting in pretax income of $60 million (see Note D).
The 1995 third quarter included a gain of approximately $33 million from the sale of certain interests in the Bob West Field (see Note C), partially offset by approximately $5 million for employee terminations and other restructuring costs (see Note J). An extraordinary loss of $2.9 million was recognized in the 1995 fourth quarter for the early extinguishment of debt (see Note I).
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE N -- NATURAL GAS PRICE AGREEMENTS
The Company enters into commodity price agreements to reduce the risk caused by fluctuations in the prices of natural gas in the spot market. During 1996, 1995 and 1994, the Company used such agreements to set the price of 30%, 38% and 11%, respectively, of the natural gas production that it sold in the spot market. It is the Company's policy to use such agreements to set the price of not more than 50% of the annual volumes of natural gas production that are sold in the spot market. The agreements provide for the Company to receive, or make, payments based upon the differential between a specified fixed price and the market price for natural gas. The market price is determined by reference to a published index for natural gas traded at the Houston Ship Channel. The Houston Ship Channel index is the price upon which the cash prices for substantially all of the Company's spot market gas sales are based and, accordingly, the risk of losses from large fluctuations in the basis differentials (normally approximating the cost of transporting gas between the Henry Hub and the Houston Ship Channel) is substantially eliminated. The Company includes the related gains or losses in gas revenues in the period in which the gas is produced, which amounted to a loss of $3.1 million ($.11 per Mcf) in 1996 and to gains of $.3 million ($.01 per Mcf) in 1995 and 1994.
As of January 9, 1997, the Company had entered into price agreements for 1997 production totaling .9 Bcf of gas for an average Houston Ship Channel price of $2.18 per Mcf. In addition, the Company has entered into price agreements with collars, under which no payment will be made by either party unless the price falls below a designated floor price or above a designated ceiling price, at which time the Company receives or pays the difference, respectively. The Company has entered into price agreements with collars for 1997 production totaling 1.8 Bcf of gas with an average floor Houston Ship Channel price of $1.93 per Mcf and an average ceiling Houston Ship Channel price of $2.42 per Mcf. In 1996, the Company's average spot market wellhead price per Mcf for gas sales was $.23 less than the average Houston Ship Channel index, the difference representing transportation and marketing costs from the wellhead in South Texas.
NOTE O -- 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. Other information pertinent to the Exploration and Production segment is contained in Notes B, C, D and N.
In 1996, a new Hydrocarbons Law was passed by the Bolivian government that significantly impacts the Company's operations in Bolivia. The new law, among other matters, granted the Company the option to convert its Contracts of Operation to new Shared Risk Contracts. During 1996, the Company signed agreements to convert its Contracts of Operation to Shared Risk Contracts subject to recision at the option of the Company if the Company is not satisfied with modifications to the Bolivian fiscal law. The Company expects to complete this conversion during the first half of 1997. The new contracts extend the Company's term of operation, provide more favorable acreage relinquishment terms and provide for a more favorable fiscal regime of royalties and taxes. The new contracts will extend the term of the Company's operations for Block 18 ten additional years to the year 2017. For Block 20, the new contract extends the Company's term 21 additional years to the year 2029 for acreage that is in the exploration phase of the contract, and ten additional years to the year 2018 for an area within Block 20 that is designated as being in the development phase of the new contract. The new contract provisions, along with a substantial discovery during 1996, significantly increased the Company's reserves.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Capitalized Costs Relating to Oil and Gas Producing Activities
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(1) The Company anticipates that the majority of the costs at December 31, 1996, incurred primarily in 1996, will be included in the amortization base during 1997.
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
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.
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(1) See Note D.
(2) Represents retroactive severance tax refunds resulting from exemptions on substantially all of the Company's reserves in the Bob West Field.
(3) Excludes corporate general and administrative expenses and financing costs.
(4) Represents gain on sale of certain interests in the Bob West Field (see Note C).
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 SFAS No. 69. The standardized measure is the estimated excess future cash inflows from proved reserves less estimated future production and development costs, estimated future income taxes and a discount factor. Future cash inflows represent expected revenues from production of year-end quantities of proved reserves based on year-end prices and any fixed and determinable future escalation provided by contractual arrangements in existence at year-end. Escalation based on inflation, federal regulatory changes and supply and demand are not considered. Estimated future production costs related to year-end reserves are based on year-end costs. Such costs include, but are not limited to, production taxes and direct operating costs. Inflation and other anticipatory costs are not considered until the actual cost change takes effect. Estimated future income tax expenses are computed using the appropriate year-end statutory tax rates. Consideration is given for the effects of permanent differences, tax credits and allowances. A discount rate of 10% is applied to the annual future net cash flows.
The methodology and assumptions used in calculating the standardized measure are those required by SFAS No. 69. The standardized measure is not intended to be representative of the fair market value of the Company's proved reserves. The calculations of revenues and costs do not necessarily represent the amounts to be received or expended by the Company.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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(1) For Bolivia, the discounted future income tax expense as of December 31, 1996 consisted of $69,363 Bolivian taxes and $10,739 U.S. taxes.
(2) Gross production rates were increased from 45 MMcf per day to 90 MMcf per day in the year 2000 due to the anticipated completion of the Bolivia-Brazil pipeline discussed in Note B. This increase accounts for approximately $19 million of the standardized measure of discounted future net cash flows for Bolivia at December 31, 1996.
Changes in Standardized Measure of Discounted Future Net Cash Flows (Unaudited)
Reserve Information (Unaudited)
The following estimates of the Company's net proved oil and gas reserves are based on evaluations prepared by Netherland, Sewell & Associates, Inc. Reserves were estimated in accordance with guidelines established by the Securities and Exchange Commission and Financial Accounting Standards Board, which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations except by contractual arrangements.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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(1) The Company was not required to file reserve estimates with federal authorities or agencies during the periods presented.
(2) No major discovery or adverse event has occurred since December 31, 1996 that would cause a significant change in net proved reserve volumes.
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 1997 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 1997 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 1997 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 1997 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
Copies of exhibits filed as part of this Form 10-K may be obtained by stockholders of record at a charge of $.15 per page, minimum $5.00 each request. Direct inquiries to the Corporate Secretary, Tesoro Petroleum Corporation, 8700 Tesoro Drive, San Antonio, Texas, 78217-6218.
(B) REPORTS ON FORM 8-K
No reports on Form 8-K were filed by the Company during the quarter ended December 31, 1996.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
TESORO PETROLEUM CORPORATION
By: /s/ BRUCE A. SMITH ---------------------------------- Bruce A. Smith Chairman of the Board of Directors, President and Chief Executive Officer
March 24, 1997
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.
INDEX TO EXHIBITS