ITEM 1. BUSINESS
Tesoro Petroleum Corporation and its subsidiaries ("Tesoro" or the "Company") is a natural resource company engaged in petroleum refining, distribution and marketing of petroleum products, marine services, and the exploration and production of natural gas and oil. These operations are conducted through three business segments: Refining and Marketing, Marine Services, and Exploration and Production.
On May 29, 1998, the Company completed the acquisition (the "Hawaii Acquisition") of all of the outstanding capital stock of BHP Petroleum Americas Refining Inc. and BHP Petroleum South Pacific Inc. (together, "BHP Hawaii") from BHP Hawaii Inc. and BHP Petroleum Pacific Islands Inc. ("BHP Sellers"), affiliates of The Broken Hill Proprietary Company Limited ("BHP"). The Hawaii Acquisition included a 95,000-barrel per day refinery and 32 retail gasoline stations located in Hawaii. Tesoro paid $252.2 million in cash for the Hawaii Acquisition, including $77.2 million for working capital. In addition, Tesoro issued an unsecured, non-interest bearing, promissory note for the Hawaii Acquisition in the amount of $50 million, payable in five equal annual installments of $10 million each, beginning in 2009. On August 10, 1998, the Company completed the acquisition (the "Washington Acquisition" and together with the Hawaii Acquisition, the "Acquisitions") of all of the outstanding stock of Shell Anacortes Refining Company ("Shell Washington"), an affiliate of Shell Oil Company ("Shell"). The Washington Acquisition included a 108,000-barrel per day refinery in Anacortes, Washington and related assets. The total cash purchase price for the Washington Acquisition was $280.1 million, including $43.1 million for working capital. For information relating to the Acquisitions, see Note C of Notes to Consolidated Financial Statements in Item 8.
In conjunction with the Acquisitions and refinancing of its then-existing indebtedness in 1998, the Company issued equity and debt securities providing the Company with $533 million of net proceeds and entered into a $500 million senior credit facility. For information related to the financings, see Note D of Notes to Consolidated Financial Statements in Item 8.
Downstream, the Acquisitions complemented the Company's existing asset base and expanded its marketing areas. The Refining and Marketing segment now operates three petroleum refineries located in: Kenai, Alaska ("Alaska Refinery"), Kapolei, Hawaii ("Hawaii Refinery") and Anacortes, Washington ("Washington Refinery"). The Company sells gasoline through wholesale marketing activities and a network of branded stations in Alaska, Hawaii and the Pacific Northwest. This segment is also a major supplier of jet fuel to the Anchorage, Honolulu and Seattle/Tacoma airports and diesel fuel to the fishing and marine industries in Alaska, Washington, Hawaii and American Samoa. The Company's Marine Services segment operates through a network of 19 marine terminals located in Louisiana and Texas and on the U.S. West Coast, distributing petroleum products and providing logistics services to the offshore Gulf of Mexico drilling industry and other customers. Upstream, the Company's Exploration and Production segment focuses on exploration, development and production of natural gas and oil in Texas, Louisiana and Bolivia. The Company's net proved worldwide reserves totaled 555 billion cubic feet equivalents ("Bcfe") of natural gas at year-end 1998.
Tesoro was incorporated in Delaware in 1968 (a successor by merger to a California corporation incorporated in 1939). Its principal executive offices are located at 8700 Tesoro Drive, San Antonio, Texas 78217-6218 and its telephone number is (210) 828-8484.
For financial and statistical information relating to the Company's operations, see Management's Discussion and Analysis of Financial Condition and Results of Operations in Item 7 and Notes E and O of Notes to Consolidated Financial Statements in Item 8.
REFINING AND MARKETING
OVERVIEW
The Company operates petroleum refineries in Alaska, Hawaii and Washington and sells refined products to a wide variety of customers in Alaska, Hawaii and American Samoa, along the U.S. West Coast, primarily in the Pacific Northwest, and in certain other South Pacific and East Asian markets, including Russia. During 1998, products from the refineries accounted for approximately 91% of these sales volumes, including products received on exchange in the U.S. West Coast market, with the remainder purchased from other refiners and suppliers. By comparison, in 1997 the Refining and Marketing segment refined about 78% of its sales volume with 22% purchased from others.
REFINERIES
The Company owns three refineries with combined rated throughput capacity of 275,000 barrels per day ("bpd"). Capacity and actual 1998 throughput (thousand bpd) by refinery are summarized below. Throughput volumes for Hawaii and Washington refineries are since the 1998 acquisition dates, averaged over the periods owned.
The Company's refineries primarily manufacture gasoline, jet fuel, diesel fuels and residual fuel oil. Other products manufactured include liquefied petroleum gas, naphtha, liquid asphalt and sulphur. Refined products manufactured are summarized below. Manufactured volumes for 1998 include amounts from the Hawaii and Washington refineries since the acquisition dates, averaged over the entire year.
The Alaska Refinery is located in Kenai, Alaska, approximately 70 miles southwest of Anchorage, Alaska, where it has access to multiple sources of crude oil. The Alaska Refinery is capable of producing liquefied petroleum gas, gasoline, jet fuel, diesel fuel, heating oil, liquid asphalt, heavy oils and residual products. In October 1997, the Company completed an expansion of the Alaska Refinery's hydrocracker unit, which increased the unit's capacity by approximately 25% to 12,500 bpd and enables the Company to produce more jet fuel. The expansion, together with the addition of a new, high-yield jet fuel hydrocracker catalyst, began to improve the Alaska Refinery's product slate during the fourth quarter of 1997. At the time of the expansion, the Company completed a scheduled 30-day maintenance turnaround of all major process units at the Alaska Refinery. The next turnaround is scheduled for June 1999.
The Hawaii Refinery, located at Kapolei in an industrial park 22 miles west of Honolulu, was acquired by the Company in May 1998. This acquisition added volumes to the Company's existing slate of refined products. The Hawaii Refinery also produces light naphtha, which is sold to Hawaii's gas utility company as feedstock for their manufacture of synthetic natural gas distributed through the Honolulu gas utility pipeline system. The Hawaii Refinery began operations in 1972 and has been expanded progressively in capacity and
complexity. Major product upgrade units include the distillate hydrocracker, vacuum distillation and catalytic reformer units. All major process units were included in a 30-day maintenance turnaround in June 1998.
The Washington Refinery, located in Anacortes on Puget Sound, about 60 miles north of Seattle, was acquired from Shell in August 1998. The Washington Refinery includes fluid catalytic cracker ("FCC"), vacuum distillation and catalytic reformer units. The Washington Refinery is the most complex of the Company's refineries. The FCC and other product upgrade units enable the Washington Refinery to produce 85% of its output as gasoline, diesel and jet fuel. The acquisition of the Washington Refinery shifted the Company's manufactured product mix by increasing gasoline yield and decreasing lower-value heavy oil and residual products. The FCC can also upgrade heavy vacuum gas oils from the Alaska and Hawaii refineries. In mid-1998 before Tesoro acquired the operations, the FCC and certain other process units were included in a maintenance turnaround, and a new asphalt plant was completed. A maintenance turnaround of the crude distillation and catalytic reformer units is scheduled for September 1999.
CRUDE OIL SUPPLY
Crude oil feedstocks for the Company's refineries are supplied from several sources, primarily in Alaska, Canada, Australia, Papua New Guinea and Southeast Asia. Purchases are made through short-term contracts and spot market purchases. Prices under the short-term contracts fluctuate with market prices of the crude oil.
The Alaska Refinery primarily runs Alaskan crude oils, both Cook Inlet and Alaskan North Slope ("ANS"), with occasional spot market purchases of other crudes. Crude oil is delivered by tanker to the Alaska Refinery through the Kenai Pipe Line Company ("KPL") marine terminal, which is a Company-owned, common carrier and marine dock facility, and by a pipeline connected directly with some of the Cook Inlet producing fields. During 1998, the Company purchased approximately 31,500 bpd of ANS crude oil from the State of Alaska under a three-year contract that expired on December 31, 1998. The Company continues to purchase ANS crude on a spot basis. Cook Inlet crude oil is generally purchased from several suppliers under annual contracts with renewal provisions and other crudes are purchased in the spot market.
For information related to a settlement of a contractual dispute with the State of Alaska, see Note D of Notes to Consolidated Financial Statements in Item 8.
The Hawaii Refinery's crude oil supply is sourced primarily from Alaska, Australia, Papua New Guinea and Southeast Asia. In connection with the Hawaii Acquisition, the Company and a BHP affiliate entered into a crude oil supply agreement pursuant to which the BHP affiliate will assist the Company in acquiring crude oil feedstocks sourced outside of North America and arrange for the transportation of such crude oil to the Hawaii Refinery. The supply agreement is for a two-year period, expiring in May 2000, and provides for annual payments of $1.4 million by the Company to the BHP affiliate for such services. The Company also purchases ANS for the Hawaii Refinery. Crude oil for the Hawaii Refinery is received through a deep-water, offshore mooring and pipeline system, which also can be used for receiving and loading refined products.
The Washington Refinery's crude oil is sourced primarily from Alaska and Canada, with occasional spot market purchases of other crudes. Alaskan and other crudes are delivered by tanker at the Washington Refinery's ship dock at Anacortes. Crude oil from Canada is received at the Washington Refinery through the Transmountain Pipeline system. Both Alaskan and Canadian crudes are purchased from a variety of producers under short-term contracts.
The Company continuously evaluates the economics of processing opportunistic crude oils, and makes adjustments in the volumes and mix of feedstocks processed at each refinery. Occasionally, a better economic opportunity displaces a previous crude oil purchase commitment and results in the resale of crude oil.
MARKETING
Gasoline. The Company sells gasoline in both the wholesale bulk and retail markets in Alaska and Hawaii and on the U.S. West Coast. The demand for gasoline is seasonal in Alaska and the Pacific Northwest with lowest demand during the winter months. The Company sells up to 35% of the Washington Refinery's
gasoline production to Equilon, a major refiner on the West Coast, through an off-take agreement. This agreement, which has a minimum term of two years, began in August 1998. The Company also sells gasoline to wholesale customers and bulk end-users under supply contracts. Gasoline is also delivered to refiners and marketers in exchange for product received at other locations on the West Coast. The Washington Refinery exchanges 30% of its gasoline production with a major oil company for gasoline received elsewhere on the West Coast. Product is distributed through Company-owned terminals, third-party terminals and truck racks. Gasoline produced in excess of market demand in Alaska is shipped to the U.S. West Coast or exported to East Asia, including Russia.
The Company distributes gasoline to end users in Alaska, Hawaii, Washington and Oregon, by retail sales through 61 Company-operated stations in Alaska and Hawaii, and by wholesale sales through 171 branded dealer stations in Alaska, Washington, Oregon and Hawaii. The Company's retail presence in Oregon and Washington was expanded during 1998 by adding 14 branded stations, bringing the number of "Tesoro" branded gasoline stations in the Pacific Northwest to 44 at year-end. In Hawaii, 32 stations were acquired with the Hawaii Refinery in May 1998. In total, Company-operated stations sold an average of 118,000 gallons per month in 1998, as well as merchandise through convenience stores and gas station kiosks. The Company also sells, at wholesale, to unbranded jobbers and dealers.
In 1998, the Company introduced its new "treasure-burst" logo and related signage. All retail stations in Hawaii were re-imaged in conjunction with the Hawaii Acquisition, and renovation and re-imaging projects were launched at Company-operated stations in Alaska. Thirty Alaska stations with convenience stores are also being re-imaged with Tesoro's new "2GO" trademark.
Middle Distillates. The Company is a major supplier of commercial jet fuel to passenger and cargo airlines in Alaska, Hawaii, American Samoa and Washington. The Company now produces about 15% of the jet fuel manufactured in the West Coast-Alaska-Hawaii area. Several marketers, including the Company, import jet fuel into Alaska and Hawaii. The expansion of the Alaska Refinery's hydrocracker unit in 1997 increased the Company's jet fuel production to supply the growing Alaska market.
The Company's diesel fuel production is sold primarily on a wholesale basis for marine, transportation and industrial purposes. Lesser amounts are sold to end-users through marine terminals and retail gas stations and for power generation in Hawaii and American Samoa. The Company sells diesel fuel through its 110,000-barrel capacity terminal in Ketchikan, Alaska. Diesel fuel is supplied to this terminal from the Alaska and Washington refineries by marine barge. Generally, the production of diesel fuel by refiners in Alaska, Hawaii and the Pacific Northwest is in balance with demand. There are occasions when diesel fuel is imported into or exported from Alaska and Hawaii because of the variability of demand. 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.
The Company markets jet fuel, diesel and gasoline in American Samoa where Tesoro operates the government-owned fuel terminals at Pago Pago Harbor and Pago Pago International Airport. Total capacity of the terminal facilities is 244,000 barrels.
Heavy Oils and Residual Products. All three of the Company's refineries have vacuum units that use crude tower bottoms as a feedstock and further process these volumes into light vacuum gas oil ("LVGO"), medium vacuum gas oil ("MVGO"), heavy vacuum gas oil ("HVGO") and vacuum tower bottoms ("VTBs"). LVGO and MVGO are further processed in the Alaska and Hawaii hydrocrackers, where they are converted into gasoline feedstock, diesel and jet fuel. HVGO is used as an FCC feedstock at the Washington Refinery or sold to other refineries. The VTBs are used to produce liquid asphalt and marine bunker fuel sold on the U.S. West Coast. The Hawaii Refinery also supplies electric power producers in Hawaii with low-sulphur fuel oil. The Company sells its liquid asphalt for paving materials in Alaska, Hawaii and Washington. In Alaska and Washington, demand for liquid asphalt is seasonal because mild weather conditions are needed for highway construction.
TRANSPORTATION
The Company charters two American flag vessels, the Potomac Trader and the Chesapeake Trader, which are used to transport ANS crude oil from the Trans Alaska Pipeline System ("TAPS") terminal at Valdez, Alaska and Cook Inlet crude oil from the Drift River terminal to the Alaska Refinery. The vessels are also used to transport heavy oils and residual products from the Alaska Refinery to the Washington Refinery or other West Coast destinations. The Potomac Trader and Chesapeake Trader are chartered under five-year agreements expiring September 2000 and May 2000, respectively. The Company charters a Russian flag vessel, the Igrim, primarily to transport refined products from the Alaska Refinery to the Far East, including Russia. The Igrim is chartered under an agreement expiring in June 2000. From time to time, the Company also charters other tankers and ocean-going barges to transport petroleum products to its customers in Alaska, on the U.S. West Coast and in the Far East.
The Company operates a common carrier petroleum products pipeline from the Alaska Refinery to its terminal in Anchorage and to the Anchorage airport. This ten-inch diameter pipeline has a capacity to transport approximately 40,000 bpd of products and allows the Company to transport light products to the terminal throughout the year regardless of weather conditions. The KPL facilities assure the Company of uninterrupted use of the dock and pipeline for unloading crude oil feedstocks and loading product inventory on tankers and barges.
Crude oil is transported to Hawaii by tankers and discharged through a single-point mooring terminal ("SPM") about 1.5 miles offshore from the Hawaii Refinery. Three underwater pipelines connect the SPM to the Hawaii Refinery to allow crude oil and products to be transferred to the Hawaii Refinery and to load products from the Hawaii Refinery to ships and barges. The Company transports petroleum products to its terminal facilities and customers in the Hawaiian Islands using tugs and barges under long-term charters. A foreign flag vessel is used under a short-term charter to transport middle distillates and gasoline to Company-operated terminal facilities in American Samoa and fuel oil to a customer in Tahiti. The vessel is also used occasionally to transport refined product imports and exports between Hawaii and the Far East.
The Company distributes refined products to customers on the island of Oahu through a pipeline system with connections to the military at several locations, to commercial customers via third-party terminals at Honolulu International Airport and Honolulu Harbor, and by barge to Company-owned and third-party terminal facilities on the neighbor islands of Maui, Kauai and Hawaii. Product pipelines connect the Hawaii Refinery to Barbers Point Harbor which is 2.5 miles away. The Barbers Point Harbor is able to accommodate barges and product tankers up to 800 feet in length and helps relieve traffic at the SPM.
The Washington Refinery receives crude oil from Canada through the 24-inch Transmountain Pipeline which originates in Edmonton, Canada. Other crudes, including ANS, are received through the Washington Refinery's ship dock. The pipeline and the ship dock are each capable of providing almost 100% of the Washington Refinery's feedstock needs.
Over 90% of the Washington Refinery's clean products (gasoline, jet fuel and diesel) leave via the Olympic Pipeline system. Olympic serves the Seattle area with 16-inch and 20-inch lines and continues to Portland, Oregon with a 14-inch line. A small amount of gasoline is delivered through a neighboring refinery's truck rack, and some diesel fuel is distributed through a truck rack at the Washington Refinery. Jet fuel is occasionally shipped by barge. The Washington Refinery has the capability to move significant volumes of all clean products over its ship dock. All of the fuel oil production is shipped by water. Propane is shipped by both truck and rail.
For further information on transportation, see "Government Regulation and Legislation -- Environmental Controls."
REFINING AND MARKETING STATISTICS
The following table summarizes the Company's refining and marketing operations for the years ended December 31, 1998, 1997 and 1996:
- --------------- (a) Throughput volumes for the Hawaii and Washington refineries are since the dates of acquisition, averaged over the periods owned. Manufactured volumes for 1998 include amounts from the acquired Hawaii and Washington operations since the dates of acquisition, averaged over the full year.
MARINE SERVICES
OVERVIEW
The Company's Marine Services segment markets and distributes a broad range of petroleum products, chemicals and supplies and provides logistical support services to the marine and offshore exploration and production industries operating in the Gulf of Mexico. These operations are conducted through a network of 16 terminals located on the Texas Gulf Coast in Galveston, Freeport, Harbor Island, Port O'Connor, Sabine Pass and Houston, along the Louisiana Gulf Coast in Cameron, Intracoastal City, Berwick, Venice, Port Fourchon and Amelia, and a fleet of tugboats and barges. In January 1998, the Company's Marine Services segment was expanded to include the operations of three terminals located on the U.S. West Coast, previously operated by the Company's Refining and Marketing segment. These terminals are located at Port Hueneme and Stockton, California and Vancouver, Washington.
FUELS AND LUBRICANTS
Fuels and lubricants, which are used by operations such as offshore drilling rigs, offshore production and transmission platforms, and various ships and equipment engaged in seismic surveys, are marketed and distributed from the Company's terminals. The Company also provides petroleum products to tugboats and barges using the Intracoastal Canal System, as well as ships entering various ports in Texas, Louisiana and the U.S. West Coast. The Company's Marine Services segment obtains its supply of fuel from local area refiners.
Total gallons of fuel, primarily diesel fuel, sold by this segment amounted to 181 million, 156 million, and 143 million in 1998, 1997 and 1996, respectively.
The Company is a distributor of major brands of marine lubricants and greases, offering a full spectrum of grades. Total gallons of lubricants sold by the Company's Marine Services segment amounted to 2.3 million, 2.7 million and 2.3 million in 1998, 1997 and 1996, respectively.
LOGISTICAL SERVICES
Through many of its Gulf Coast terminals, the Company provides full-service shore-based support for offshore drilling rigs and production platforms. These quay-side services provide cranes, forklifts and loading docks for supply boats serving the offshore exploration and production industry. In addition, the Company provides warehousing, office space, living quarters, helicopter landing pads, and long-term parking for offshore workers. The Company's terminals also serve as delivery points for drilling products, primarily drilling muds, by providing warehousing, blending, inventory control and delivery services. In 1998, 1997 and 1996, revenues from these logistical services were $11.6 million, $11.3 million and $8.7 million, respectively.
EXPLORATION AND PRODUCTION
OVERVIEW
The Company's Exploration and Production segment is engaged in the exploration for and development and production of natural gas and oil in Texas, Louisiana and Bolivia. This segment also includes the transportation of natural gas, including the Company's production, to common carrier pipelines in South Texas. During 1998, the Company increased its worldwide net proved reserves by 7% to 555 Bcfe of natural gas. Worldwide net production of natural gas and oil averaged 121 million cubic feet equivalents ("MMcfe") per day during 1998.
In the U.S., the Company has made significant progress in diversifying its operations to areas other than the mature Bob West Field in South Texas. The Company's U.S. production from fields outside the Bob West Field rose to 55% of its total U.S. production in 1998, compared to 6% during 1996. During the past three years, the Company has increased its net undeveloped acres in the U.S. from 7,000 at the beginning of 1996 to 154,000 at December 31, 1998. During this timeframe, the Exploration and Production segment purchased interests in the Frio/Vicksburg Trend and the Wilcox Trend along the Gulf Coast of Texas and Louisiana, the Val Verde Basin in Southwest Texas, the East Texas Basin, and the Morrow Trend in the Texas Panhandle. By the end of 1998, the Company served as operator of 48% of its U.S. net production, compared to 5% at year-end 1996. During 1998, the Company's U.S. net proved reserve volumes increased 15% to 174 Bcfe and net production averaged 92 MMcfe per day. The Company participated in the completion of 23 gross development wells and eleven gross exploratory wells in 1998, with seven gross wells drilling or completing at year-end.
In Bolivia, the Company operates under five contracts with the Bolivian government to explore for and produce hydrocarbons. The Company's Bolivian natural gas production is currently sold under contract to the Bolivian government for export to Argentina. The majority of the Company's natural gas and oil reserves in Bolivia are shut-in awaiting access to gas-consuming markets which is expected to be provided by a third-party, 1,900-mile pipeline from Bolivia to Brazil. The pipeline is expected to begin operations during the second quarter of 1999. During 1998, the Company's Bolivian net proved reserve volumes increased by 4% to 381 Bcfe and net production averaged 29 MMcfe per day.
During 1998, the Company wrote-down the capitalized costs of its U.S. and Bolivian oil and gas properties by $28.4 million and $39.9 million, respectively, as required by cost ceiling limitations under full-cost accounting. These write-downs were primarily the result of declines in oil and gas prices during the fourth quarter of 1998.
WORLDWIDE RESERVE REPLACEMENT AND COSTS OF ADDING RESERVES
In 1998, the Company's worldwide net proved reserve additions included 141 Bcfe from discoveries, extensions and purchases of proved properties (70 Bcfe in Bolivia and 71 Bcfe in the U.S.), partly offset by 57 Bcfe from downward revisions of previous estimates. Excluding revisions, 141 Bcfe were added for a 320% replacement of 44 Bcfe of production. Additions were realized with a 77% drilling success rate during 1998, reflecting an 88% success rate on 26 development wells and a 64% success rate on 22 exploratory wells. The Company's three-year worldwide average cost of adding these reserves was $0.60 per Mcfe. In the U.S., 71 Bcfe were added through discoveries, extensions and acquisitions for a 209% replacement of 34 Bcfe of production. In Bolivia, 70 Bcfe were added through discoveries, extensions and acquisitions, a seven-fold replacement of 10 Bcfe of production. The three-year average cost of adding reserves was $1.26 per Mcfe in the U.S. and $0.24 per Mcfe in Bolivia. See Note O of Notes to Consolidated Financial Statements in Item 8.
UNITED STATES
RESERVES
The following table shows the estimated net proved reserves, based on evaluations audited by Netherland, Sewell & Associates, Inc., and gross producing wells for each of the Company's U.S. fields:
- --------------- (a) 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.
WILCOX TREND
The Company has 24,597 net acres, including 18,227 net undeveloped acres, under lease in the Wilcox Trend. Approximately 29% (50.9 Bcfe) of the Company's U.S. net proved reserve volumes are located in 13 producing fields in this trend, including the Bob West Field, the Company's largest U.S. field. The Wilcox Trend extends from Northern Mexico through South Texas into the other Gulf Coast states. Multiple pay sands exist within the Wilcox Trend, where extensive faulting has trapped hydrocarbons in numerous producing zones.
Bob West Field. The Bob West Field, which was discovered by the Company in 1990, is located in the southern part of the Wilcox Trend in Starr and Zapata Counties, Texas. From 1991 to 1997, the Company participated in the completion of 77 gross wells in this 4,000-acre field, including 14 gross wells that were sold in 1995. During 1998, the Company's net natural gas production from the Bob West Field averaged approximately 42 million cubic feet ("MMcf") per day. The Company's estimated net proved reserve
volumes in the Bob West Field totaled 39 Bcfe at December 31, 1998. The Company's working interests in wells located in the Bob West Field range from 33% to 70%. In addition, the Company owns a 70% interest in the field's central gas processing facility which has a gross capacity of 350 MMcf per day. The Company also owns a 25% interest in the field's central compression facility, rated at 19,270 horsepower with an estimated gross capacity of 82 MMcf per day.
FRIO/VICKSBURG TREND
The Company has 23,217 net acres, including 18,129 net undeveloped acres, under lease in the Frio/ Vicksburg Trend. Approximately 19% (32.4 Bcfe) of the Company's U.S. net proved reserve volumes are located in eight producing fields in this trend, primarily the Los Indios, La Reforma and Kent Bayou Fields. The Frio/Vicksburg Trend lies between the Gulf Coast shoreline and the Wilcox Trend.
Los Indios and La Reforma Fields. In December 1996, the Company purchased 25% to 50% working interests in portions of the Los Indios and La Reforma Fields, located in Hidalgo and Starr Counties in South Texas. The Company's working interest covers 11,700 gross acres, which has been evaluated using 50 square miles of three-dimensional ("3-D") seismic data. During 1997 and 1998, three exploratory wells and six development wells were completed. Production from these two fields has increased from 4.8 MMcfe per day net at the date of acquisition to an average of 8 MMcfe per day net in 1998. The Company's estimated net proved reserve volumes in these fields totaled 18 Bcfe at December 31, 1998. Additional drilling is planned in 1999.
Kent Bayou Field. During 1997 and 1998, the Company purchased working interests totaling 89% in one producing well and a 100% working interest in 920 acres adjoining the producing unit located in the Kent Bayou Field in Terrebonne Parish, Louisiana. Production in 1998 averaged 2 MMcfe per day net. A 3-D seismic survey is being analyzed to identify potential development locations. The Company's estimated net proved reserve volumes in this field totaled 10.3 Bcfe at December 31, 1998.
EAST TEXAS BASIN
The Company has 17,777 net acres, including 14,691 net undeveloped acres, under lease in the East Texas Basin. The undeveloped acreage is located on prospects in the Cotton Valley Pinnacle Reef play and on prospects targeting various Cretaceous-aged objectives. The Company is currently analyzing 3-D seismic surveys to evaluate its acreage holdings. Approximately 22% (38.4 Bcfe) of the Company's U.S. net proved reserve volumes are in five fields in this basin, which is located in the northeastern part of Texas.
Oak Hill, Woodlawn and Carthage Fields. In December 1997, the Company purchased interests in three natural gas fields in East Texas, which included interests in the Oak Hill Field in Rusk County, the Woodlawn Field in Harrison County and the Carthage Field in Panola County. The Company purchased an average 90% working interest in seven mature producing wells and approximately 3,500 net acres. The Company serves as operator of these properties. Under current spacing rules regulating development of these fields, approximately 30 infill drilling locations have been identified, seven of which were drilled during 1998. The Company's estimated net proved reserves in these fields increased from 21 Bcfe to 25 Bcfe during 1998. Net production averaged approximately 2.2 MMcfe per day during 1998.
Bethel Dome Field. The Company discovered the Bethel Dome Field, located in Anderson County, Texas in December 1998. The Company's working interest in the field ranges from 75% to 100%. The discovery well was being completed at year-end and is expected to flow to sales in the first quarter of 1999. The well was drilled using 3-D seismic data covering the 1,060 gross acres of controlled leasehold. The discovery added 13 Bcfe to the Company's year-end net proved reserves. The potential for additional development will be evaluated in 1999.
VAL VERDE BASIN
The Company has 81,081 net acres, primarily undeveloped, under lease in the Val Verde Basin in Edwards and Val Verde Counties, Texas. Approximately 15% (26.7 Bcfe) of the Company's U.S. net proved reserve volumes are in this basin, which is located in the southwestern part of Texas.
Vinegarone East Field. The Company discovered the Vinegarone East Field, located in Edwards County, Texas, in 1996. The Company's working interests range from 75% to 100%. The field began production in September 1997 following completion of a 10-mile, 6-inch gathering line. Two exploration and eight development wells were completed in this field during 1997 and 1998. Net production from this field averaged 15 MMcfe per day in 1998. Additional exploration and development wells are planned in 1999.
MORROW TREND
During the third quarter of 1998, the Company acquired properties in four producing fields in the Morrow Trend. The properties were acquired in two separate acquisitions with a combined purchase price of $18 million cash plus the conveyance of a working interest in an undeveloped prospect owned by the Company in South Texas. Through these producing property acquisitions and through previous acquisitions of undeveloped acreage, the Company acquired 25,163 net acres, including 17,742 net undeveloped acres in the Morrow Trend during 1998. The Morrow Trend extends from the Texas Panhandle through the western part of Oklahoma. By the end of 1998, 3-D seismic data had been acquired and is being evaluated over the undeveloped acreage. The acquired properties represent approximately 12% (20.1 Bcfe) of the Company's U.S. net proved reserve volumes at year-end. The largest of these four fields is the Stiles Ranch Field.
Stiles Ranch Field. The Company's working interest in the Stiles Ranch Field, located in Wheeler County in the Texas Panhandle, covers 10,200 gross acres, which is being evaluated by a 3-D seismic acquisition program. Subsequent to the acquisition, four development wells were completed in 1998 and the field was producing an average of 2.1 MMcfe per day net at year-end.
GAS GATHERING AND TRANSPORTATION
The Company owns a 70% interest in the Starr County Gathering System, which consists of two ten-inch diameter pipelines and one twenty-inch diameter pipeline that transport natural gas eight miles from the Bob West Field in South Texas to common carrier pipeline facilities. In addition, the Company owns a 50% interest in the twenty-inch diameter Starr-Zapata Pipe Line that transports natural gas 26 miles from the Starr County Gathering System to a market hub at Fandango, Texas. The Company does not operate either pipeline. During 1998, gross throughput averaged 118 MMcf per day for both the Starr County Gathering System and the Starr-Zapata Pipe Line, with approximately 35% of the throughput consisting of the Company's net working interest share of Bob West Field production. The Starr County Gathering System receives a transportation fee of $0.06 per thousand cubic feet ("Mcf") and the Starr-Zapata Pipe Line receives a fee of $0.07 per Mcf for volumes transported.
MARKETING
The Company's U.S. natural gas production is sold on the spot market and under short-term contracts with a variety of purchasers, including intrastate and interstate pipelines, their marketing affiliates, independent marketing companies and other purchasers who have the ability to move the gas under firm transportation or interruptible agreements. Prices for the Company's natural gas production are subject to regional discounts or premiums tied to regional spot market prices.
U.S. ACREAGE AND PRODUCTIVE WELLS
The Company holds its U.S. acreage through oil and natural gas leases and lease options. The leases have a variety of primary terms and may require delay rentals to continue the primary term, if not productive. The leases may be surrendered by the operator at any time for various reasons, which may include cessation of production, fulfillment of commitments, or failure to make timely payment of delay rentals. The following
tables set forth the Company's U.S. gross and net acreage (thousands of acres) and productive wells at December 31, 1998:
- --------------- (a) Includes 8 gross (3.6 net) gas wells and 1 gross (0.5 net) oil well with multiple completions. At December 31, 1998, the Company was participating in drilling or completing 7 gross (3.7 net) wells.
U.S. OPERATING STATISTICS
The following table summarizes the Company's U.S. exploration and production activities for the years ended December 31, 1998, 1997 and 1996:
- --------------- (a) Includes effects of the Company's natural gas commodity price agreements which amounted to a gain of $0.04 per Mcf in 1998 and losses of $0.05 per Mcf and $0.11 per Mcf in 1997 and 1996, respectively.
(b) Includes effects in 1996 of above-market pricing provisions under a natural gas contract which was terminated effective October 1, 1996 (see Notes E and F of Notes to Consolidated Financial Statements in Item 8).
(c) Does not include the effect of the 1998 oil and gas properties write-down.
(d) All of the Company's drilling is performed by independent drilling contractors.
For further information regarding the Company's U.S. exploration and production operations, see Notes C, E and O of Notes to Consolidated Financial Statements in Item 8.
BOLIVIA
The Company's Bolivian exploration, development and production operations are located in the Chaco Basin in southern Bolivia near the border of Argentina. The Company has discovered six fields in Bolivia since 1976, five of which have currently estimated proved reserves totaling 381 Bcfe at December 31, 1998. The Company intends to complete additional seismic studies and appraisal wells before assigning proved reserves to the sixth field. With gross production of 41 MMcfe per day in 1998, the Company is one of the largest operators in Bolivia. The Company holds five Shared Risk Contracts with Yacimientos Petroliferos Fiscales Bolivianos ("YPFB"), the Bolivian governmental agency responsible for administration of these contracts, covering a total of 1.1 million gross acres. The contract for Block 18 is through the year 2017. The contracts for Block 20 are through the year 2018 for Block 20-Los Suris, which is in the development phase, and through the year 2029 for Block 20-West and Block 20-East, which are in the exploration phase.
FARMOUT AGREEMENT
A farmout agreement executed June 19, 1997, between the Company and Total Exploration Production Bolivie S.A. ("Total"), an affiliate of Total S.A., covers a portion of Block 20-West. Total has the right to drill, at its sole cost, two exploratory wells to earn a 75% interest in the farmout area which consists of 315,000 acres of Block 20-West. If Total drills only one well, Total will earn a 37.5% interest in the farmout area. Total may also satisfy its drilling obligation to earn a full 75% interest by drilling the first well and paying cumulative drilling costs of $40 million. Total commenced drilling the first well in June 1998, which is expected to reach target depth and be tested by the second quarter of 1999.
MARKET FOR NATURAL GAS
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. Management believes that a third-party, 1,900-mile pipeline from Bolivia to Brazil, which is expected to begin operations during the second quarter of 1999, will provide access to potentially larger gas-consuming markets.
The Company's natural gas production is currently sold to YPFB, which in turn sells the natural gas to Yacimientos Petroliferos Fiscales, SA ("YPF"), a publicly-held company based in Argentina. The Company's sale of natural gas production is based on the volume and pricing terms in a take-or-pay contract ("Argentina Contract") between YPFB and YPF. The Argentina Contract's primary term ends March 31, 1999 and has been extended an additional five months to August 31, 1999, at which time the Argentina Contract is expected to expire without renewal. The Company's share of the minimum contract volumes from the Argentina Contract are 37 MMcf per day gross (26 net) through March 31, 1999 and 12 MMcf per day gross (9 net) from April 1999 through August 1999.
Beginning in the second quarter of 1999, sales of natural gas through the new pipeline to Brazil will be governed by a 20-year take-or-pay contract ("Brazil Contract") between YPFB and Petroleo Brasileiro, S.A. ("Petrobras"). Initial Brazilian demand estimates are approximately 125 MMcf per day and are expected to
increase to the 200 MMcf per day level by the end of 1999. Looking forward from 1999, Petrobras estimates that demand from Brazil will increase to the one billion cubic feet per day maximum pipeline capacity in the 2003-2005 timeframe.
Tesoro has a preferential right to 22% of the first 200 MMcf per day sold under the Brazil Contract. For incremental demand above 200 MMcf per day, Petrobras, in its capacity as a producer, has a preferential right to sell production from its Bolivian wells. During March 1999, Petrobras exercised its preferential right for 23% of the first increment of 123 MMcf per day of gas to be sold beginning in 2000 and for 100% of the second increment of 105 MMcf per day of gas to be sold beginning in 2001. Excluding Petrobras' preferential right for gas volumes in excess of 200 MMcf per day, remaining gas sales will be allocated by YPFB to the other producers according to a number of factors, including each producer's reserve volumes and production capacity. Although the new Bolivia-to-Brazil pipeline creates the potential for increased Tesoro gas sales, Tesoro cannot be assured that it will be able to maintain its approximate 20% historical market share for gas sold in excess of 200 MMcf per day.
BOLIVIAN TAXES
Reserves are classified by the Bolivian government as either existing or new hydrocarbons depending upon whether they were in production prior to May 1, 1996 ("Existing Hydrocarbons") or after that date ("New Hydrocarbons"). Existing Hydrocarbons are subject to a 29% royalty to YPFB, plus Bolivian taxes that are equal to an additional 31% of gross revenue. New Hydrocarbons are subject to a more favorable tax treatment. New Hydrocarbons are subject to a tax equal to 18% of gross revenue plus 25% of net income, and there is no royalty paid to YPFB. Under certain circumstances, New Hydrocarbons may be subject to additional taxes including a tax on remittances abroad and a surtax on oil and gas production.
BLOCK 18
The Company has a 100% working interest in a Shared Risk Contract covering 92,625 acres in Block 18. Approximately 35% (133 Bcfe) of the Company's Bolivian reserve volumes are in the Escondido, La Vertiente and Taiguati Fields of Block 18. During 1998, the Company's net production from this block averaged 24 MMcf of gas per day and 700 barrels of condensate per day. A 3-D seismic survey over the Escondido Field was completed in 1997 to identify additional drilling locations. The Escondido X7 well was drilled in 1998, adding 25 Bcfe of net proved reserves. With the exception of the Escondido X7, which is classified as New Hydrocarbons, Block 18 production is classified as Existing Hydrocarbons for tax purposes.
BLOCK 20
The Company has a 100% working interest in Block 20-Los Suris and Block 20-East and a 25% working interest in Block 20-West, which is subject to the provisions of the farmout agreement with Total. All of Block 20 production is classified as New Hydrocarbons for tax purposes.
Block 20-Los Suris. This contract covers 12,350 acres of the Los Suris Field, where approximately 37% (141 Bcfe) of the Company's Bolivian reserve volumes are located. Although this contract is in the development phase, existing wells are shut-in awaiting access to markets. A 3-D seismic survey over Block 20-Los Suris was completed in 1997 to identify additional drilling locations and two exploration wells were drilled in 1998, adding 31 Bcfe of proved reserves.
Block 20-East. This contract, which is in the exploration phase, covers 385,938 acres and includes the Palo Marcado Field, where approximately 28% (106 Bcfe) of the Company's proved Bolivian reserves are located. A 3-D seismic survey was completed over the Palo Marcado Field in 1997 to identify additional drilling locations, and the Palo Marcado X5 was drilled in 1998. Although the well has not reached final depth, the Palo Marcado X5 added 14 Bcfe to net proved reserves at year-end based upon intermediate well logs.
Block 20-West. This contract covers 389,025 acres, of which 315,000 acres are subject to the Total farmout agreement, and extends into the difficult terrain of the Andes mountains. Total has contracted, at its sole cost, for the drilling of the first well under the farmout agreement and it is anticipated that this well will
reach target depth by the second quarter of 1999. Total estimates that the cost of this well will exceed $30 million due to the mountainous location and depth of the objective.
BERETI BLOCK
In November 1998, Total and Tesoro executed a new Shared Risk Contract covering 249,000 gross acres adjacent to the Company's existing acreage. Tesoro holds a 25% working interest in the new acreage, and Total holds the remaining 75%.
RESERVES
The table below shows the estimated net proved reserves, based on evaluations prepared by Netherland, Sewell & Associates, Inc., and productive wells for each of the Company's Bolivian fields. Each of the following fields is operated by the Company:
- --------------- (a) Represents the discounted future net cash flows after Bolivian 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.
BOLIVIAN ACREAGE AND PRODUCTIVE WELLS
The following table sets forth the Company's Bolivian gross and net acreage (thousands of acres) and productive wells at December 31, 1998:
- --------------- (a) Included in productive gas wells are seven gross (seven net) wells with multiple completions. The Company has no producing oil wells in Bolivia.
BOLIVIA OPERATING STATISTICS
The following table summarizes the Company's Bolivian exploration and production activities for the years ended December 31, 1998, 1997 and 1996:
- --------------- (a) Does not include the effect of the 1998 oil and gas properties write-down. (b) No exploratory dry holes or development wells were drilled in Bolivia during the periods presented.
For further information regarding the Company's Bolivian operations, see Notes E and O of Notes to Consolidated Financial Statements in Item 8.
COMPETITION AND OTHER
The petroleum industry is highly competitive in all phases, including the refining of crude oil, the marketing of refined petroleum products, the search for and development of oil and gas reserves, and the marine services business. The industry also competes with other industries that supply the energy and fuel requirements of industrial, commercial and individual consumers. The Company competes with a substantial number of major integrated oil companies and other companies having materially greater financial and other resources than the Company. These competitors have a greater ability to bear the economic risks inherent in all phases of the industry. In addition, unlike the Company, many of its competitors produce large volumes of crude oil which can then be used in connection with their refining operations. The North American Free Trade Agreement has further streamlined and simplified procedures for the importation and exportation of natural gas among Mexico, the United States and Canada. These changes are likely to enhance the ability of Canadian and Mexican producers to export natural gas and other products to the United States, thereby further increasing competition for domestic sales.
The refining and marketing businesses are highly competitive, with price being the principal factor in competition. In the refining industry, the Alaska Refinery competes primarily with other refineries in Alaska and on the U.S. West Coast. The Company's refining competition in Alaska includes two refineries situated near Fairbanks and one refinery situated near Valdez. The Company estimates that such other refineries have a combined capacity to process approximately 267,000 bpd of crude oil. The Company believes that ANS crude oil is the only feedstock used in these competing refineries. After processing the crude oil and removing the lighter-end products, which the Company believes represent approximately 30% of each barrel processed, these refiners are permitted, because of their direct connection to 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 Alaska 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 large, integrated oil companies that do business in Alaska and have materially greater financial and other resources. The Hawaii Refinery competes primarily with one other refinery in Hawaii which is also located at Kapolei and which has a rated capacity of 54,000 bpd of crude oil. Historically, the other refinery produced lower volumes of jet fuel than the Hawaii Refinery. The Washington Refinery competes with several refineries on the U.S. West Coast, including refineries which are larger than the Washington Refinery and which are owned by companies substantially larger than the Company.
The Company is a major producer and distributor of gasoline in Alaska and Hawaii through a large network of Company-operated stations and branded and unbranded dealers and jobbers. The Company supplies 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. The Company also supplies a major oil company in Hawaii through a gasoline sales agreement. The Washington Refinery sells up to 35% of its gasoline to a major refiner through an off-take agreement, and provides another major oil company with about 30% of its gasoline production in exchange for gasoline received elsewhere on the West Coast.
Competitive factors affecting the retail marketing of gasoline in Alaska, Hawaii and the Pacific Northwest include such factors as product price, location and quality together with station appearance and brand-name identification. The Company competes with other petroleum companies, distributors and other developers for new locations. The Company believes it is in a position to compete effectively as a marketer of gasoline in Alaska and Hawaii because of its strong presence in these markets. The Company's Pacific Northwest marketing business sells to independent dealers and jobbers. The Company also sells its gasoline through 44 branded gasoline stations in the Pacific Northwest. The Company competes against independent marketing companies and integrated oil companies when engaging in these marketing operations.
The Company's jet fuel sales in Alaska are concentrated in Anchorage, where it is one of the principal suppliers to the Anchorage International Airport, a major hub for air cargo traffic between manufacturing regions in the Far East and consuming regions in the United States and Europe. In Hawaii, jet fuel sales are concentrated in Honolulu, where the Company is the principal supplier to the Honolulu International Airport. The Company also serves four airports on other islands in Hawaii. In Washington, jet fuel sales are concentrated at the Seattle/Tacoma International Airport. Other refiners and marketers compete for sales at all of these airports.
The Company sells its diesel fuel primarily on a wholesale basis, competing with other refiners and marketers in all of its market areas. Refined products from foreign sources also compete for distillate markets in the Company's Alaskan market area.
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 operators, and in certain locations with one or more major mud companies who maintain their own marine terminals.
The exploration for and production of natural gas and oil is highly competitive in both the United States and in South America. In seeking to acquire producing properties, new leases, concessions and exploration prospects, the Company faces competition from both major and independent oil and natural gas companies. Many of these competitors have financial and other resources substantially in excess of those available to the Company and, therefore, may be better positioned to acquire and develop prospects, hire personnel and market production. The larger competitors may also be able to better respond to factors that influence the market for oil and natural gas production, such as changes in worldwide prices and governmental regulations. Such factors are beyond the control of the Company.
The Company's natural gas production in Bolivia is sold under contract to YPFB, which in turn exports the natural gas to Argentina, as the internal demand for natural gas in Bolivia is limited. The Company believes that a third-party, 1,900-mile pipeline from Bolivia to Brazil, which is expected to begin operations during the second quarter of 1999, will provide access to potentially larger gas-consuming markets. Tesoro has a preferential right to 22% of the first 200 MMcf per day sold under the Brazil Contract. For incremental demand above 200 MMcf per day, Petrobras, in its capacity as a producer, has a preferential right to sell production from its Bolivian wells. During March 1999, Petrobras exercised its preferential right for 23% of the first increment of 123 MMcf per day of gas to be sold beginning in 2000 and for 100% of the second increment of 105 MMcf per day of gas to be sold beginning in 2001. Excluding Petrobras' preferential right for gas volumes in excess of 200 MMcf per day, remaining gas sales will be allocated by YPFB to the other producers according to a number of factors, including each producer's reserve volumes and production capacity. Although the new Bolivia-to-Brazil pipeline creates the potential for increased Tesoro gas sales, Tesoro cannot be assured that it will be able to maintain its approximate 20% historical market share for gas sold in excess of 200 MMcf per day.
A portion of the Company's operations are conducted in foreign countries where the Company is also subject to risks of a political nature and other risks inherent in foreign operations. The Company's operations outside the United States in recent years have been, and in the future may be, materially affected by host governments through increases or variations in taxes, royalty payments, export taxes and export restrictions and adverse economic conditions in the foreign countries, the future effects of which the Company is unable to predict.
GOVERNMENT REGULATION AND LEGISLATION
UNITED STATES
Natural Gas and Oil Regulations. Historically, all domestic natural gas sold in so-called "first sales" was subject to federal price regulations under the Natural Gas Policy Act of 1978 ("NGPA"), the Natural Gas Act ("NGA") and the regulations and orders issued by the Federal Energy Regulatory Commission ("FERC") in implementing such Acts. Under the Natural Gas Wellhead Decontrol Act of 1989, all remaining federal natural gas wellhead pricing and sales regulation was terminated on January 1, 1993.
The FERC also regulates interstate natural gas pipeline transportation rates and service conditions, both of which affect the marketing of gas produced by the Company, as well as the revenues received by the Company for sales of such gas. Since the latter part of 1985, culminating in the Order No. 636 series of orders, the FERC has endeavored to make natural gas transportation more accessible to gas buyers and sellers on an open and non-discriminatory basis. The FERC believes "open access" policies are 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. As a result of the Order No. 636 program, the marketing and pricing of natural gas has been significantly altered. The interstate pipelines' traditional role as wholesalers of natural gas was terminated and replaced by regulations which require pipelines to provide transportation and storage service to others who buy and sell natural gas. Although the FERC's orders do not directly regulate gas producers, such as the Company, they are intended to foster increased competition within all phases of the natural gas industry.
Some aspects of the Order No. 636 program are still being reviewed by the courts and the FERC. In addition, on July 29, 1998, the FERC issued a Notice of Proposed Rulemaking in Docket No. RM98-10 proposing yet another round of revisions to its regulations governing the market for short-term transportation services on regulated gas pipelines. These new regulations are intended to create even greater competition among short-term service offerings and include, among other things, a proposal to require all available short-term capacity to be subject to capacity auctions. The FERC also issued a Notice of Inquiry on July 29, 1998 in Docket No. RM98-12 requesting comments on its pricing policies in the existing long-term transportation services market and the market for new capacity. While the Notice of Inquiry does not propose any specific changes to existing regulations, the FERC seeks comments on whether fundamental aspects of its pricing for long-term service and new capacity should be modified to be more effective in the current, more competitive
environment. It is unclear what impact, if any, increased competition within the natural gas industry will have on the Company and its gas sales efforts. It is not possible to predict what, if any, effect the Order No. 636 program or the new proceedings in Docket Nos. RM98-10 and RM98-12 will have on the Company. The Company believes, however, that it will not be affected any differently than other gas producers or marketers with which it competes.
The oil and gas exploration and production operations of the Company are subject to various types of regulations at the state and local levels. Such regulations include 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.
Environmental Controls. Federal, state, area and local laws, regulations and ordinances relating to the protection of the environment affect all operations of the Company to some degree. An example of a federal environmental law that will require operational additions and modifications is the Clean Air Act, which was amended in 1990. While the Company believes that its facilities generally are in substantial compliance with current regulatory standards for air emissions, over the next several years the Company's facilities will be required to comply with the new requirements being adopted and promulgated by the U.S. Environmental Protection Agency ("EPA") and the states in which the Company operates. These regulations will necessitate the installation of additional controls or other modifications or changes in use for certain emission sources, such as gasoline tank roof seal replacements. Specifics as to the cost of these requirements at certain facilities are still being determined. As part of these requirements, the Company's refineries as well as certain other Company facilities submitted applications for Clean Air Act Amendment Title V permits in 1997. Each application has subsequently been deemed complete by the respective state agencies, and most applications are expected to undergo technical review in 1999. The Company believes it can comply with these new requirements, and in some cases already has done so, without adversely affecting operations.
Additional Federal environmental regulations promulgated on August 21, 1990, and effective on October 1, 1993, set limits on the quantity of sulphur in on-highway diesel fuels which the Company produces. The State of Alaska 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. The EPA has since extended the temporary exemption to July 1, 1999. The Company estimates that capital expenditures will be required for the Company to produce lower sulphur diesel fuel to meet these federal regulations. If the State of Alaska is unable to obtain a permanent waiver from the federal regulations, the Company would produce lower sulphur diesel fuel for on-highway use based on market demand. The Company estimates that such sales accounted for less than 1% of its refined product sales in Alaska. 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 and contingency plans for use during an oil spill response. The Company has prepared and submitted these plans
for approval and 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, on a long-term and short-term basis, tankers and barges for shipment of crude oil from foreign and domestic sources to its Alaska, Hawaii and Washington refineries. 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. As an example, the State of Alaska requires the Company to provide spill-response capability to contain or control and cleanup, an amount equal to (i) 50,000 barrels for a tanker carrying fewer than 500,000 barrels of crude oil or (ii) 300,000 barrels for a tanker carrying more than 500,000 barrels. To meet such requirements, the Company has entered into contracts with various parties to provide initial spill response services, with the Company later to assume those responsibilities after mutual agreement with spill response providers or the state and federal On-Scene Coordinators. The Company has entered into spill response agreements with (i) Cook Inlet Spill Prevention and Response, Incorporated for oil spill response services near the Alaska Refinery; (ii) Clean Islands Council for response services throughout the State of Hawaii; and (iii) Clean Sound Incorporated for response actions associated with the Washington Refinery. In addition, for larger spill contingency capabilities the Company has entered into contracts with Marine Spill Response Corporation in Hawaii and in the Gulf Coast region. The Company believes these contracts and those with other regional spill response organizations that are in place on a location by location basis, provide the additional services necessary to meet spill response requirements established by state and federal law.
Regulations promulgated by the Alaska Department of Environmental Conservation ("ADEC") would have required the installation of dike liners in secondary containment systems for petroleum storage tanks by January 1997. However, on December 18, 1996, ADEC approved the Company's alternative compliance schedule which allows the Company until the year 2002 to implement alternative secondary containment systems for all of the Company's existing petroleum storage tank facilities in Alaska. The total estimated cost of these improvements is approximately $8 million, which is expected to be spent over a five-year period beginning in 1998.
Underground Storage Tanks. Regulations promulgated by the EPA on September 23, 1988, require that all underground storage tanks used for storing gasoline or diesel fuel either be closed or upgraded not later than December 22, 1998, in accordance with standards set forth in the regulations. The Company's service stations subject to the upgrade requirements include locations in Alaska and Hawaii. The Company had upgraded all of its underground storage tanks by December 22, 1998.
Total Environmental Expenditures. The Company's total capital expenditures for environmental control purposes were $10 million during 1998. Capital expenditures for the alternative secondary containment systems discussed above were $1 million in 1998 and are estimated to be $2 million in 1999 and $1 million in 2000. The remaining $4 million is expected to be spent by 2002. Capital expenditures for other environmental control purposes, including tank vapor control seals at the Washington Refinery, waste water treatment system upgrades at the Alaska Refinery and reliability upgrades at the Hawaii Refinery's sulphur recovery unit, are estimated to be $12 million in 1999 and $5 million in 2000. For further information regarding environmental matters, see "Legal Proceedings" in Item 3 and "Environmental Controls", "Oil Spill Prevention and Response" and "Underground Storage Tanks" discussed above.
BOLIVIA
The Company's operations in Bolivia are subject to the Bolivian Hydrocarbons Law and various other laws and regulations. In the Company's opinion, neither the Hydrocarbons Law nor other requirements currently imposed by Bolivian laws, regulations and practices will have a material adverse effect upon its Bolivian operations. For information on the Bolivian Hydrocarbons Law and Bolivian taxation, see "Exploration and Production -- Bolivia" discussed above.
EMPLOYEES
At December 31, 1998, the Company employed approximately 2,140 persons, of whom approximately 66 were located in foreign countries. Approximately 175 employees at the Washington Refinery are covered by a collective bargaining agreement. The Company considers its relations with its employees to be satisfactory.
RISK FACTORS AND INVESTMENT CONSIDERATIONS
VOLATILITY OF PRICES; EFFECT ON EARNINGS AND CASH FLOWS
The Company's refining and marketing earnings and cash flows from operations are dependent upon the margin above fixed and variable expenses (including the cost of crude oil feedstocks) at which the Company is able to sell refined products. In recent years, the prices of crude oil and refined products have fluctuated substantially. These prices depend on numerous factors, including the demand for crude oil, gasoline and other refined products, which in turn depend on, among other factors, changes in the economy, the level of foreign and domestic production of crude oil and refined products, political conditions in the Middle East, the availability of imports of crude oil and refined products, the marketing of alternative and competing fuels and the extent of government regulations. The prices received by the Company for its refined products are also affected by local factors such as local market conditions and the level of operations of other refineries in Alaska, Hawaii and Washington.
The price at which the Company can sell its refined products will be strongly influenced by the commodity price of crude oil. Generally, an increase or decrease in the price of crude oil results in a corresponding increase or decrease in the price of gasoline and other refined products and could have a significant short-term impact on the Company's refining operations and the earnings and cash flows of the Company as a whole. However, each of the Company's refineries maintains inventories of crude oil, intermediate products and refined products, the value of each of which is subject to rapid fluctuation in market prices. In addition, crude oil supply contracts are generally contracts with market-responsive pricing provisions.
Any significant decline in the price for natural gas could have a material adverse effect on the Company's exploration and production operations and the financial condition of the Company as a whole. Prices for natural gas are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas, market uncertainty and a variety of additional factors that are beyond the control of the Company. These factors include the domestic and foreign supply of natural gas, the level of consumer demand, weather conditions, domestic and foreign government regulations, the price and availability of alternative fuels and overall economic conditions. While the Company from time to time enters into agreements with respect to a portion of its future production in an effort to reduce price risk, including commodity price contracts and forward sales agreements, there can be no assurance that such transactions will reduce risk or mitigate the effect of any substantial or prolonged decline in the price of natural gas.
CRUDE OIL SUPPLY
The Company believes an adequate supply of crude oil will be available to its three refineries to sustain the Company's refining operations for the foreseeable future at substantially the levels currently being experienced. However, there can be no assurance that this situation will continue. If additional supplemental crude oil becomes necessary at one or more of its refineries, the Company intends to implement available alternatives that are most advantageous under then prevailing conditions. Implementation of some alternatives could require the consent or cooperation of third parties and other considerations beyond the control of the Company. If the Company is unable to obtain such supplemental crude oil volumes, or is only able to obtain such volumes at uneconomic prices, the Company's results from operations could be materially adversely effected.
HAWAII REFINED PRODUCT MARKET; ECONOMIC CONDITIONS IN HAWAII
In the Hawaii refined product market, local refined products supply currently is reasonably balanced to slightly surplus for all finished products except jet fuel. This could limit the potential future growth in earnings generated by the Hawaii Refinery. One competing gasoline marketer has been importing gasoline for retail sale in Hawaii. In addition, the growth rate in Hawaii's gross state product from 1991 through 1997 was substantially below the U.S. average. If these trends continue, they may have an adverse effect on the business and results of operations of the Company.
HAWAII GASOLINE RETAILING RESTRICTIONS AND STATE GOVERNMENT ALLEGATIONS
In 1991 and 1993 at the request of independent gasoline dealers, the Hawaii legislature enacted a series of two-year moratorium periods during which refiners and jobbers were prevented or restricted from operating additional retail stations pending the outcome of legislative studies. In 1995, legislation was enacted which restricted refiners and jobbers to only one company-operated station per dealer station opened, subject to a maximum of two company-operated stations. In 1997, the Hawaii legislature ended the moratorium with the enactment of a statute that permits refiners and jobbers to acquire or build any number of retail stations, provided these are situated at least one-eighth of a mile from any existing dealer station in the urban Honolulu area and at least one-fourth of a mile from any existing dealer station in the remainder of the State.
On October 1, 1998, the Attorney General for the State of Hawaii filed a lawsuit in the U.S. District Court for the District of Hawaii against thirteen oil companies, including Tesoro Petroleum Corporation and Tesoro Hawaii Corporation, alleging anti-competitive marketing practices in violation of federal and state anti-trust laws. See Item 3, Legal Proceedings, contained herein.
RISKS ASSOCIATED WITH BOLIVIAN AND OTHER INTERNATIONAL OPERATIONS
The Company's international operations are primarily conducted in Bolivia, where it has operated for over 25 years and where it currently explores for and produces hydrocarbons through five contracts with the Bolivian government. Substantially all of the Company's current Bolivian production is sold under contract to the Bolivian government for export to Argentina, as there is currently little internal demand in Bolivia for natural gas. As a result, the Company's Bolivian operations are heavily dependent on its relations with the Bolivian government. Moreover, a majority of the Company's Bolivian reserves are currently shut-in. The Company believes that the recent completion of the construction of a third-party, 1,900-mile pipeline from Bolivia to Brazil will provide access to gas-consuming markets. The Company faces intense competition from major and independent natural gas companies operating in Bolivia for a share of the contractual volumes to be exported to Brazil. Tesoro has a preferential right to 22% of the first 200 MMcf per day sold under the Brazil Contract. For incremental demand above 200 MMcf per day, Petrobras, in its capacity as a producer, has a preferential right to sell production from its Bolivian wells. During March 1999, Petrobras exercised its preferential right for 23% of the first increment of 123 MMcf per day of gas to be sold beginning in 2000 and for 100% of the second increment of 105 MMcf per day of gas to be sold beginning in 2001. Excluding Petrobras' preferential right for gas volumes in excess of 200 MMcf per day, remaining gas sales will be allocated by YPFB to the other producers according to a number of factors, including each producer's reserve volumes and production capacity. Although the new Bolivia-to-Brazil pipeline creates the potential for increased Tesoro gas sales, Tesoro cannot be assured that it will be able to maintain its approximate 20% historical market share for gas sold in excess of 200 MMcf per day. When the pipeline begins operating, which is expected to occur in the second quarter of 1999, the Company's Bolivian gas production will become dependent to a large extent upon the continued demand for natural gas in Brazil and the stability of such markets. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Item 7 and "Exploration and Production -- Bolivia" discussed above.
The future success of the Company's international operations in Bolivia and elsewhere is subject to political, economic and other uncertainties, including, among others, risk of war, revolution, border disputes, expropriation, renegotiation or modification of existing contracts, import, export and transportation regulations and tariffs, taxation policies, including royalty and tax increases and retroactive tax claims, exchange controls,
currency fluctuations and other uncertainties arising out of foreign government sovereignty over the Company's international operations. The Company's international operations may also be adversely affected by laws and policies of the United States affecting foreign trade, taxation and investment. Furthermore, in the event of a dispute arising from its Bolivian or other international operations, the Company may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the jurisdiction of courts in the United States. The Company believes Bolivia possesses relatively stable political and economic environments in which to operate; however, there can be no assurance that political and economic and other uncertainties will not develop in Bolivia or neighboring countries. Such uncertainty or instability could result in new governments or the adoption of new policies that might assume a substantially more hostile attitude toward foreign investment. In an extreme case, such a change could result in voiding pre-existing contracts and/or expropriation of foreign-owned assets.
REPLACEMENT OF RESERVES
The future success of the Company's exploration and production operations depends upon the ability to find, develop or acquire additional oil and gas reserves that are economically recoverable. The proved reserves of the Company will generally decline as reserves are depleted, except to the extent that the Company conducts successful exploration or development activities, acquires properties containing proved reserves, or both. In order to increase reserves and production, the Company must continue its development and exploration drilling and recompletion programs or undertake other replacement activities. The Company's current strategy includes continuing to exploit its existing properties, discovering new reserves through exploration and increasing its reserve base through acquisitions of producing properties. There can be no assurance, however, that the Company's planned exploration, development and acquisition activities will result in significant additional reserves or that the Company will have continuing success drilling productive wells at low finding and development costs. For a discussion of the Company's reserves, see "Exploration and Production -- U.S. -- Reserves" and "Exploration and Production -- Bolivia -- Reserves" discussed above.
DRILLING RISKS
Drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. There can be no assurance that new wells drilled by the Company will be productive or that the Company will recover all or any portion of its investment. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, completing, operating, and other costs. The cost of drilling, completing and operating wells is often uncertain. The Company's drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond the Company's control, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment and services.
RELIANCE ON ESTIMATES OF PROVED RESERVES
There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond the control of the Company. The Company's historical reserve information set forth herein represents estimates based on evaluations either prepared by or audited by Netherland, Sewell & Associates, Inc., as of December 31, 1998.
Petroleum engineering is not an exact science. Information relating to the Company's proved oil and gas reserves is based upon engineering estimates. Estimates of economically recoverable oil and gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions concerning future oil and gas prices, future operating costs, severance and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of the future net cash flows expected therefrom prepared by different engineers or by
the same engineers at different times may vary substantially. Actual production, revenues and expenditures with respect to the Company's reserves will likely vary from estimates, and such variances may be material. See "Exploration and Production -- U.S. -- Reserves" and "Exploration and Production -- Bolivia -- Reserves" discussed above.
The discounted future net cash flows of proved reserves (sometimes referred to herein as "PV10") should not be construed as the current market value of the estimated oil and gas reserves attributable to the Company's properties. In accordance with applicable requirements of the Securities and Exchange Commission ("SEC"), the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate, whereas actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as the amount and timing of actual production, supply and demand for oil and gas, curtailments or increases in consumption by gas purchasers and changes in governmental regulations or taxation. The timing of actual future net cash flows from proved reserves, and thus their actual present value, will be affected by the timing of both the production and the incurrence of expenses in connection with development and production of oil and gas properties. In addition, the 10% discount factor, which is required by the SEC to be used to calculate discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and gas industry in general.
OPERATING HAZARDS AND UNINSURED RISKS
The Company's operations are subject to hazards and risks inherent in drilling for, producing and transporting oil and natural gas and refining crude oil, such as fires, natural disasters, explosions, blowouts, cratering, pipeline ruptures, and spills, any of which can result in loss of hydrocarbons, environmental pollution, personal injury claims, and other damage to properties of the Company and others. As protection against operating hazards, the Company maintains insurance coverage against some, but not all, potential losses. The Company's coverages include, but are not limited to, operator's extra expense, physical damage on certain assets, employer's liability, comprehensive general liability, automobile, workers' compensation and loss of production income insurance. The Company believes that its insurance is adequate and customary for companies of a similar size engaged in operations similar to those of the Company, but losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have an adverse impact on the Company's financial condition and results of operations.
CONCENTRATION OF OPERATIONS
A significant portion of the Company's domestic exploration and production operations are located in the Wilcox Trend along the Texas and Louisiana Gulf Coast. During 1998, the Company made significant progress in diversifying its operations to areas other than the mature Bob West Field, which is located in the Wilcox Trend. At December 31, 1998, approximately 23% of the Company's domestic net proved gas reserves were located in the Bob West Field compared to 39% at December 31, 1997. As a result, any interruption of the Company's production in the Bob West Field due to any one or more of a variety of conditions and events, including natural disaster, reservoir damage, mechanical difficulties, unavailability of equipment and supplies, transportation problems, title and contractual controversies or government regulation, could have a material adverse effect on the Company's operations and its ability to service debt and other obligations. See "Exploration and Production -- U.S. -- Reserves" discussed above.
The Company's refining activities are conducted at its three refineries in Hawaii, Alaska and Washington. The refineries are three of the Company's principal operating assets. As a result, the operations of the Company, and its ability to service debt and other obligations are subject to significant interruption if one or more of the refineries were to experience a major accident, be damaged by severe weather or other natural disaster, or otherwise be forced to shut down. Although the Company maintains business interruption insurance against some types of risks in amounts which the Company believes to be economically prudent, if the refineries were to experience an interruption in operations, the Company's business could be materially adversely affected. See "Refining and Marketing" discussed above.
OTHER
For information on competitive factors affecting the Company's business, see "Competition and Other" discussed above. A discussion of environmental controls and factors are included in "Government Regulation and Legislation" discussed above. Matters related to Year 2000 readiness are addressed in "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained in Item 7 herein. See also "Legal Proceedings" in Item 3 herein.
ITEM 2.
ITEM 2. PROPERTIES
See information appearing under Item 1, Business herein and Notes C, E and O of Notes to Consolidated Financial Statements in Item 8.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
Environmental. The Company is currently involved with the EPA regarding a waste disposal site near Abbeville, Louisiana and the Casmalia Disposal Site in Santa Barbara County, California. The Company has been named a potentially responsible party ("PRP") under the Federal Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA" or "Superfund") at both sites. Although the Superfund law might impose joint and several liability upon each party at the sites, the extent of the Company's allocated financial contributions for cleanup is expected to be de minimis based upon the number of companies, volumes of waste involved, and total estimated costs to close each site. The Company believes, based on these considerations and discussions with the EPA, that its liability at the Abbeville site will not exceed $25,000. The Company believes that its liability at the Casmalia Site is de minimis based on a February 1, 1999 notification from the EPA indicating that the Company's liability will not exceed $125,000.
On August 26, 1998, the United States Coast Guard issued a Notice of Federal Interest For An Oil Pollution Incident to Tesoro Hawaii Corporation ("Tesoro Hawaii"), a subsidiary of the Company, in connection with an oil spill which occurred on August 24, 1998, at Tesoro Hawaii's single point mooring at Barbers Point, Oahu, Hawaii. Tesoro Hawaii, the Coast Guard and the Hawaii Department of Health ("HDOH") responded to the spill immediately and clean up efforts have been completed. Under the Federal Water Pollution Control Act and the Oil Pollution Act of 1990, the responsible party is liable for removal costs and damages, including damages from injury to natural resources and may be assessed administrative or civil penalties. The Company carries insurance to provide protection against pollution damages. The Company believes that the resolution of this oil spill will not have a material adverse effect on the Company.
On October 2, 1998, the Alaska Department of Environmental Conservation ("ADEC") issued a Notice of Violation ("NOV") against the Alaska Refinery related to non-compliance with the facility air quality permit. This NOV alleges that an air emission treatment unit at the Alaska Refinery groundwater treatment system did not maintain the air contaminant removal efficiency rate required in the facility air quality permit. The Company has initiated discussions with the ADEC on this matter and believes that the resolution thereof will not have a material adverse effect on the Company.
As previously reported, on October 16, 1998, the HDOH issued a Notice of Apparent Violation of Hawaii state law to Tesoro Hawaii in connection with a spill on September 23, 1998. During the loading of a time-chartered barge, diesel fuel was spilled into the state waters at Barbers Point Harbor, Oahu, Hawaii. It was immediately cleaned up by the charterer of the barge. Hawaii law requires that appropriate action to correct an apparent violation must be taken and further provides for civil penalties. HDOH notified Tesoro Hawaii on November 24, 1998 that due to the Tesoro Hawaii immediate response, clean-up and implementation of corrective and preventive measures, HDOH does not intend to pursue an enforcement action against Tesoro Hawaii.
The Company is currently involved with a waste water disposal site in Redwood City, California. On December 18, 1998, the Port of Redwood City filed suit against numerous defendants, including the Company, for contribution pursuant to CERCLA and the Resource Conservation and Recovery Act ("RCRA"). The Company has negotiated with the Port of Redwood City and expects to settle its liability in
early 1999. The Company believes it is not subject to joint and several liability for the clean-up of the site and that its liability will not exceed $40,000.
The EPA issued a NOV on June 24, 1997, against the Hawaii Refinery alleging violations of the Clean Water Act associated with the content and implementation of the Hawaii Refinery's Spill Prevention, Control and Countermeasures ("SPCC") Plan, and further alleging violations based on a series of oil releases. The Company and the EPA remain engaged in settlement discussions with remaining issues limited to alleged deficiencies in the content and implementation of the Hawaii Refinery's SPCC. This proceeding is subject to the indemnity provision of the environmental agreement between the BHP Sellers and the Company, and the Company believes that resolution of this matter will not have a material adverse effect on the Company.
Also on June 24, 1997, a NOV was issued against BHP companies pursuant to Section 103 of the CERCLA and Section 304 of the Emergency Planning and Community Right to Know Act ("EPCRA") regarding past releases of reportable quantities of regulated substances and oil. This matter remains subject to EPA review and penalty amounts have not been assessed to date. This proceeding is subject to the indemnity provisions of the environmental agreement between the BHP Sellers and the Company, and the Company believes that resolution of this matter will not have a material adverse effect on the Company.
On August 5, 1996, the EPA issued a Finding of Violation ("FOV") against BHP Hawaii pursuant to disclosures made by BHP Hawaii pursuant to a permit application for compliance with Title V of the Clean Air Act. The parties have engaged in settlement negotiations and no penalty amount has been assessed. This proceeding is subject to the indemnity provision of the environmental agreement between the BHP Sellers and the Company, and the Company believes that resolution of this matter will not have a material adverse effect on the Company.
As previously reported, on May 19, 1998, the EPA issued a NOV against Tesoro Alaska Petroleum Company, a subsidiary of the Company, alleging violations of the RCRA associated with the failure to maintain closure of certain containers of hazardous waste at the Alaska Refinery when not in use and the failure to retain on-site certain records of land disposal restriction notifications. On August 28, 1998, the EPA conducted a subsequent inspection at the facility and issued a finding of no violations of RCRA.
Other. As previously reported, on October 1, 1998, the Attorney General for the State of Hawaii filed a lawsuit in the U.S. District Court for the District of Hawaii against thirteen oil companies, including Tesoro Petroleum Corporation and Tesoro Hawaii Corporation, alleging anti-competitive marketing practices in violation of federal and state anti-trust laws, and seeking injunctive relief and compensatory and treble damages and civil penalties against all defendants in an amount in excess of $500 million. On March 25, 1999, the Attorney General filed an amended complaint with the U.S. District Court seeking damages against all defendants for such alleged anti-competitive marketing practices in an amount in excess of $1.3 billion. The Company believes that it has not engaged in any anti-competitive activities and will defend this litigation vigorously. This proceeding is subject to the indemnity provision of the stock sale agreement between the BHP Sellers and the Company which provides for indemnification in excess of $2 million and not to exceed $65 million.
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 Company's Common Stock is listed under the symbol "TSO" on the New York Stock Exchange and the Pacific Stock Exchange. The per share market price ranges for the Company's Common Stock on the New York Stock Exchange during 1998 and 1997 are summarized below:
At March 1, 1999, there were approximately 3,200 holders of record of the Company's 32,341,386 outstanding shares of Common Stock. The Company has not paid dividends on its Common Stock since 1986.
For information regarding restrictions on future dividend payments, see Management's Discussion and Analysis of Financial Condition and Results of Operations in Item 7 and Note D of Notes to Consolidated Financial Statements in Item 8. The Board of Directors has no present plans to pay dividends on Common Stock. However, from time to time, the Board of Directors reevaluates the feasibility of declaring future dividends on Common Stock.
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
Those statements in the Management's Discussion and Analysis that are not historical in nature should be deemed forward-looking statements that are inherently uncertain. See "Forward-Looking Statements" on page 48 for discussion of the factors which could cause actual results to differ materially from those projected in such statements.
GENERAL
The Company's strategy is to (i) maximize earnings, cash flows and return on capital employed and increase the competitiveness of each of its business units by reducing costs, increasing operating efficiencies and optimizing existing assets and (ii) expand its overall market presence through a combination of internal growth initiatives and selective acquisitions which are both accretive to earnings and provide significant operational synergies. The Company plans to further improve profitability in the Refining and Marketing segment by enhancing processing capabilities, strengthening marketing channels and improving supply and transportation functions. Improved profitability has positioned the Marine Services segment to participate in the consolidation of the industry by pursuing opportunities for expansion, as well as optimizing existing operations. In the Exploration and Production segment, the strategy focuses on generating and operating exploration projects in an effort to diversify its oil and gas production and reserve base. Selectively, the Company uses acquisitions and enhanced technical capabilities. The Company has made significant progress in diversifying its U.S. operations to areas other than the Bob West Field and has taken steps to begin serving emerging markets in South America.
As part of this strategy, the Company completed the following Refining and Marketing acquisitions during 1998:
- On May 29, 1998, the Company completed the acquisition (the "Hawaii Acquisition") of all of the outstanding capital stock of BHP Petroleum Americas Refining Inc. and BHP Petroleum South Pacific Inc. (together, "BHP Hawaii") from BHP Hawaii Inc. and BHP Petroleum Pacific Islands Inc., affiliates of The Broken Hill Proprietary Company Limited ("BHP"). The Hawaii Acquisition included a 95,000-barrel per day refinery (the "Hawaii Refinery") and 32 retail gasoline stations located in Hawaii. Tesoro paid $252.2 million in cash for the Hawaii Acquisition, including $77.2 million for working capital. In addition, Tesoro issued an unsecured, non-interest bearing, promissory note for the purchase in the amount of $50 million, payable in five equal annual installments of $10 million each, beginning in 2009.
- On August 10, 1998, the Company completed the acquisition (the "Washington Acquisition" and together with the Hawaii Acquisition, the "Acquisitions") of all of the outstanding stock of Shell Anacortes Refining Company ("Shell Washington"), an affiliate of Shell Oil Company. The Washington Acquisition included a 108,000-barrel per day refinery (the "Washington Refinery") in Anacortes, Washington and related assets. The total cash purchase price for the Washington Acquisition was $280.1 million, including $43.1 million for working capital.
The Acquisitions are expected to triple Tesoro's historical annual revenues and significantly increase the scope of its refining and marketing operations. The Acquisitions had a positive impact on earnings and cash flows in the fourth quarter of 1998, and management expects that the Acquisitions will add to earnings and cash flows in 1999. Management believes that there are significant cost-saving and revenue-enhancement opportunities available by integrating the Hawaii and Washington refineries with the Alaskan operations and has identified approximately $25 million of potential annual cost saving and revenue enhancing synergies. Management expects to realize the full annual impact of such synergies during 1999. The Company will continue to pursue other opportunities that are operationally and geographically complementary with its asset base.
In conjunction with the Acquisitions and refinancing of its then-existing indebtedness ("Refinancing") in 1998, the Company issued equity and debt securities providing the Company with $533 million of net proceeds
and entered into a $500 million senior credit facility ("Senior Credit Facility"). For information related to the financings, see Note D of Notes to Consolidated Financial Statements in Item 8.
BUSINESS ENVIRONMENT
The Company operates in an environment where its earnings and cash flows are sensitive to volatile changes in energy prices. Fluctuations in the cost of crude oil used for refinery feedstocks and the price of refined products can result in changes in margins from the Refining and Marketing operations, as prices received for refined products may or may not keep pace with changes in crude oil costs. These energy prices, together with volume levels, also determine the carrying value of crude oil and refined product inventory. The Company uses the last-in, first-out ("LIFO") method of accounting for inventories of crude oil and U.S. wholesale refined products in its Refining and Marketing segment. This method results in inventory carrying amounts that are less likely to represent current values and in costs of sales which more closely represent current costs. If, however, fluctuations in market prices cause the market value of inventories to fall below their LIFO cost, the Company would write-down its inventories to estimated realizable value.
Changes in crude oil and natural gas prices also influence the level of drilling activity in the Gulf of Mexico. The Company's Marine Services segment, whose customers include offshore drilling contractors and related industries, can be impacted by significant fluctuations in natural gas, condensate and oil prices. The Company's Marine Services segment uses the first-in, first-out ("FIFO") method of accounting for inventories of fuels. Changes in fuel prices can significantly impact inventory valuations and costs of sales in this segment.
Changes in natural gas, condensate and oil prices impact revenues and the present value of estimated future net revenues and cash flows from the Company's Exploration and Production segment. The Company may increase or decrease its natural gas production in response to market conditions. The carrying costs of oil and gas assets are subject to noncash write-downs based on decreases in natural gas and oil prices and other determining factors. In 1998, the Company recorded a $68.3 million noncash write-down of its oil and gas properties. It is reasonably possible that the present value of proved oil and gas reserves could be significantly reduced during the first quarter of 1999 due to further decreases in natural gas and oil prices since year-end. This could result in further write-downs of the Company's oil and gas properties.
RESULTS OF OPERATIONS
SUMMARY
Tesoro's net loss for 1998 was $19.4 million, compared with net earnings of $30.7 million and $74.5 million in 1997 and 1996, respectively. In 1998 and 1996, the Company incurred aftertax extraordinary losses of $4.4 million and $2.3 million, respectively, for early extinguishments of debt. Results before extraordinary losses amounted to a loss of $15.0 million in 1998 and earnings of $30.7 million and $76.8 million in 1997 and 1996, respectively. The net loss per share for 1998 was $0.86 (basic and diluted) after preferred dividends, compared with net earnings per basic share of $1.16 ($1.14 diluted) and $2.87 ($2.81 diluted) in 1997 and 1996, respectively. Significant items, including write-downs of oil and gas properties, which affect the comparability between results for the years ended December 31, 1998, 1997 and 1996 are highlighted in the table below (in millions except per share amounts):
Excluding the significant items affecting comparability, net earnings would have been $27.3 million in 1998, compared with net earnings of $27.9 million in 1997 and $13.9 million in 1996. Increased Refining and Marketing results in 1998 were substantially offset by higher interest and financing costs and lower natural gas sales prices in the Exploration and Production segment. When comparing 1997 with 1996, after excluding significant items, the $14 million improvement in net earnings was primarily attributable to better refined product margins, higher spot market natural gas prices and lower interest expense.
Net earnings per share, after excluding significant items, would have been $0.72 per basic share ($0.71 diluted) for 1998, compared with $1.06 per basic share ($1.04 diluted) in 1997 and $0.53 per basic and
diluted share in 1996. On a per share basis, the Company's results for 1998 were reduced by dividends on Preferred Stock and the impact of issuing additional shares of Common Stock during the year.
The accompanying consolidated financial statements and related notes, together with the following discussion and analysis, are intended to provide shareholders and other investors with a reasonable basis for assessing the Company's operations, but should not serve as the only criteria for predicting the future performance of the Company.
REFINING AND MARKETING
- --------------- (a) Amounts reported for 1997 and 1996 have been reclassified to conform with current presentation, primarily to reclassify retail margins and intrasegment transportation revenues from non-refinery margin to refinery product spread.
(b) Sales and manufactured volumes for 1998 included amounts from the acquired Hawaii and Washington operations since the acquisition dates, averaged over the full year. Refinery throughput for 1998 included volumes from the Hawaii and Washington refineries, averaged over the periods owned since acquisition.
(c) Sources of total product sales included products manufactured at the Company's refineries, products drawn from inventory balances and products purchased from third parties.
(d) Gross margins on product sales included margins on sales of manufactured and purchased products and the effects of inventory changes.
1998 Compared with 1997. Segment operating profit from the Refining and Marketing operations totaled $69.7 million in 1998, an increase of $49.2 million from segment operating profit of $20.5 million in 1997. The increase in segment operating profit was primarily due to higher throughput and sales volumes, primarily from the acquired refineries (see Note C to Consolidated Financial Statements in Item 8), and improved refined product yields in Alaska. Financial results from the acquired operations have been included since the dates of acquisition. The Hawaii Acquisition was completed on May 29, 1998, and the Washington Acquisition was completed on August 10, 1998. The Acquisitions contributed positively to the segment's operating profit in 1998; however, on a consolidated basis, these results were largely offset by corporate interest and financing costs.
During 1998, the Company's refined product yields in Alaska benefitted from an expansion of the hydrocracker unit completed in October 1997. The expansion, which increased the unit's capacity by approximately 25%, enables production of more jet fuel. Segment results were favorably impacted by this expansion beginning in the fourth quarter of 1997. During 1998, average throughput at the Alaska Refinery increased by 7,400 barrels per day, a 15% increase over 1997 which included a 30-day maintenance turnaround. Production of jet fuel at this refinery increased by approximately 30% over 1997 due to the hydrocracker expansion and higher throughput levels.
The Alaska hydrocracker expansion and the Acquisitions contributed to an increase in the proportion of higher value gasoline and middle distillates manufactured by the Company in 1998. Conversely, the proportion of lower value heavy oils and residual products manufactured by the Company decreased in 1998. The higher-value mix of product partly offset market pressures which decreased year-to-year refinery product spreads to $5.67 per barrel in 1998 from $6.38 per barrel in 1997. Increased gross margins of $5.07 per barrel in 1998, which compare to $4.84 per barrel in 1997, reflected the higher-value mix of manufactured product and a reduction in products purchased and resold. In 1998, products from the Company's refineries accounted for
approximately 91% of its sales volume, compared with 78% in 1997, enabling the Company to reduce the amounts of products purchased from others which generally sell at lower margins.
Revenues from sales of refined products in the Refining and Marketing segment increased during 1998 primarily due to the higher sales volumes from the Acquisitions, partially offset by lower sales prices. Export sales of refined products increased to $35.5 million in 1998, compared with $16.1 million in 1997, primarily due to sales from Hawaii to Asia partly offset by a decrease in exports from the Alaska Refinery to the Far East. Other revenues included crude oil resales of $29.9 million in 1998 compared to $44.4 million in 1997. Merchandise sales, also included in other revenues, increased in 1998 due to the Hawaii Acquisition which included 30 Company-operated retail stations. The increase in costs of sales reflected higher volumes associated with the Acquisitions, partly offset by lower feedstock prices. Margins from non-refinery activities increased to $22.6 million in 1998, compared with $13.0 million in 1997, primarily due to the higher merchandise sales. Operating expenses and depreciation and amortization were higher in 1998 primarily due to the Acquisitions.
With the acquisitions of the Hawaii and Washington refineries, enhancements of product mix and expansion of market areas, the Company has improved the fundamental earnings potential of this segment. Management plans to further improve profitability by enhancing processing capabilities, strengthening marketing channels and improving supply and transportation functions. The ability to supply these expanded markets with a higher proportion of manufactured products, rather than purchased products, is also expected to improve profitability. Future profitability of this segment, however, will continue to be influenced by market conditions, particularly as these conditions influence costs of crude oil relative to prices received for sales of refined products, and other additional factors that are beyond the control of the Company.
1997 Compared with 1996. The Refining and Marketing segment's operating profit of $20.5 million in 1997 increased $14.5 million from operating profit of $6.0 million in 1996. The improvement was due in part to the Company's initiatives to enhance its product slate, improve efficiencies and sell a larger portion of the Alaska Refinery's production within the core Alaska market. The expansion of the hydrocracker unit discussed above began to favorably impact this segment's results in the fourth quarter of 1997. In October 1997, the Company began purchasing approximately 25,000 barrels per day of Cook Inlet crude oil in addition to the 9,000 barrels per day under previously existing contracts.
During 1997, the Company's production of refined products increased by 5%. The operational changes, discussed above, resulted in an 8% increase in the production of higher-value middle distillates, primarily jet fuel, while production of lower-value heavy oils, residual products and other increased by 5%. The improved product slate, which better matches the Company's product supply with demand in Alaska, reflected a change of the hydrocracker catalyst in late 1996, as well as the hydrocracker expansion and catalyst change in late 1997. The Company's sales of refined products within Alaska increased by 6% in 1997, contributing to higher product margins. The improved product slate and marketing efforts, together with generally favorable industry conditions, resulted in an increase in the Company's refinery spread to $6.38 per barrel in 1997, compared to $5.33 per barrel in 1996. Both years included scheduled 30-day maintenance turnarounds.
Revenues from sales of refined products in the Refining and Marketing segment increased during 1997, reflecting a 6% increase in sales volumes, partially offset by slightly lower average sales prices. Total refined product sales averaged 65,900 barrels per day in 1997, compared to 62,200 barrels per day in 1996. Other revenues, which included crude oil resales of $44.4 million in 1997 and $93.8 million in 1996, declined due to lower sales volumes and prices. The Company had less crude oil available for resale in 1997 as throughput at the Alaska Refinery increased by 2,700 barrels per day, or 6%, from 1996. Export sales of refined products, including sales to Russia, amounted to $16.1 million in 1997, compared to $22.0 million in 1996. Costs of sales decreased in 1997 due to lower spot purchases of crude oil and lower prices. Margins from non-refinery activities decreased to $13.0 million in 1997 due primarily to lower margins on refined product purchased for resale. Operating expenses and other increased 9% in 1997 due primarily to higher employee costs, professional fees and marketing expenses.
MARINE SERVICES
1998 Compared with 1997. Gross operating revenues decreased 10% from $132.2 million in 1997 to $118.6 million in 1998, reflecting a $13.4 million decline in fuel revenues from lower market prices partly offset by a 16% increase in fuel sales volumes. The increase in fuel volumes was attributable to operations in the Gulf of Mexico and the transfer of three West Coast terminals from the Company's Refining and Marketing segment to Marine Services in January 1998. The decrease in costs of sales also reflected lower fuel prices, partly offset by increased volumes. Gross profit, which improved by $4.1 million due to higher volumes, was partly offset by additional operating expenses from the West Coast terminals and higher depreciation and amortization resulting from upgrades to facilities. Despite lower rig activity in the Gulf of Mexico, total segment operating profit increased by $2.3 million largely due to the Company's ability to emphasize customer service, control expenses and increase sales volumes.
Profitability of the Marine Services segment can be affected significantly by the level of oil and gas drilling, workover, construction and seismic activity in the Gulf of Mexico. With depressed oil and gas prices continuing into 1999, exploration and production activity in the Gulf of Mexico has significantly declined. While the Company's Marine Services segment has taken initiatives to be a low-cost provider and has expanded its operations into the West Coast, its operating results will be adversely impacted by reduced sales volumes and pressure on margins in the near term.
1997 Compared with 1996. Gross operating revenues increased by $9.7 million, which included a $7.1 million increase in fuels and lubricant revenues and a $2.6 million increase in service revenues. The increase in fuels and lubricant revenues reflected a 10% increase in sales volumes, partially offset by lower prices. The 30% increase in service revenue was due in part to increased rig activity in the Gulf of Mexico and the Company's focus to serve these customers. Additional terminal locations stemming from an acquisition in February 1996 together with internal growth initiatives have enabled the Company to increase its sales activity. Costs of sales increased in 1997 due to the higher volumes. The improvement of $6.0 million in gross profit was largely offset by higher operating and other expenses associated with the increased activity and higher depreciation and amortization expense.
EXPLORATION AND PRODUCTION
- --------------- (a) Represents the Company's U.S. oil and gas operations combined with gas transportation activities. (b) Results for 1996 included revenues from sales of natural gas at above-market prices under a contract with Tennessee Gas Pipeline Company ("Tennessee Gas") which was terminated effective October 1, 1996. During 1996, the spot market price for natural gas was $1.95 per Mcf, while the average price, including the impact of the Tennessee Gas contract, was $2.75 per Mcf. Net natural gas production sold under the contract averaged approximately 11 MMcf per day in 1996. Operating profit for 1996 included $24.6 million from the excess of these contract prices over spot market prices. Upon termination of the contract, the Company recorded other income and operating profit of $60 million during the fourth quarter of 1996. See Note F of Notes to Consolidated Financial Statements in Item 8. (c) Operating profit for 1998 included income from receipt of $21.3 million from an operator in the Bob West Field, representing funds that were no longer needed as a contingency reserve for litigation. (d) Includes effect of the Company's natural gas commodity price agreements which amounted to a gain of $0.04 per Mcf in 1998 and to losses of $0.05 per Mcf in 1997 and $0.11 per Mcf in 1996.
EXPLORATION AND PRODUCTION -- U.S.
1998 Compared with 1997. Segment operating profit from the Company's U.S. exploration and production operations was $17.5 million, compared with $37.3 million in 1997. Comparability between these years was impacted by certain significant items. Results for 1998 included income from receipt of $21.3 million from an operator in the Bob West Field, representing funds that were no longer needed as a contingency reserve for litigation, and a write-down of its domestic oil and gas properties of $28.4 million. In 1997, the Company recognized income of $1.8 million for retroactive severance tax refunds. Excluding these significant items, segment operating profit decreased by $10.9 million in 1998 primarily due to lower prices, higher depletion and increased production costs.
Gross operating revenues from the Company's U.S. operations decreased by $2.1 million as lower sale prices generally offset higher production volumes. Prices realized by the Company on its natural gas production declined to $2.02 per Mcf in 1998 from $2.17 per Mcf in 1997. The Company's U.S. production averaged 92.4 MMcfe per day in 1998, compared with 86.8 MMcfe per day in 1997. The 5.6 MMcfe per day increase consisted of a 30.3 MMcfe per day increase in production from outside the Bob West Field, partially offset by a 24.7 MMcfe per day decline at the Bob West Field. Production from outside the Bob West Field provided 55% of the Company's total production in 1998, compared to 24% in 1997.
Total production costs increased $2.3 million, to $9.7 million in 1998 from $7.4 million in 1997. On a per unit basis, total production costs increased to $0.29 per Mcfe in 1998 from $0.23 per Mcfe in 1997. Production costs from outside the Bob West Field increased by $3.0 million due to the higher volumes from these newer fields, but on a per unit basis, production costs from these fields declined to $0.32 per Mcfe in 1998 from $0.40 per Mcfe in 1997. Production costs at the Bob West Field decreased by $0.7 million due to the decline in volumes which resulted in an increase in the per unit cost to $0.25 per Mcfe in 1998 from $0.18 per Mcfe in 1997.
Depreciation, depletion and amortization increased by $6.1 million, or 20%, due to a higher depletion rate and increased production volumes. The higher depletion rate of $1.04 per Mcfe in 1998, compared to $0.93 per Mcfe in 1997, was due, in part, to the Company's emphasis on exploration, which accounted for more than half of the total drilling costs in 1998. The Company's $28.4 million write-down of capitalized costs of oil and gas properties, which was required by the cost ceiling limitation under full-cost accounting, was primarily the result of declines in oil and gas prices during the fourth quarter of 1998. Although the effect of the write-down resulted in a noncash charge to operating profit in 1998, it will positively impact future earnings through lower depletion rates, beginning in the first quarter of 1999. The 1998 year-end write-down reduced amortizable domestic costs by 14%. It is reasonably possible that further decreases in oil and natural gas prices since 1998 year-end may cause the Company to reduce its capitalized costs of oil and gas properties in the near term.
For information related to natural gas commodity price agreements, see Item 7A
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company utilizes various financial instruments and enters into agreements which inherently have some degree of market risk. The primary sources of market risk include fluctuations in commodity prices and interest rate fluctuations.
PRICE FLUCTUATIONS
The Company's results of operations are highly dependent upon prices received for refined products and natural gas production and on the prices paid for crude oil and other refinery feedstocks. The volatility of prices and their effect on the Company's earnings and cash flows are discussed in "Risk Factors and Investment Considerations" in Item 1 and "Business Environment" in Item 7.
From time to time, the Company enters into commodity price agreements to reduce the risk caused by fluctuations in the prices of natural gas in the spot market. During 1998, 1997 and 1996, the Company used such agreements to set the price of 13%, 9% and 30%, respectively, of the natural gas production that it sold in the spot market. In 1998, the Company recognized a gain of $1.3 million ($0.04 per Mcf) from these price agreements. During 1997 and 1996, the effects of natural gas price agreements resulted in losses of $1.6 million ($0.05 per Mcf) and $3.1 million ($0.11 per Mcf), respectively. As of year-end 1998, the Company had remaining price agreements outstanding through March 31, 1999 for 500 MMcf of natural gas production with an average Houston Ship Channel floor price of $2.15 per Mcf and an average ceiling price of $2.59 per Mcf.
INTEREST RATE RISK
Total debt at December 31, 1998 included $211 million of floating-rate debt attributed to the Term Loans and the Revolver and $333 million of fixed-rate debt. As a result, the Company's annual interest cost in 1999 will fluctuate based on short-term interest rates. The impact on annual cash flows of a 10% change in the floating rate (approximately 70 basis points) would be approximately $1.5 million.
At December 31, 1998, the fair market value of the Company's fixed-rate debt approximated its book value of $333 million. The floating-rate debt will mature over varying periods through the end of 2003. Fixed-rate debt of $297 million will mature in 2008, while other fixed-rate notes and obligations will mature over varying periods through 2013.
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, 1998 and 1997, and the related statements of consolidated operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 1998. 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, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998 in conformity with generally accepted accounting principles.
/s/ DELOITTE & TOUCHE LLP
San Antonio, Texas January 29, 1999 (March 25, 1999 as to Note M)
TESORO PETROLEUM CORPORATION
STATEMENTS OF CONSOLIDATED OPERATIONS (IN MILLIONS EXCEPT PER SHARE AMOUNTS)
The accompanying notes are an integral part of these consolidated financial statements.
TESORO PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS (DOLLARS IN MILLIONS 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 MILLIONS)
The accompanying notes are an integral part of these consolidated financial statements.
TESORO PETROLEUM CORPORATION
STATEMENTS OF CONSOLIDATED CASH FLOWS (IN MILLIONS)
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 accompanying Consolidated Financial Statements include the accounts of Tesoro Petroleum Corporation and its subsidiaries (collectively, the "Company" or "Tesoro"). All significant intercompany accounts and transactions have been eliminated. Tesoro is a natural resource company engaged in petroleum refining, distribution and marketing of petroleum products, marine logistics services and the exploration for and production of natural gas and oil.
Use of Estimates and Presentation
Preparation of the Company's Consolidated Financial Statements in conformity with generally accepted accounting principles requires 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 reclassifications have been made to information previously reported to conform to current 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.
Financial Instruments
The carrying amounts of financial instruments, including cash and cash equivalents, accounts receivable, accounts payable and certain accrued liabilities, approximate fair value because of the short maturity of these instruments. The carrying amounts of the Company's long-term debt and other obligations approximate the Company's estimates of the fair value of such items.
Inventories
Inventories are stated at the lower of cost or market. The last-in, first-out ("LIFO") method is used to determine the cost of the Company's refining and marketing inventories of crude oil and U.S. wholesale refined products. The cost of remaining refined product inventories, including fuel at the Company's marine services terminals, is determined principally on the first-in, first-out ("FIFO") method. The carrying value of petroleum inventories is sensitive to volatile market prices. Merchandise and materials and supplies are valued at average cost, not in excess of market value. See Note I.
Property, Plant and Equipment
Additions to property, plant and equipment and major improvements and modifications are capitalized at cost. Depletion of oil and gas producing properties is determined principally by the unit-of-production method and is based on estimated proved recoverable reserves. Depreciation of other property, plant and equipment is generally computed on the straight-line method based upon the estimated useful life of each asset. The weighted average lives range from 8 to 30 years for refining, marketing and pipeline assets, 13 to 15 years for service equipment and marine fleets, and three to seven years for corporate and other assets.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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. Capitalized costs within a cost center, together with estimates of costs for future development, dismantlement and abandonment, are amortized by the unit-of-production method using the proved oil and gas reserves for each cost center. The Company's investment in certain oil and gas properties is excluded from the amortization base until the properties are evaluated. Gain or loss is recognized only on the sale of oil and gas properties involving significant reserves. Proceeds from the sale of insignificant reserves and undeveloped properties are applied to reduce the costs in the cost centers. 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 unevaluated properties included in the cost center. See Notes E and O for write-downs of oil and gas properties in 1998. It is reasonably possible that the present value of future net revenues from estimated production of proved oil and gas reserves could be significantly reduced due to further decreases in oil and natural gas prices since 1998 year-end. This could result in further write-downs of capitalized costs of oil and gas properties in the near term.
Other Assets
The cost over the fair value of net assets acquired (goodwill) is amortized by the straight-line method over 28 years for refining and marketing assets and 20 years for marine services assets.
Debt issue costs are deferred and amortized using the effective interest method over the estimated terms of each instrument.
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 extend the life or increase the capacity of facilities, or expenditures that mitigate or prevent environmental contamination that is yet to occur, 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. Cost estimates are based on the expected timing and extent of remedial actions required by applicable governing agencies, experience gained from similar sites on which environmental assessments or remediation have been completed, and the amount of the Company's anticipated liability considering the proportional liability and financial abilities of other responsible parties. Generally, the timing of these accruals coincides with the completion of a feasibility study or the Company's commitment to a formal plan of action. Estimated liabilities are not discounted to present value.
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 TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
pay to acquire the stock, except for stock options granted under the special incentive compensation which became fully vested in May 1998 (see Note L).
New Accounting Standards
In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standard ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities," which establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. SFAS No. 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. SFAS No. 133 is effective for all quarters of fiscal years beginning after June 15, 1999 and should not be applied retroactively to financial statements of prior periods. From time to time, the Company enters into agreements to reduce commodity price risks. Gains or losses on these hedging activities are recognized when the related physical transactions are recognized as sales or purchases. The Company is evaluating the effects that this new statement will have on its financial condition, results of operations and financial reporting and disclosures.
In 1998, the Company adopted SFAS No. 130, "Reporting Comprehensive Income," which established standards for reporting and displaying comprehensive income and its components in the financial statements. The Company did not have any material amounts which would be reported separately from net income as "other comprehensive income."
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE B -- EARNINGS PER SHARE
Basic earnings per share is determined by dividing net earnings applicable to Common Stock by the weighted average number of common shares outstanding during the period. The Company's calculation of diluted earnings per share takes into account the effect of potentially dilutive shares, principally stock options, outstanding during the period. The assumed conversion of Preferred Stock to 8.75 million shares of Common Stock, or a weighted average of 4.37 million for the year ended December 31, 1998, produced an anti-dilutive result and, in accordance with SFAS No. 128, was not included in the dilutive calculation. Earnings (loss) per share calculations for the years ended December 31, 1998, 1997 and 1996 are presented below (in millions except per share amounts):
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE C -- ACQUISITIONS AND EXPANSIONS
Acquisitions of Hawaii Refinery and Washington Refinery
On May 29, 1998, the Company acquired (the "Hawaii Acquisition") all of the outstanding capital stock of BHP Petroleum Americas Refining Inc. and BHP Petroleum South Pacific Inc. (together, "BHP Hawaii") from BHP Hawaii Inc. and BHP Petroleum Pacific Islands Inc. ("BHP Sellers"), affiliates of The Broken Hill Proprietary Company Limited ("BHP"). The Hawaii Acquisition included a 95,000-barrel per day refinery (the "Hawaii Refinery") and 32 retail gasoline stations in Hawaii. Tesoro and a BHP affiliate entered into a two-year crude supply agreement pursuant to which the BHP affiliate will assist Tesoro in acquiring crude oil feedstocks sourced outside of North America and arrange for the transportation of such crude oil to the Hawaii Refinery. Tesoro paid $252.2 million in cash for the Hawaii Acquisition, including $77.2 million for working capital. In addition, Tesoro issued an unsecured, non-interest bearing, promissory note ("BHP Note") for $50 million. The present value of the BHP Note amounted to $17.4 million, after the accelerated payment provision (see Note D), and was recorded as part of the purchase price.
On August 10, 1998, the Company acquired (the "Washington Acquisition" and together with the Hawaii Acquisition, the "Acquisitions") all of the outstanding stock of Shell Anacortes Refining Company ("Shell Washington"), an affiliate of Shell Oil Company ("Shell"). The Washington Acquisition included a 108,000-barrel per day refinery (the "Washington Refinery") in Anacortes, Washington and related assets. The total cash purchase price for the Washington Acquisition was $280.1 million, including $43.1 million for working capital.
The Acquisitions were accounted for as purchases whereby the purchase prices were allocated to the assets acquired and liabilities assumed based upon their respective fair market values at the dates of acquisition. Under purchase accounting, financial results of the Acquisitions have been included in Tesoro's consolidated financial statements since the dates of acquisition. Had these results been included in Tesoro's results since January 1, 1997, and the Refinancing and Offerings completed (as defined in Note D below), Tesoro's consolidated results for the years ended December 31, 1998 and 1997, on a pro forma basis, would have been as follows (in millions except per share amounts):
The 1998 extraordinary loss on extinguishment of debt amounted to $0.14 per share (basic and diluted) on a proforma basis.
See Note D for information related to financing the Acquisitions and Note M for related environmental matters.
Alaska Refining and Marketing
In October 1997, the Company completed an expansion of its Alaska refinery hydrocracker unit which enabled the Company to increase its jet fuel production. The expansion, together with the addition of a new, high-yield jet fuel hydrocracker catalyst, was completed at a cost of approximately $19 million.
In December 1997, the Company purchased the Union 76 marketing assets in Southeast Alaska, consisting of one terminal, two retail stations and the rights to use the Union 76 trademark within Alaska.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Marine Services
In February 1996, the Company purchased 100% of the capital stock of Coastwide Energy Services, Inc. ("Coastwide"). The consideration included approximately 1.4 million shares of Tesoro's Common Stock and $7.7 million in cash. The market price of Tesoro's Common Stock was $9.00 per share at closing of this transaction. Subsequent to the acquisition, Tesoro repaid approximately $4.5 million of Coastwide's outstanding debt. The acquired operations provide logistical support services and distribute petroleum products to the offshore oil and gas industry in the Gulf of Mexico. 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.
Exploration and Production
In September 1998, the Company purchased oil and gas assets for $10 million, which included working interests in producing wells and undeveloped acreage in the Morrow gas play located in Wheeler County in the Texas Panhandle, together with undeveloped acres in prospective areas of the onshore Texas Gulf Coast. In August 1998, the Company purchased a working interest in the Stiles Ranch Field, located in Wheeler County in the Texas Panhandle, for $8 million in cash plus the conveyance of a working interest in an undeveloped prospect owned by the Company in South Texas. Also in 1998, the Company acquired additional undeveloped acreage for $6 million, located primarily in the onshore Gulf Coast of Texas and in Wheeler County in the Texas Panhandle.
In July 1997, the Company purchased the interests held by its former joint venture participant in the then existing two contract blocks in southern Bolivia, consisting of a 25% interest in Block 18 and a 27.4% interest in Block 20. The purchase price was approximately $20 million, which included $11.9 million for proved reserves and $3.3 million for undeveloped acreage with the remainder for working capital and assumption of certain liabilities.
In the U.S., the Company purchased proved and unproved properties totaling $22 million during 1997. These purchases included interests in fields in southern Louisiana, South Texas and East Texas. During 1996, the Company acquired proved and unproved properties totaling $25.7 million in South Texas and East Texas.
For further information related to exploration and production activities, see Note O.
NOTE D -- CAPITALIZATION
Credit Facility
In conjunction with closing the Hawaii Acquisition (see Note C) on May 29, 1998, Tesoro refinanced substantially all of its then-existing indebtedness ("Refinancing"). The Company recorded an extraordinary loss on early extinguishment of debt of approximately $7.0 million pretax ($4.4 million aftertax, or $0.15 per basic and diluted share) for the Refinancing during the second quarter of 1998.
The total amount of funds required by Tesoro to complete the Hawaii Acquisition and the Refinancing, to pay related fees and expenses and for general corporate purposes was financed through a secured credit facility ("Interim Credit Facility"), which replaced the Company's previous corporate revolving credit agreement. In the third quarter of 1998, the Company refinanced all borrowings under the Interim Credit Facility with net proceeds from the Offerings (as defined below) and borrowings under the Senior Credit Facility (as defined below).
On July 2, 1998, and in connection with the Notes Offering (defined below) and the Washington Acquisition, the Company entered into a senior credit facility ("Senior Credit Facility") in the amount of $500 million. The Senior Credit Facility is comprised of term loan facilities aggregating $200 million (the "Tranche A Term Loans" and the "Tranche B Term Loan," collectively, the "Term Loans") and a
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
$300 million revolving credit and letter of credit facility ("Revolver"). The Senior Credit Facility is guaranteed by substantially all of the Company's active direct and indirect subsidiaries ("Guarantors") and is secured by substantially all of the domestic assets of the Company and each of the Guarantors. At December 31, 1998, the Company had outstanding borrowings of $149.5 million under the Term Loans and $61.2 million under the Revolver. Outstanding letters of credit totaled $14 million at December 31, 1998. Unused availability under the Senior Credit Facility and Term Loans was approximately $275 million at December 31, 1998. On January 4, 1999, the final $50 million tranche under the Term Loans was borrowed and used to reduce borrowings under the Revolver. The Revolver terminates on July 2, 2001, while the Term Loans mature in varying quarterly installments through 2003. Maturities under the Tranche A Term Loans, including the final $50 million borrowed in 1999, aggregate to $10.0 million, $22.5 million, $25.0 million, $27.5 million and $15.0 million in 1999, 2000, 2001, 2002 and 2003, respectively. Maturities of outstanding borrowings under the Tranche B Term Loan equal $1 million annually in 1999 through 2002 and $95.5 million in 2003.
The Senior Credit Facility requires the Company to maintain specified levels of consolidated leverage and interest coverage and contains other covenants and restrictions customary in credit arrangements of this kind. The Company was in compliance with these covenants at December 31, 1998. Future compliance with financial covenants under the Senior Credit Facility is primarily dependent on the Company's cash flows and levels of borrowings under the Revolver. Based on market conditions in the first quarter of 1999, including depressed natural gas prices and downturn in refinery margins, continued compliance with such covenants is not assured. If the Company is not able to continue to comply with its financial covenants, it will be required to seek waivers or amendments from its lenders. If such an event occurs, management of the Company believes that it will be able to obtain waivers and/or negotiate terms and conditions with its lenders under the Senior Credit Facility which will allow the Company to adequately finance its operations.
The Revolver and the Tranche A Term Loans bear interest, at the Company's election, at either the Base Rate (as defined in the Senior Credit Facility) plus a margin ranging from 0.00% to 0.625% or the Eurodollar Rate (as defined in the Senior Credit Facility) plus a margin ranging from 1.125% to 2.125%. The Tranche B Term Loan bears interest, at the Company's election, at either the Base Rate plus a margin ranging from 0.50% to 0.625% or the Eurodollar Rate plus a margin ranging from 2.00% to 2.125%. At December 31, 1998, the interest rates were 7.75% on the Revolver, 6.315% on the Tranche A Term Loans and 7.19% on the Tranche B Term Loan.
The terms of the Senior Credit Facility allow for payment of cash dividends on the Company's Common Stock not to exceed an aggregate of $10 million in any year and also allow for payment of required dividends on its 7.25% Mandatorily Convertible Preferred Stock.
Provisions of the Senior Credit Facility require prepayments to the Term Loans, with certain defined exceptions, in an amount equal to: (i) 100% of the net proceeds of certain incurred indebtedness; (ii) 100% of the net proceeds received by the Company and its subsidiaries (other than certain net proceeds reinvested in the business of the Company or its subsidiaries) from the disposition of any assets, including proceeds from the sale of stock of the Company's subsidiaries; and (iii) a percentage of excess cash flow, as defined, depending on certain credit statistics. No prepayments were required for 1998.
Senior Subordinated Notes
On July 2, 1998, concurrently with the syndication of the Senior Credit Facility, the Company issued $300 million aggregate principal amount of 9% senior subordinated notes due 2008 through a private offering ("Notes Offering"). Each $1,000 principal amount of its unregistered and outstanding senior subordinated notes due 2008 was exchanged for $1,000 principal amount of the Company's registered 9% Senior Subordinated Notes due 2008, Series B ("Senior Subordinated Notes") in September 1998. The Senior Subordinated Notes have a ten-year maturity without sinking fund requirements and are subject to optional redemption by the Company after five years at declining premiums. The indenture ("Indenture") for the TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Senior Subordinated Notes contains covenants and restrictions which are customary for notes of this nature. The restrictions under the Indenture are less restrictive than those in the Senior Credit Facility. To the extent the Company's fixed charge coverage ratio, as defined in the Indenture, allows for the incurrence of additional indebtedness, the Company will be allowed to pay cash dividends on Common Stock. The effective interest rate on the Senior Subordinated Notes is 9.16%, after giving effect to the discount at the date of issue.
Common Stock and Preferred Stock
On May 14, 1998, the Company filed a universal shelf registration statement ("Shelf Registration") for $600 million of debt or equity securities for acquisitions or general corporate purposes. The Company offered Premium Income Equity Securities ("PIES") and Common Stock (collectively, the "Equity Offerings" and together with the Notes Offering, the "Offerings") from the Shelf Registration to provide partial funding for the Acquisitions discussed in Note C. On July 1, 1998, the Company issued 9,000,000 PIES, representing fractional interests in the Company's 7.25% Mandatorily Convertible Preferred Stock ("Preferred Stock"), with gross proceeds of approximately $143.4 million, and 5,000,000 shares of Common Stock, with gross proceeds of $79.7 million. Upon exercise of the over-allotment options granted to the underwriters of the Equity Offerings, on July 8, 1998, the Company issued 1,350,000 PIES with gross proceeds of $21.5 million and 750,000 shares of Common Stock with gross proceeds of $11.9 million. Holders of PIES are entitled to receive a cash dividend. The PIES will automatically convert into shares of Common Stock on July 1, 2001, at a rate based upon a formula dependent upon the market price of Common Stock. Before July 1, 2001, each PIES is convertible, at the option of the holder thereof, into 0.8455 shares of Common Stock, subject to adjustment in certain events, such as Common Stock splits and stock dividends.
In connection with filing the Shelf Registration in May 1998, the Company's Board of Directors approved terminating a repurchase program for Tesoro's Common Stock that was initiated in May 1997. Under that program in 1997, the Company used cash flows of $3.7 million to repurchase 236,800 shares of Common Stock.
For information relating to stock-based compensation and Common Stock reserved for exercise of options and conversion of Preferred Stock, see Note L.
BHP Note
In connection with the Hawaii Acquisition (Note C), Tesoro issued an unsecured, non-interest bearing, promissory note ("BHP Note") for the purchase in the amount of $50 million, payable in five equal annual installments of $10 million each, beginning in 2009. The BHP Note provides for early payments to the extent of one-half of the amount by which earnings from the Hawaii Acquisition, before interest expense, income taxes and depreciation and amortization, as specified in the BHP Note, exceed $50 million in any calendar year. Based on 1998 earnings from the Hawaii Acquisition, an early principal payment will be made on the BHP Note in 1999. The present value of the BHP Note, discounted at 10% and including the effect of the early principal payment, was recorded as part of the purchase price of the Hawaii Acquisition. The future effects of any additional accelerated payments under the BHP Note, if required, would be accounted for as additional cost of the acquired assets and amortized over the remaining life of the assets.
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 was obligated to make variable monthly payments to the State through December 2001 based on a per barrel charge on the volume of feedstock processed through the Company's Alaska refinery crude unit. In 1997, based on a per barrel throughput charge of 24 cents, the Company's variable payment to the State totaled $4.4 million. In 1998, based on a per barrel throughput charge of 30 cents, the Company's variable payments to the State totaled TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
$3.0 million. The per barrel charge increased to 30 cents in 1998 with one cent annual incremental increases thereafter through 2001. The Agreement obligated the Company to pay the State $60 million in January 2002; provided, however, that such payment could be deferred indefinitely at the Company's option, by continuing the variable monthly payments to the State beginning at 34 cents per barrel for 2002 and increasing one cent per barrel annually thereafter. Under the Agreement, variable monthly payments made after January 2002 would 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%.
Beginning June 1, 1998, the State released the Company from all payment obligations, and all mortgages, liens and security interests in connection therewith, under the Agreement in exchange for a payment of $66.1 million. The Company is only obligated to continue payment of the per barrel throughput charge through 2001 with respect to barrels of feedstock processed at the refinery which exceed 50,000 barrels per day on a monthly basis, subject to available credits (as defined in the Agreement) for amounts by which the barrels of feedstock processed average less than 50,000 barrels per day on a monthly basis.
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, 1998, the Company's remaining obligation is to pay the DOE $7.9 million, plus interest at 6%, over the next four years.
Hydrocracker Unit and Vacuum Unit Loans
In October 1997, the National Bank of Alaska ("NBA") and the Alaska Industrial Development and Export Authority ("AIDEA"), under a loan agreement ("Hydrocracker Loan") entered into between the Company and NBA, provided a $16.2 million loan to the Company towards the cost of its Alaska refinery hydrocracker expansion (see Note C). In 1994, NBA and the AIDEA provided a $15 million loan to the Company towards the cost of the Company's Alaska refinery vacuum unit ("Vacuum Unit Loan"). The Hydrocracker Unit Loan and Vacuum Unit Loan were repaid and terminated on May 29, 1998, in connection with the Refinancing described above.
Capital Leases
Capital leases are primarily for tugs and barges used in transportation of petroleum products within Hawaii. At December 31, 1998, the cost of capital leases included in fixed assets was $9.3 million and the related accumulated amortization was $0.9 million. Capital lease obligations included in long-term debt totaled $9.8 million and $1.6 million at December 31, 1998 and 1997, respectively.
1996 Repurchase of Debentures and Notes
In November 1996, the Company fully redeemed its two public debt issues, totaling approximately $74 million, at a price equal to 100% of the principal amount, plus accrued interest to the redemption date. The redemption of debt was comprised of $44.1 million of outstanding 13% Exchange Notes and $30 million of outstanding 12 3/4% Subordinated Debentures. 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.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Summary Table of Long-Term Debt and Other Obligations
Long-term debt and other obligations at December 31, 1998 and 1997 consisted of the following (in millions):
At December 31, 1998, aggregate maturities of outstanding long-term debt and other obligations, including the Term Loans and Revolver, for each of the five years following December 31, 1998 were as follows: 1999 - $12.5 million; 2000 - $14.6 million; 2001 - $78.5 million; 2002 - $18.4 million; and 2003 - $104.1 million.
NOTE E -- OPERATING SEGMENTS
The Company's revenues are derived from three operating segments: Refining and Marketing, Marine Services and Exploration and Production. Management has identified these segments for managing operations and investing activities. The segments are organized primarily by petroleum industry classification as upstream (Exploration and Production) and downstream (Refining and Marketing, and Marine Services). These classifications represent significantly different activities with respect to investment, asset development, asset valuations, production, maintenance, supply and market distribution. The downstream businesses are organized into two operating segments representing (i) the manufacturing and marketing of refined products and (ii) product distribution and logistics services provided to the marine industry.
Refining and Marketing
Refining and Marketing operates three petroleum refineries located in Alaska, Hawaii and Washington, which manufacture gasoline and gasoline components, 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, the Pacific Northwest, Hawaii and American Samoa. In addition, Refining and Marketing markets gasoline, other petroleum products and convenience store items through Company-operated retail stations in Alaska and Hawaii. Refining and Marketing also markets petroleum products through branded and unbranded stations located in Alaska, Hawaii, American Samoa and the Pacific Northwest. Revenues from export sales, primarily to Far East markets, amounted to $35.5 million, $16.1 million and $22.0 million in 1998, 1997 and 1996, respectively. The Company at times resells previously purchased crude oil, sales of which amounted to $29.9 million, $44.4 million and $93.8 million in 1998, 1997 and 1996, respectively. See Note C for information related to Acquisitions in this segment during 1998.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Marine Services
The Marine Services segment markets and distributes petroleum products, water, drilling mud, and other supplies and services primarily to the marine and offshore exploration and production industries operating in the Gulf of Mexico. This segment currently operates through terminals along the Texas and Louisiana Gulf Coast and on the U.S. West Coast.
Exploration and Production
The Exploration and Production segment is engaged in the exploration, production and development of natural gas and oil in Texas, Louisiana and Bolivia. This segment also includes the transportation of natural gas, including the Company's production, to common carrier pipelines in South Texas. In Bolivia, the Company operates under contracts with the Bolivian government to explore for and produce hydrocarbons. The Company's Bolivian natural gas production is sold under contract to the Bolivian government for export to Argentina. The majority of the Company's Bolivian natural gas and oil reserves are shut-in awaiting access to gas-consuming markets. A new, third-party pipeline that will link Bolivia's gas reserves with markets in Brazil is expected to begin operations in the second quarter of 1999.
In Exploration and Production, segment operating profit in 1998 included fourth quarter write-downs of oil and gas properties totaling $68.3 million in 1998 ($28.4 million in the U.S. and $39.9 million in Bolivia) and other income of $21.3 million in the second quarter representing funds received from an operator that were no longer needed as a contingency reserve for litigation. Segment operating profit in 1997 included income of $1.8 million for severance tax refunds and $2.2 million related to the collection of a receivable for prior years' Bolivian production. Segment operating profit in 1996 included $60 million of other income from termination of a natural gas contract and $5 million from retroactive severance tax refunds. In 1996, Exploration and Production's segment operating profit also included $24.6 million from the excess of natural gas contract prices over spot market prices (see Note F).
Other
Segment operating profit includes those revenues and expenses that are directly attributable to management of the respective segment. For the years presented, revenues were generated from sales to external customers, and intersegment revenues were not significant. Income taxes, interest and financing costs, interest income and corporate general and administrative expenses are not included in determining segment operating profit. Corporate and unallocated costs in 1998 included $19.9 million for special incentive compensation (see Note L) and $33.0 million from interest and financing costs primarily related to the Acquisitions (see Notes C and D).
EBITDA represents earnings before extraordinary items, interest and financing costs expense, income taxes, write-downs of oil and gas properties and depreciation, depletion and amortization. While not purporting to reflect any measure of the Company's operations or cash flows, EBITDA is presented for additional analysis. Operating segment EBITDA is equal to segment operating profit before depreciation, depletion and amortization related to each segment.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Identifiable assets are those assets utilized by the segment. Corporate assets are principally cash and other assets that are not directly associated with the operations of a business segment. Segment information for the three years ended December 31, 1998 is as follows (in millions):
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
- --------------- (a) Including 1998 write-downs of oil and gas properties of $28.4 million in the U.S. and $39.9 million in Bolivia.
(b) Excluding 1998 Acquisitions of $536.5 million.
NOTE F -- OTHER INCOME AND EXPENSE
Other income and other expense for the years ended December 31, 1998, 1997 and 1996 included the following (in millions):
In 1998, the Exploration and Production segment received $21.3 million from an operator in the Bob West Field, representing funds that were no longer needed as a contingency reserve for litigation.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
In 1996, the Company settled all claims and disputes with Tennessee Gas Pipeline Company ("Tennessee Gas") and agreed to terminate the Tennessee Gas contract effective October 1, 1996. The 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 in 1996. The severance taxes were subsequently received in 1997.
In 1998, other expenses included $19.9 million for special incentive compensation earned when the market price of the Company's stock achieved a certain performance target (see Note L), of which $7.9 million was included in other operating costs and expenses since it related to the operating segments.
NOTE G -- INCOME TAXES
The income tax provision (benefit) for the years ended December 31, 1998, 1997 and 1996 included the following (in millions):
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 liabilities and assets at December 31, 1998 and 1997 are summarized as follows (in millions):
In 1998, the Acquisitions described in Note C resulted in net deferred federal tax liabilities of $46.7 million and net deferred state liabilities of $11.1 million as of the dates of acquisition.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following tables set forth domestic and foreign components of the Company's results of operations (in millions) and a reconciliation of the normal statutory federal income tax rate with the Company's effective tax rate (percent):
At December 31, 1998, the Company had approximately $3.5 million of investment tax credits and employee stock ownership credits available for carryover to subsequent years which, if not used, will expire in the years 1999 through 2006. Additionally, at December 31, 1998, the Company had approximately $1.3 million of alternative minimum tax credit carryforwards, with no expiration dates, to offset future regular tax liabilities.
NOTE H -- RECEIVABLES
Concentrations of credit risk with respect to accounts receivable are limited, due to the large number of customers comprising the Company's customer base and their dispersion across the Company's industry segments and geographic areas of operations. The Company performs ongoing credit evaluations of its customers' financial condition and in certain circumstances requires letters of credit or other collateral arrangements. The Company's allowance for doubtful accounts is reflected as a reduction of receivables in the Consolidated Balance Sheets and amounted to $1.7 million and $1.4 million at December 31, 1998 and 1997, respectively.
NOTE I -- INVENTORIES
Components of inventories at December 31, 1998 and 1997 were as follows (in millions):
At December 31, 1998 and 1997, inventories valued using LIFO were lower than replacement cost by approximately $3.3 million and $4.4 million, respectively.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE J -- ACCRUED LIABILITIES
The Company's current accrued liabilities and noncurrent other liabilities as shown in the Consolidated Balance Sheets at December 31, 1998 and 1997 included the following (in millions):
NOTE K -- BENEFIT PLANS
Pension Benefits and Other Postretirement Benefits
The Company sponsors multiple defined benefit pension plans which consist of a retirement plan, executive security plans and a non-employee director retirement plan.
The Company provides a qualified noncontributory retirement plan ("Retirement Plan") for all eligible employees. 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. Retirement plan assets are primarily comprised of common stock and bond funds. As a result of the Washington Acquisition, the Retirement Plan's benefit obligation increased by $9.1 million during 1998.
The Company's executive security plans ("ESP Plans") provide executive officers and other key personnel with supplemental death or retirement plans. Such benefits are provided by two nonqualified, noncontributory plans and are based on years of service and compensation. The Company makes contributions to one plan based upon estimated requirements. Assets of the funded plan consist of a group annuity contract.
The Company had previously established an unfunded non-employee director retirement plan ("Director Retirement Plan") which provided eligible directors retirement payments upon meeting certain age or other requirements. However, in March 1997, the Board of Directors elected to freeze the Director Retirement Plan and transfer accrued benefits of current directors to the Tesoro Petroleum Corporation Board of Directors Phantom Stock Plan (see Note L). After the amendment and transfer, only those retired directors or beneficiaries who had begun to receive benefits remained participants in the Director Retirement Plan.
The projected benefit obligation, accumulated benefit obligation, and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets were $85.7 million, $66.2 million and $59.1 million, respectively as of December 31, 1998, and $54.6 million, $45.9 million, and $51.0 million, respectively, as of December 31, 1997.
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 provided to qualified dependents of
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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. As a result of the Acquisitions, the postretirement health and life insurance benefit obligations increased by $7.4 million during 1998.
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care and life insurance plans. A one-percentage-point change in assumed health care cost trend rates could have the following effects (in millions):
Financial information related to the Company's pension plans and other postretirement benefits is presented below (in millions except percentages):
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
For measurement purposes, the weighted average annual assumed rate of increase in the per capita cost of covered health care benefits was assumed to be 7.5% for 1998, decreasing gradually to 5% by the year 2010 and remaining level thereafter.
Thrift Plan
The Company sponsors an employee thrift plan ("Thrift Plan") which provides for contributions by eligible employees into designated investment funds with a matching contribution by the Company. Employees may contribute a portion 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 September 1, 1998, the Thrift Plan was amended to change the Company's 100% matching contribution, from a maximum of 4% to 6% of the employee's eligible contribution, with at least 50% of the Company's matching contribution invested in Common Stock of the Company. In addition, the maximum employee contribution changed from 10% to 15%. The Company's contributions amounted to $1.7 million, $1.2 million and $0.8 million during 1998, 1997 and 1996, respectively.
NOTE L -- STOCK-BASED COMPENSATION
Incentive Stock Plans
The Company has two employee incentive stock plans, the Amended and Restated Executive Long-Term Incentive Plan ("1993 Plan") and Amended Incentive Stock Plan of 1982 ("1982 Plan"), and the 1995 Non-Employee Director Stock Option Plan ("1995 Plan") (collectively, the "Plans").
Shares of Common Stock may be granted under the 1993 Plan in a variety of forms, including restricted stock, incentive stock options, nonqualified stock options, stock appreciation rights and performance share and performance unit awards. In 1998, the aggregate number of shares of Common Stock which can be granted under the 1993 Plan was increased from 2,650,000 to 4,250,000. Stock options may be granted at exercise prices not less than the fair market value on the date the options are granted. The options granted generally become exercisable after one year in 20%, 25% or 33% increments per year and expire ten years from the date
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
of grant. The 1993 Plan will expire, unless earlier terminated, as to the issuance of awards in the year 2003. At December 31, 1998, the Company had 893,880 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. These automatic, non-discretionary stock options are granted at an exercise price equal to the fair market value per share of the Company's Common Stock as of the date of grant. Under the 1995 Plan, each person serving as a non-employee director on February 23, 1995, or elected thereafter, initially receives an option to purchase 5,000 shares of Common Stock. Thereafter, each non-employee director, while the 1995 Plan is in effect and shares are available to grant, will be granted an option to purchase 1,000 shares of Common Stock on the next day after each annual meeting of the Company's stockholders but not later than June 1, if no annual meeting is held. The term of each option is ten years, and an option first becomes exercisable six months after the date of grant. The 1995 Plan will terminate as to issuance of stock options in February 2005. At December 31, 1998, the Company had 62,000 options outstanding and 71,000 shares available for future grants under the 1995 Plan.
A summary of stock option activity in the Plans is set forth below (thousands of shares):
At December 31, 1998, 1997 and 1996, exercisable stock options totaled 1.4 million, 0.7 million and 0.4 million, respectively.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following table summarizes information about stock options outstanding under the Plans at December 31, 1998 (thousands of shares):
Phantom Stock Agreement and Phantom Stock Plan
In 1997, the Compensation Committee of the Board of Directors granted 175,000 phantom stock options to an executive officer of the Company at 100% of the fair market value of the Company's Common Stock on the grant date, or $16.9844 per share. These phantom stock options vest in 15% increments in each of the first three years and the remaining 55% increment vests in the fourth year. At December 31, 1998, 26,250 of these phantom stock options were exercisable. Upon exercise, the executive officer would be entitled to receive in cash the difference between the fair market value of the Common Stock on the date of the phantom stock option grant and the fair market value of Common Stock on the date of exercise. At the discretion of the Compensation Committee, these phantom stock options may be converted to traditional stock options under the 1993 Plan.
To more closely align director compensation with shareholders' interests, in March 1997, the lump-sum accrued benefit of each of the current non-employee directors was transferred from the Director Retirement Plan (see Note K) into an account ("Account") in the Company's Board of Directors Deferred Phantom Stock Plan ("Phantom Stock Plan"). Under the Phantom Stock Plan, a yearly credit of $7,250 (prorated to $6,042 for 1997) is made to the Account of each director in units, based upon the closing market price of the Company's Common Stock on the date of credit. In addition, a director may elect to have the value of his cash retainer fee deposited quarterly into the Account in units. The value of each Account balance, which is a function of the amount, if any, by which the market value of the Company's Common stock changes, is payable in cash at retirement, death, disability or termination, if vested. In 1998, the Company credited expense for approximately $110,000 related to the Phantom Stock Plan due to the net depreciation in the market price of the Company's Common Stock. In 1997, the Company recorded expense of approximately $127,000 due to the increase in the market price of the Company's Common Stock.
Incentive Compensation
In October 1998, the Company's Board of Directors unanimously approved the 1998 Performance Incentive Compensation Plan ("1998 Performance Plan"), which is intended to advance the best interests of the Company and its stockholders by directly targeting Company performance to align with the ninetieth percentile historical stock-price growth rate for the Company's peer group. In addition, the 1998 Performance Plan will provide the Company's employees with additional compensation, contingent upon achievement of the targeted objectives, thereby encouraging them to continue in the employ of the Company. Under the 1998 Performance Plan, targeted objectives are comprised of the fair market value of the Company's Common Stock equaling or exceeding an average of $35 per share ("First Performance Target") and $45 per share ("Second Performance Target") on any 20 consecutive trading days during a period commencing on October 1, 1998 and ending on the earlier of September 30, 2002, or the date on which the Second Performance Target is achieved ("Performance Period"). The 1998 Performance Plan has several tiers of
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
awards, with the award generally determined by job level. Most eligible employees have contingent cash bonus opportunities of 25% of their annual "basic compensation" (as defined in the 1998 Performance Plan) and three executive officers have contingent awards totaling 655,000 shares of phantom stock which will be payable solely in cash. Upon achievement of the First Performance Target, one-fourth of the contingent award will be earned, with payout deferred until the end of the Performance Period. The remaining 75% will be earned only upon achievement of the Second Performance Target, with payout occurring 30 days thereafter. Employees will need to have at least one year of regular, full-time service at the time the Performance Period ends in order to be eligible for a payment. The Company estimates that it will incur aftertax costs of approximately 1% of the total aggregate increase in shareholder value if the First Performance Target is reached and will incur an additional 2% aftertax charge if the Second Performance Target is reached.
Under a previous special incentive compensation strategy, approved unanimously by the Company's Board of Director in June 1996, eligible employees were provided with incentives to achieve a significant increase in the market price of the Company's Common Stock. Under this strategy, awards were earned when the market price of the Company's Common Stock reached an average price per share of $20 or higher over 20 consecutive trading days after June 30, 1997 and before December 31, 1998 ("Performance Target"). In connection with this strategy, certain executives were granted, from the Company's 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 vested upon achieving the Performance Target in May of 1998. Non-executive employees earned cash bonuses equal to 25% of their individual payroll amounts for the previous twelve complete months. In May 1998, the Company recorded a pretax charge of approximately $20 million ($10 million related to the noncash vesting of restricted stock awards and stock options and $10 million for cash bonuses) for this strategy. On an aftertax basis, the charge totaled approximately $13 million, representing approximately 5% of the total aggregate increase in shareholder value since approval of the special incentive strategy in 1996.
Pro Forma Information
The Company applies APB No. 25 and related interpretations in accounting for its stock-based compensation. Had compensation cost been determined based on the fair value at the grant dates for awards in accordance with SFAS No. 123, "Accounting for Stock-Based Compensation," the Company's pro forma results in 1998, 1997 and 1996 would have been a net loss of approximately $22.3 million ($0.96 per basic and diluted share), net earnings of $28.5 million ($1.08 per basic share, $1.06 per diluted share) and net earnings of $72.6 million ($2.79 per basic share, $2.74 per diluted share), respectively. The fair value of each option grant was estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions: expected volatility of 49%, 32% and 30%; risk free interest rates of 4.7%, 6.7% and 6.6%; expected lives of seven years; and no dividend yields for 1998, 1997 and 1996, respectively. The estimated average fair value per share of options granted during 1998, 1997 and 1996 were $7.85, $5.96 and $4.26, respectively. The fair value of phantom stock awards in 1998 was $0.82 per share and the fair value of restricted stock awards in 1996 was $0.95 per share.
Shares Reserved
Shares of unissued Common Stock reserved for the Plans were 3,928,466 at December 31, 1998. In addition, at December 31, 1998, 8,750,925 shares of unissued Common Stock were reserved for the conversion of Preferred Stock (see Note D).
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE M -- COMMITMENTS AND CONTINGENCIES
Operating Leases
The Company has various noncancellable operating leases related to buildings, equipment, property and other facilities. These long-term leases have remaining primary terms generally up to ten years, with terms of certain rights-of-way extending up to 34 years, and generally contain multiple renewal options. Future minimum annual lease payments as of December 31, 1998, for operating leases having initial or remaining noncancelable lease terms in excess of one year, excluding marine charters, were as follows (in millions):
In addition to the long-term lease commitments above, the Company has leases for two vessels that are primarily used to transport crude oil and refined products to and from the Company's refineries. At December 31, 1998, future minimum annual lease payments remaining for these two vessels, which include operating costs, are approximately $28 million for 1999 and $16 million for 2000. Operating costs related to these vessels, which may vary from year to year, comprised approximately 30% of the total minimum payments during 1998. The Company also enters into various month-to-month and other short-term rentals, including three charters for vessels primarily used to transport refined products from the Company's refineries to the Far East and South Pacific. The Company also leases tugs and barges for Hawaii operations under capital leases (see Note D). Under these leases, the Company pays operating costs, including personnel, repairs, maintenance and dry-docking, estimated at $9 million for 1999.
Total rental expense for short-term and long-term leases, excluding marine charters, amounted to approximately $20 million, $11 million and $12 million for 1998, 1997 and 1996, respectively. In addition, expenses related to charters of marine vessels were $34 million in 1998 and 1997 and $30 million in 1996.
In November 1998, the Company entered into a lease agreement to become the sole tenant of an office building to be constructed in 1999. Upon substantial completion of the building, annual base lease commitments will range from $1.8 million to $2.4 million over a 15-year lease term.
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 the Environmental Protection Agency ("EPA") regarding a waste disposal site near Abbeville, Louisiana and the Casmalia Disposal Site in Santa Barbara County, California. The Company has been named a potentially responsible party ("PRP") under the Federal Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA" or "Superfund") at both sites. Although the Superfund law might impose joint and several liability upon each party at the sites, the extent of the Company's allocated financial contribution for cleanup is expected to be de minimis based upon the number of companies, volumes of waste involved and total estimated costs to close each site. The Company believes, based on these considerations and discussions with the EPA, that its liability at the TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Abbeville site will not exceed $25,000. The Company believes that its liability at the Casmalia Site is de minimis based on a 1999 notification from the EPA indicating that the Company's liability will not exceed $125,000.
The Company is currently involved with a waste water disposal site in Redwood City, California. On December 18, 1998, the Port of Redwood City filed suit against numerous defendants, including the Company, for contribution pursuant to CERCLA and the Resource Conservation and Recovery Act ("RCRA"). The Company has negotiated with the Port of Redwood City and expects to settle its liability in early 1999. The Company believes that it is not subject to joint and several liability for the cleanup of the site and that its liability will not exceed $40,000.
In connection with the Hawaii Acquisition discussed in Note C, the BHP Sellers and the Company have executed a separate environmental agreement, whereby the BHP Sellers have indemnified the Company for environmental costs arising out of conditions which existed at or prior to closing. This indemnification is subject to a maximum limit of $9.5 million and expires after a period of ten years. Under the environmental agreement, the first $5.0 million of these liabilities will be the responsibility of the BHP Sellers and the next $6.0 million will be shared on the basis of 75% by the BHP Sellers and 25% by the Company. Certain environmental claims arising out of prior operations will not be subject to the $9.5 million limit or the ten-year time limit.
Under the agreement related to the Washington Acquisition discussed in Note C, Shell Refining Holding Company, a subsidiary of Shell (the "Shell Seller"), generally has agreed to indemnify the Company for environmental liabilities at the Washington Refinery arising out of conditions which existed at or prior to the closing date and identified by the Company prior to August 1, 2001. The Company is responsible for environmental costs up to the first $0.5 million each year, after which the Shell Seller will be responsible for annual environmental costs up to $1.0 million. Annual costs greater than $1.0 million will be shared equally between the Company and the Shell Seller, subject to an aggregate maximum of $5.0 million and a ten-year term.
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, 1998, the Company's accruals for environmental expenses amounted to $9.3 million. Based on currently available information, including the participation of other parties or former owners in remediation actions, the Company believes these accruals are adequate.
To comply with environmental laws and regulations, the Company anticipates that it will make capital improvements of approximately $12 million in 1999 and $5 million in 2000. In addition, capital expenditures for alternative secondary containment systems for existing storage tank facilities are estimated to be $2 million in 1999 and $1 million in 2000, with a remaining $4 million expected to be spent by 2002.
Conditions that require additional expenditures may exist for various Company sites, including, but not limited to, the Company's refineries, retail gasoline stations (operating and closed locations) and petroleum product terminals, and for compliance with the Clean Air Act and other state and federal regulations. The amount of such future expenditures cannot currently be determined by the Company.
Other
On October 1, 1998, the Attorney General for the State of Hawaii filed a lawsuit in the U.S. District Court for the District of Hawaii against thirteen oil companies, including Tesoro Petroleum Corporation and Tesoro Hawaii Corporation, alleging anti-competitive marketing practices in violation of federal and state anti-trust laws, and seeking injunctive relief and compensatory and treble damages and civil penalties against all defendants in an amount in excess of $500 million. On March 25, 1999, the Attorney General filed an amended complaint with the U.S. District Court seeking damages against all defendants for such alleged TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
anti-competitive marketing practices in an amount in excess of $1.3 billion. The Company believes that it has not engaged in any anti-competitive activities and will defend this litigation vigorously. This proceeding is subject to the indemnity provision of the stock sale agreement between the BHP Sellers and the Company which provides for indemnification in excess of $2 million and not to exceed $65 million.
NOTE N -- QUARTERLY FINANCIAL DATA (UNAUDITED)
The 1998 second quarter included pretax other income of $21.3 million for receipt of funds from an operator and a pretax charge of $19.9 million for special incentive compensation (Note L). In addition, an aftertax extraordinary loss of $4.4 million was recorded in the 1998 second quarter for the early extinguishment of debt (Note D). During the 1998 fourth quarter, pretax write-downs of oil and gas properties totaled $68.3 million (Notes A and O). Earnings per share in the 1998 third and fourth quarters were reduced by the effects of dividends on Preferred Stock issued in July 1998.
Other income in 1997 included severance tax refunds of $1.6 million and $0.2 million in the first and second quarters, respectively. Other income of $2.2 million related to the collection of a Bolivian receivable for prior years' production was recorded in the 1997 second quarter.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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, excluding amounts related to its U.S. natural gas transportation operations. Other information pertinent to the Exploration and Production segment is contained in Notes C and E.
Capitalized Costs Relating to Oil and Gas Producing Activities
The Company's investment in oil and gas properties included $25 million in unevaluated properties, primarily undeveloped leasehold costs and seismic costs, which have been excluded from the amortization base at December 31, 1998. Of this amount, $14 million, $8 million and $3 million of such costs were incurred in 1998, 1997 and 1996, respectively. The Company anticipates that the majority of these costs will be included in the amortization base during the next three years.
During the fourth quarter of 1998, the Company wrote down its capitalized costs of oil and gas properties by $68.3 million ($28.4 million in U.S. and $39.9 million in Bolivia). These write-downs, which were required by the cost ceiling limitation under full-cost accounting, were primarily the result of declines in oil and gas prices during the fourth quarter of 1998.
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.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
- --------------- (a) Revenues included the effects of natural gas commodity price agreements which amounted to a gain of $1.3 million ($0.04 per thousand cubic feet ("Mcf")) in 1998 and to losses of $1.6 million ($0.05 per Mcf) and $3.1 million ($0.11 per Mcf) in 1997 and 1996, respectively. The Company had entered into these agreements to reduce risks caused by fluctuations in the prices of natural gas in the spot market. During 1998, 1997 and 1996, the Company used such agreements to set the price of 13%, 9%, and 30%, respectively, of the natural gas that it sold in the spot market. At year-end, the Company had natural gas price agreements outstanding through March 31, 1999.
(b) Other income included $21.3 million in 1998 from an operator in the Bob West Field, representing funds that are no longer needed as a contingency reserve for litigation. Other income in 1997 primarily represented retroactive severance tax refunds in the U.S. and income related to a collection of a receivable in Bolivia.
(c) Excludes corporate general and administrative expenses and financing costs.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves (Unaudited)
The following table sets forth the computation of the standardized measure of discounted future net cash flows relating to proved reserves and the changes in such cash flows in accordance with SFAS No. 69. The standardized measure is the estimated excess future cash inflows from proved reserves less estimated future production and development costs, estimated future income taxes and a discount factor. Future cash inflows represent expected revenues from production of year-end quantities of proved reserves based on year-end prices and any fixed and determinable future escalation provided by contractual arrangements in existence at year-end. Escalation based on inflation, federal regulatory changes and supply and demand are not considered. Estimated future production costs related to year-end reserves are based on year-end costs. Such costs include, but are not limited to, production taxes and direct operating costs. Inflation and other anticipatory costs are not considered until the actual cost change takes effect. Estimated future income tax expenses are computed using the appropriate year-end statutory tax rates. Consideration is given for the effects of permanent differences, tax credits and allowances. A discount rate of 10% is applied to the annual future net cash flows.
The methodology and assumptions used in calculating the standardized measure are those required by SFAS No. 69. The standardized measure is not intended to be representative of the fair market value of the Company's proved reserves. The calculations of revenues and costs do not necessarily represent the amounts to be received or expended by the Company.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
- --------------- (a) For Bolivia, the discounted future income tax expense includes Bolivian taxes of $41.4, $105.0 million and $69.4 million at December 31, 1998, 1997 and 1996, respectively, and U.S. income taxes of $2.3 million and $10.7 million at December 31, 1997 and 1996, respectively.
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Changes in Standardized Measure of Discounted Future Net Cash Flows (Unaudited)
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Reserve Information (Unaudited)
The following estimates of the Company's net proved oil and gas reserves are based on evaluations prepared by Netherland, Sewell & Associates, Inc., except for U.S. net reserves at December 31, 1998 and 1997 which were prepared by in-house engineers and audited by Netherland, Sewell & Associates, Inc. Reserves were estimated in accordance with guidelines established by the Securities and Exchange Commission and FASB, 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.
Table continued on next page
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
- --------------- (a) The Company is required to file annual estimates of its proved reserves with the Department of Energy. Such filings have been consistent with the information presented herein.
(b) Under the Bolivian Hydrocarbons Law passed in 1996, the Company converted its Contracts of Operation for Block 18 and Block 20 into Shared Risk Contracts, which, among other matters, extended the Company's term of operation, provided more favorable acreage relinquishment terms and provided for a more favorable royalty and tax structure.
(c) No major discovery or adverse event has occurred since December 31, 1998 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
DIRECTORS OF THE REGISTRANT
The Company's Board of Directors (sometimes referred to herein as the "Board") consists of seven members, each to hold office until the 1999 Annual Meeting of Stockholders or until their successors are duly elected and qualified. Certain information as to each of the Company's directors is set forth in the table below and in the following paragraphs. Certain of the information appearing in the table and the notes thereto has been furnished to the Company by the respective directors.
- --------------- (a) Member of the Executive Committee (Mr. Smith, Chairman).
(b) Member of the Audit Committee (Mr. Grapstein, Chairman).
(c) Member of the Governance Committee (Dr. Weidenbaum, Chairman).
(d) Member of the Compensation Committee (Mr. Mason, Chairman).
On December 26, 1995, the Stockholders' Committee for New Management of Tesoro Petroleum Corporation (the "Committee"), comprised at that time of five holders of the Company's Common Stock, announced its intention to engage in a solicitation of written consents for the primary purpose of removing the then current members of the Board and replacing them with a new board. On April 4, 1996, a settlement agreement was reached between the Committee and certain related parties (the "Solicitation Parties"), the Company and Ardsley Advisory Partners ("Ardsley"), the Company's then largest stockholder. Pursuant to the settlement agreement, the Solicitation Parties severally agreed, among other things, that for a period beginning as of April 4, 1996, and ending on the earlier of the day after the Company's 1999 annual meeting or June 30, 1999 (the "Standstill Period"), he or it shall not in any way, directly or indirectly, without the approval of the Board, make, encourage, participate or assist in (a) any attempt to take control of the Company, (b) any consent solicitation to remove any member of the Company's Board of Directors, (c) any solicitation of proxies to vote or become a participant in any election contest to remove any member of the Company's Board of Directors, (d) the nomination or election of any alternate director or slate of directors proposed from the floor at any meeting of the Company's stockholders, or (e) any offers or indications of interest with respect to the acquisition or disposition of the Company or any of its business units. In accordance with the settlement agreement, Alan J. Kaufman, M.D., and William J. Johnson are serving as directors of the Company. Pursuant to the settlement agreement, Dr. Kaufman and Mr. Johnson shall continue subject to the terms of the settlement agreement to be nominated for election as part of the Board's
recommended slate throughout the Standstill Period. In the case of Dr. Kaufman, the settlement agreement provides that, in the event any of the Solicitation Parties breaches the terms of the standstill, confidentiality and non-disparagement provisions of the settlement agreement or in the event Dr. Kaufman reduces his holdings of Company Common Stock below 400,000 shares or votes for any nominee for director other than those supported by a majority of the Board, Dr. Kaufman shall immediately tender his resignation and, at the option of the Company, be removed from the Board.
Steven H. Grapstein has been Chief Executive Officer of Kuo Investment Company and subsidiaries ("Kuo"), an international investment group, since January 1997. From September 1985 to January 1997, Mr. Grapstein was a Vice President of Kuo. He is also a director of several of the Kuo companies. Mr. Grapstein has been a Vice President of Oakville N.V. ("Oakville"), a Kuo subsidiary, since 1989.
William J. Johnson has been a petroleum consultant and president of JonLoc Inc., a private company engaged in oil and gas investments, since 1994. From 1990 through 1994, Mr. Johnson served as President, Chief Operating Officer and a director of Apache Corporation, a large independent oil and gas company. Mr. Johnson is on the Board of Directors of Snyder Oil Corporation, an exploration and production company, and J. Ray McDermott, S.A., an engineering and construction company.
Alan J. Kaufman, M.D., is an investor in a number of companies and a retired neurosurgeon. Since 1987, he has been a director of Newpark Resources, Inc., a company engaged primarily in providing oil field services.
Raymond K. Mason, Sr., has been Chairman of the Board of Directors of American Banks of Florida, Inc., since 1978.
Bruce A. Smith has been Chairman of the Board of Directors, President and Chief Executive Officer of the Company since June 1996. He has been a director of the Company since July 1995. Mr. Smith was President and Chief Executive Officer of the Company from September 1995 to June 1996; Executive Vice President, Chief Financial Officer and Chief Operating Officer of the Company from July 1995 to September 1995; Executive Vice President responsible for Exploration and Production and Chief Financial Officer of the Company from September 1993 to July 1995.
Patrick J. Ward has 47 years of experience in international energy operations with Caltex Petroleum Corporation, a 50/50 joint venture of Chevron Corp. and Texaco, Inc., engaged in the business of refining and marketing. Prior to his retirement in August 1995, he was Chairman, President and Chief Executive Officer of Caltex, positions he had held since 1990. Mr. Ward served on the Board of Directors of Caltex from 1989 to 1995.
Murray L. Weidenbaum, an economist and educator, has been the Mallinckrodt Distinguished University Professor and Chairman of the Center for the Study of American Business at Washington University in St. Louis, Missouri, since 1975. Dr. Weidenbaum is a director of May Department Stores Company.
No director of the Company has a family relationship with any other director or executive officer of the Company.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following is a list of the Company's executive officers, their ages and their positions with the Company at March 1, 1999.
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 Company's executive officers have been employed by the Company or its subsidiaries in an executive capacity for at least the past five years, except for those named below who have had the business experience indicated during that period. Positions, unless otherwise specified, are with the Company.
Thomas E. Reardon........... Senior Vice President, Corporate Resources since May 1998. Vice President, Human Resources and Environmental, from September 1995 to May 1998. Vice President, Human Resources and Environmental Services, of Tesoro Petroleum Companies, Inc., a subsidiary of the Company, from October 1994 to September 1995. Vice President, Human Resources, of Tesoro Petroleum Companies, Inc. from February 1990 to October 1994.
Donald A. Nyberg............ President of Tesoro Marine Services, Inc., a subsidiary of the Company, since November 1996. Vice President, Strategic Planning, of MAPCO Inc. from January 1996 to November 1996. President and Chief Executive Officer of Marya Resources from August 1994 to January 1996. President and Chief Executive Officer of BP Pipelines Inc. and Vice President, BP Exploration, of The British Petroleum Group, Ltd., from 1991 to 1994.
Robert W. Oliver............ President of Tesoro Exploration and Production Company, a subsidiary of the Company, since September 1995. Independent consultant from November 1994 to September 1995. Vice President,
Exploration/Acquisitions, of Bridge Oil (USA) Inc. from December 1988 to November 1994.
Stephen L. Wormington....... Executive Vice President and Chief Operating Officer of Tesoro Refining, Marketing & Supply Company, a subsidiary of the Company, since May 1998. President of Tesoro Alaska Petroleum Company, a subsidiary of the Company, from September 1995 to August 1998. Vice President, Supply and Operations Coordination, of Tesoro Alaska Petroleum Company from April 1995 to September 1995. General Manager, Strategic Projects, from January 1995 to April 1995. Executive Vice President, Special Projects, of MG Refining & Marketing, Inc. from January 1994 to January 1995. Executive Vice President of MG Natural Gas Corp. from May 1992 to January 1994.
Bobby J. Culpepper.......... Vice President, Information Technology since July 1998. Vice President, Information Technology, of Tesoro Petroleum Companies, Inc., a subsidiary of the Company, since June 1998. Vice President, Operations of Microage Integration Group from July 1997 to May 1998. Vice President, Information Technology, of Phillips 66 Company, a division of Phillips Petroleum Company from May 1991 to June 1997.
Don M. Heep................. Vice President, Controller since May 1998. Senior Vice President, Administration for Tesoro Alaska Petroleum Company, a subsidiary of the Company, from November 1996 to May 1998. Senior Vice President and Chief Financial Officer of Valero Energy Corporation from 1994 to 1996. Vice President and Chief Accounting Officer of Valero Energy Corporation from 1992 to 1994.
Gregory A. Wright........... Vice President, Finance and Treasurer since May 1998. Vice President and Treasurer from September 1995 to May 1998. Vice President, Corporate Communications from February 1995 to September 1995. Vice President, Corporate Communications, of Tesoro Petroleum Companies, Inc., a subsidiary of the Company, from January 1995 to February 1995. Vice President, Business Development of Valero Energy Corporation from 1994 to January 1995. Vice President, Corporate Planning of Valero Energy Corporation from 1992 to 1994.
SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Securities Exchange Act of 1934, as amended ("Exchange Act"), requires the Company's directors, executive officers and holders of more than 10% of the Company's voting stock to file with the Securities and Exchange Commission ("SEC") initial reports of ownership and reports of changes in ownership of Common Stock or other equity securities of the Company. The Company believes that during the fiscal year ended December 31, 1998, its directors, executive officers and holders of more than 10% of the Company's voting stock complied with all Section 16(a) filing requirements with the following exception: Mr. Grapstein failed to timely report an aggregate of eleven transactions in January 1998 with respect to 131,000 shares of the Company's Common Stock sold by Oakville, of which Mr. Grapstein is a Vice President; and a transaction in July 1998 with respect to 4,000 Premium Income Equity Securities ("PIES"), for which he disclaims beneficial ownership, acquired for the accounts of Mr. Grapstein's minor children.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
COMPENSATION OF EXECUTIVE OFFICERS
SUMMARY OF COMPENSATION
The following table contains information concerning the annual and long-term compensation for services in all capacities to the Company for fiscal years ended December 31, 1998, 1997 and 1996, of those persons who were on December 31, 1998, (i) the Chief Executive Officer and (ii) the other four most highly compensated officers of the Company (collectively, the "named executive officers").
SUMMARY COMPENSATION TABLE
- --------------- (a) No payments were made to the named executive officers which are reportable in Other Annual Compensation. The aggregate amount of perquisites and other personal benefits was less than either $50,000 or 10% of the total annual salary and bonus reported for the named executive officers for all periods shown.
(b) Amounts represent traditional stock options granted to each named executive officer during 1998, 1997 and 1996, except for grants to Mr. Smith in 1997 which were in the form of phantom stock options. At the discretion of the Compensation Committee of the Board of Directors, the 175,000 phantom stock options granted to Mr. Smith in 1997 may be converted to traditional stock options under the Amended and Restated Executive Long-Term Incentive Plan ("1993 Plan"). See table, "Long-Term Incentive Plans-Awards in 1998," on page 92 for information related to contingent awards of phantom stock and cash bonus opportunities under the 1998 Performance Incentive Compensation Plan ("1998 Performance Plan").
(c) In 1996, the Compensation Committee of the Board of Directors approved a special incentive strategy comprised of long-term performance-vested restricted stock and stock options for the executive officers. Awards of restricted Common Stock and stock options under this strategy were earned when the market price of the Company's Common Stock reached an average price of $20 or higher over any 20 consecutive trading days after June 30, 1997, and before December 31, 1998 ("Performance Target"). In connection with this strategy, Messrs. Smith, Van Kleef and Reed were awarded 200,000, 75,000 and 75,000 shares, respectively, of restricted Common Stock, and Messrs. Wormington and Oliver were each granted 75,000 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). On May 12, 1998, the
Performance Target was achieved which resulted in the lapse of restrictions on the restricted Common Stock and vesting of the stock options. Long-term incentive plan ("LTIP") payouts presented above represent the shares of Common Stock awarded under the incentive compensation strategy times $20.4375 per share, or the average market price of the Company's Common Stock on the day of reaching the Performance Target. Although Mr. Wormington and Mr. Oliver became fully vested in the stock options granted under this strategy upon reaching the Performance Target, none of the stock options have been exercised.
(d) All Other Compensation for 1998 includes amounts contributed by the Company and earnings on the respective executive officer's account in the Funded Executive Security Plan (see "Retirement Benefits" below) of $1,353,060, $460,500 and $871,459 for Mr. Smith, Mr. Van Kleef and Mr. Reed, respectively; and amounts contributed to the Company's Thrift Plan of $6,400 each for Mr. Smith, Mr. Van Kleef, Mr. Reed and Mr. Wormington and $6,723 for Mr. Oliver. All Other Compensation for 1997 includes amounts contributed by the Company and earnings on the respective executive officer's account in the Funded Executive Security Plan of $1,135,617, $362,941 and $907,963 for Mr. Smith, Mr. Van Kleef and Mr. Reed, respectively; and amounts contributed to the Company's Thrift Plan of $6,400 for each of the named executive officers. All Other Compensation for 1996 includes amounts contributed by the Company and earnings on the respective executive officer's account in the Funded Executive Security Plan of $786,251, $211,707 and $1,000,176 for Mr. Smith, Mr. Van Kleef and Mr. Reed, respectively; and amounts contributed to the Company's Thrift Plan of $4,500 for each of these executive officers.
(e) Since Mr. Wormington and Mr. Oliver were not considered executive officers during 1996, information is not given for that year.
OPTION GRANTS IN 1998
The following table sets forth information concerning individual grants of traditional stock options pursuant to the 1993 Plan to the named executive officers during the year ended December 31, 1998. No Stock Appreciation Rights ("SARs") were granted under the 1993 Plan during 1998.
OPTION GRANTS IN 1998
- --------------- (a) The right to exercise these options vests in four equal annual installments beginning one year from the date of grant.
(b) The exercise price per share is equal to the public offering price of a share of the Company's Common Stock on July 1, 1998, which was above the market price for the Company's Common Stock on the date of grant of these options in October 1998.
AGGREGATED OPTION/SAR EXERCISES IN 1998 AND OPTION/SAR VALUES AT DECEMBER 31,
The following table reflects the number of unexercised stock options and SARs remaining at year-end and the potential value thereof based on the year-end market price of the Company's Common Stock of $12 1/8 per share. No stock options or SARs were exercised by the named executive officers during 1998.
- --------------- (a) The number of unexercised options/SARs include 26,250 exercisable phantom stock options and 148,750 unexercisable phantom stock options which were granted to Mr. Smith in 1997.
(b) The number of exercisable options for Mr. Wormington and Mr. Oliver includes 75,000 stock options each which were earned in May 1998 when the Performance Target was attained under the special incentive compensation strategy.
LONG-TERM INCENTIVE PLANS -- AWARDS IN 1998
In October 1998, the Company's Board of Directors unanimously approved the 1998 Performance Incentive Compensation Plan ("1998 Performance Plan"), which is intended to advance the best interests of the Company and its stockholders by directly targeting Company performance to align with the ninetieth percentile historical stock-price growth rate for the Company's peer group. In addition, the 1998 Performance Plan will provide the Company's employees with additional compensation, contingent upon achievement of the targeted objectives, thereby encouraging them to continue in the employ of the Company. The 1998 Performance Plan has several tiers of awards, with the award generally determined by job level. The following table and notes thereto provide information concerning contingent long-term incentive awards granted under the 1998 Performance Plan to the named executive officers during the year ended December 31, 1998. The long-term incentive awards under the 1998 Performance Plan are not included in the Summary Compensation Table on page 90.
LONG-TERM INCENTIVE PLANS -- AWARDS IN 1998
- --------------- (a) Under the 1998 Performance Plan, targeted objectives are comprised of the fair market value of the Company's Common Stock equaling or exceeding an average of $35 per share ("First Performance Target") and $45 per share ("Second Performance Target") on any 20 consecutive trading days during a period commencing on October 1, 1998 and ending on the earlier of September 30, 2002, or the date on which the Second Performance Target is achieved ("Performance Period"). Upon achievement of the
First Performance Target, one-fourth of the contingent awards will be earned, with payout deferred until the end of the Performance Period. The remaining 75% will be earned only upon achievement of the Second Performance Target.
(b) Shares represent contingent awards of performance-vested phantom stock granted to Mr. Smith, Mr. Van Kleef and Mr. Reed. If the Second Performance Target is achieved, the executive officer would be entitled to receive in cash an amount equal to the number of shares of phantom stock granted to him multiplied by the fair market value of a share of Common Stock on the last day of the Performance Period. If the First Performance Target is attained but the Second Performance is not attained, the executive officer would receive one-fourth of the amount specified in the preceding sentence.
(c) Mr. Wormington and Mr. Oliver were awarded contingent cash bonus opportunities under the Performance Plan. If the Second Performance Target is achieved, Mr. Wormington and Mr. Oliver would be entitled to receive a cash bonus equal to five times and four times, respectively, of their annual "basic compensation," as defined in the 1998 Performance Plan. If the First Performance Target is attained but the Second Performance is not attained, Mr. Wormington and Mr. Oliver would receive one-fourth of the amount specified in the preceding sentence. Based on current salary rates for Mr. Wormington and Mr. Oliver, estimated future payouts shown above represent the attainment of the First Performance Target (vesting in one-fourth of the award) under "Threshold" and the attainment of the Second Performance Target (earning 100% of the award) under "Maximum."
RETIREMENT BENEFITS
The Company maintains a noncontributory qualified Retirement Plan which covers officers and other eligible employees. Benefits under the plan are payable on a straight life annuity basis and are based on the average monthly earnings and years of service of participating employees. Average monthly earnings used in calculating retirement benefits are primarily salary and bonus received by the participating employee during the 36 consecutive months of the last 120 months of service which produces the highest average monthly rate of earnings.
In addition, the Company maintains an unfunded executive security plan, the Amended Executive Security Plan ("Amended Plan"), for executive officers and other key personnel selected by the Chief Executive Officer. The Amended Plan provides for a monthly retirement income payment during retirement equal to a percentage of a participant's Earnings. "Earnings" is defined under the Amended Plan to mean a participant's average monthly rate of total compensation, primarily salary and bonus earned, including performance bonuses and incentive compensation paid after December 1, 1993, in the form of stock awards of the Company's Common Stock (excluding stock awards under the special incentive compensation strategy and contingent awards under the 1998 Performance Plan), for the 36 consecutive calendar months within the last ten-year period which produce the highest average monthly rate of compensation for the participant. The monthly retirement benefit percentage is defined as the sum of 4 percent of Earnings for each of the first ten years of employment, plus 2 percent of Earnings for each of the next ten years of employment, plus 1 percent of Earnings for each of the next ten years of employment. The maximum percentage is 70 percent. The Amended Plan provides for the payment of the difference, if any, between (a) the total retirement income payment calculated above and (b) the sum of retirement income payments from the Company's Retirement Plan and Social Security benefits.
The Company also maintains the Funded Executive Security Plan ("Funded Plan") which covers only selected persons approved by the Chief Executive Officer, who are also participants in the Amended Plan, and provides participants with substantially the same aftertax benefits as the Amended Plan. Advance payments are made to the extent a participant is expected to incur a pre-retirement tax liability as a result of his participation in the Funded Plan. The Funded Plan is funded separately for each participant on an actuarially determined basis through a bank trust whose primary asset is an insurance contract providing for a guaranteed rate of return for certain periods. Amounts payable to participants from the Funded Plan reduce amounts otherwise payable under the Amended Plan.
The following table shows the estimated annual benefits payable upon retirement under the Company's Retirement Plan, Amended Plan and the Funded Plan for employees in specified compensation and years of benefit service classifications without reference to any amount payable upon retirement under the Social Security law or any amount advanced before retirement. The estimated annual benefits shown are based upon the assumption that the plans continue in effect and that the participant receives payment for life. For limitation years ending with or within calendar year 1998 or 1999, the federal tax law generally limits maximum annual retirement benefits payable by the Retirement Plan to any employee to $130,000, adjusted annually to reflect increases in the cost of living and adjusted actuarially for retirement. However, since the Amended Plan and the Funded Plan are not qualified under Section 401 of the Internal Revenue Code of 1986, as amended (the "Code"), it is possible for certain retirees to receive annual benefits in excess of this tax limitation.
The years of benefit service as of December 31, 1998, for the named executive officers were as follows: Mr. Smith, 6 years; Mr. Van Kleef, 5 years; Mr. Reed, 24 years; Mr. Wormington, 4 years; and Mr. Oliver, 3 years.
In addition to the retirement benefits described above, the Amended Plan provides for a pre-retirement death benefit payable over eight years of four times a participant's annual base pay as of December 1 preceding a participant's date of death, less the amount payable from the Funded Plan at the date of death. The amount payable from the Funded Plan at death is based on the actuarial value of the participant's vested accrued benefit, payable in 96 monthly installments or as a life annuity if a surviving spouse is the designated beneficiary.
COMPENSATION OF DIRECTORS
Each member of the Board of Directors who is not an officer of the Company receives a base retainer of $18,000 per year, and an additional $2,000 for each meeting of the Board of Directors or any committee thereof attended in person, and $1,000 for each telephone meeting, including committee meetings held on the same day as a meeting of the Board of Directors. The non-executive Vice Chairman of the Board of Directors receives $25,000 per year for his service. In addition, the Chairman of the Audit Committee, Chairman of the Compensation Committee and Chairman of the Governance Committee each receive $5,000 per year for their service in such positions. The Company provides group life insurance benefits in the amount of $100,000 and accidental death and dismemberment insurance up to a maximum of $350,000 for each of the members of the Board of Directors who are not employees of the Company. The premium for such insurance ranged from $265 to $5,844 for each of these directors during fiscal year 1998. Commencing with the 1997 Annual Meeting of Stockholders, one-half of each of the director's annual retainer is paid in Common Stock of the Company on an annual basis. The Company issues to each director within 30 days after the annual meeting of
stockholders of the Company at which the director is elected a number of shares equal to one-half of the annual retainer in effect on the date of such meeting divided by the average of the closing prices for the Common Stock, as reported on the New York Stock Exchange ("NYSE") composite tape, for the ten trading days prior to such annual meeting. The shares of Common Stock issued to the directors will be held by the Company and will not be sold, pledged or otherwise disposed of and will not be delivered to the directors until the earlier of (i) the first anniversary date of the annual meeting which immediately preceded the issuance of such shares or (ii) the date on which the person ceases to be a director. The directors will have full voting rights with respect to such shares of Common Stock.
The Company had established an unfunded Non-Employee Director Retirement Plan ("Director Retirement Plan") in December 1994 which provided that any eligible non-employee director who elected to participate in the Director Retirement Plan and who had served on the Company's Board of Directors for at least three full years would be entitled to a retirement payment in cash beginning the later of the director's sixty-fifth birthday or such later date that the individual's service as a director ended. However, to more closely align director compensation with shareholders' interest, in March 1997, the Board of Directors amended the Director Retirement Plan to freeze the plan and convert the accrued benefits of each current director under the plan to a lump-sum present value which was transferred to an account ("Account") for each director in the Tesoro Petroleum Corporation Board of Directors Deferred Phantom Stock Plan ("Phantom Stock Plan"). After the amendment and transfer, only those retired directors or beneficiaries who had begun receiving benefits remained participants in the Director Retirement Plan. By participating in the Phantom Stock Plan, each director waives any and all rights under the Director Retirement Plan. Commencing with 1997, each current and future non-employee director ("Participant") shall have credited to his Account as of the last day of the year a yearly accrual equal to $7,250, prorated to $6,042 for 1997 (limited to 15 accruals, including previous accruals of retirement benefits under the Director Retirement Plan); and each Participant who is serving as a chairman of a committee of the Board of Directors immediately prior to his termination as director and who has served at least three years as a director shall have an additional $5,000 credited to his Account. The Phantom Stock Plan allows for pro rata calculations of the yearly accrual in the event a director serves for part of a year. In addition, a Participant may elect to defer any part or all of the cash portion of his annual director retainer into his Account. Each transfer, accrual or deferral shall be credited quarterly to the Participant's Account in units based upon the number of shares that could have been purchased with the dollars credited based upon the closing price of the Company's Common Stock on the NYSE on the date the amount is credited. Dividends or other distributions accrue to the Participant's Account. Participants are vested 100 percent at all times with respect to deferrals and, if applicable, the chairman fee portion of his Account. Participants vest in amounts transferred from the Director Retirement Plan and the yearly accruals upon completion of three full years of service (including all service prior to March 6, 1997) as a member of the Board. If a Participant voluntarily resigns or is removed from the Board prior to serving three years on the Board, he shall forfeit all amounts not vested. If a director dies, retires, or becomes disabled, he shall be 100 percent vested in his Account without regard to services. Distributions from the Phantom Stock Plan shall be made in cash, based on the closing market price of the Company's Common Stock on the NYSE on the business day immediately preceding the date on which the cash distribution is to be made, and such distributions shall be made in either a lump-sum distribution or in annual installments not exceeding ten years. Death, disability, retirement or cessation of a Participant as a director of the Company constitute an event requiring a distribution. Upon the death of a Participant, the Participant's beneficiary will receive as soon as practicable the cash value of the Participant's Account as of the date of death. At December 31, 1998, each Participant's Account was comprised of 4,474 units, 1,767 units, 2,299 units, 14,736 units, 2,209 units and 7,433 units of phantom stock for Messrs. Grapstein, Johnson, Kaufman, Mason, Ward and Weidenbaum, respectively.
Under the Tesoro Petroleum Corporation Board of Directors Deferred Compensation Plan ("Deferred Compensation Plan"), a director electing to participate may defer between 20 percent and 100 percent of his total cash compensation for the ensuing year, which deferred fees are credited to an interest-bearing account maintained by the Company. Interest is applied to each quarter's deferral at the prime rate published in The Wall Street Journal on the last business day of such quarter plus two percentage points (9.75% at December 31, 1998). All payments under the Deferred Compensation Plan are the sole obligation of the
Company. Upon the death of a participating director, the balance in his account under the Deferred Compensation Plan is paid to his beneficiary or beneficiaries in one lump sum. In the event of the disability, retirement or the removal or resignation prior to the death, disability or retirement of a participating director, the balance in his account will be paid to such director in ten equal annual installments. In the event of a change of control (as "change of control" is defined in the Deferred Compensation Plan), the balance in each participating director's account will be distributed to him as a lump sum within 30 days after the date of the change of control. The Company also has an agreement with Frost National Bank of San Antonio, Texas, under which the Tesoro Petroleum Corporation Board of Directors Deferred Compensation Trust was established for the sole purpose of creating a fund to provide for the payment of deferred compensation to participating directors under the Deferred Compensation Plan.
The Company's 1995 Non-Employee Director Stock Option Plan ("1995 Plan") provides for the grant to non-employee directors of automatic, non-discretionary stock options, at an exercise price equal to the fair market value of the Common Stock as of the date of grant. Under the 1995 Plan, each person serving as a non-employee director on February 23, 1995, or elected thereafter, initially receives an option to purchase 5,000 shares of the Company's Common Stock. Thereafter, each non-employee director, while the 1995 Plan is in effect and shares are available to grant, will be granted an option to purchase 1,000 shares of Common Stock on the next day after each annual meeting of the Company's stockholders but not later than June 1, if no annual meeting is held. All options under the 1995 Plan become exercisable six months after the date of grant. The 1995 Plan will terminate as to the issuance of stock options in February 2005. Under the 1995 Plan, stock options for 1,000 shares with an exercise price of $16.1875 per share were granted to each non-employee director of the Company on July 30, 1998. At March 1, 1999, the Company had 62,000 options outstanding and 71,000 shares available for future grants under the 1995 Plan.
EMPLOYMENT CONTRACTS, MANAGEMENT STABILITY AGREEMENTS AND CHANGE-IN-CONTROL ARRANGEMENTS
Under an amendment effective October 28, 1998 to an employment agreement dated November 1, 1997, Mr. Smith is employed until November 1, 2000, at an annual base salary of $700,000. Under separate employment agreements, Mr. Van Kleef and Mr. Reed are employed until October 28, 2000, at annual base salaries of $450,000 and $350,000, respectively. In addition to their base salaries, each of the employment agreements for the above executives provides that the Company shall establish an annual incentive compensation strategy for executive officers in which each executive shall be entitled to participate in a manner consistent with his position with the Company and the evaluations of his performance by the Board of Directors or any appropriate committee thereof. The target incentive bonus under the 1998 annual incentive compensation strategy was a percentage of the respective executive officer's annual base salary and was 100% for Mr. Smith, 90% for Mr. Van Kleef and 75% for Mr. Reed. Each of the employment agreements also provides that the executive will receive an annual amount ("flexible perquisite amount") to cover various business-related expenses such as dues for country, luncheon or social clubs; automobile expenses; and financial and tax planning expenses. The executive may elect at any time by written notice to the Company to receive in cash any of such flexible perquisite amount which has not been paid to or on behalf of the executive. The annual flexible perquisite amount is $30,000, $20,000 and $20,000 for Mr. Smith, Mr. Van Kleef and Mr. Reed, respectively. Each employment agreement also provides that the Company will pay initiation fees for social clubs and reimburse the executive for related tax expenses to the extent the Board of Directors, or a duly authorized committee thereof, determines such fees are reasonable and in the best interest of the Company.
Each of the employment agreements with Mr. Smith, Mr. Van Kleef and Mr. Reed provides that in the event the Company should terminate such executive officer's employment without cause, if he should resign his employment for "good reason" (as "good reason" is defined in the employment agreements), or if the Company shall not have offered to such executive officer prior to the termination date of his employment agreement the opportunity to enter into a new employment agreement, with terms, in all respects, no less favorable to the executive than the terms of his current employment agreement, such executive will be paid a lump-sum payment equal to (i) two times the sum of (a) his base salary at the then current rate and (b) the
sum of the target bonuses under all of the Company's incentive bonus plans applicable to such executive for the year in which the termination occurs and (ii) if termination occurs in the fourth quarter of a calendar year, the sum of the target bonuses under all of the Company's incentive bonus plans applicable to such executive for the year in which the termination occurs prorated daily based on the number of days from the beginning of the calendar year in which the termination occurs to and including the date of termination. Each executive shall also receive all unpaid bonuses for the year prior to the year in which the termination occurs and shall receive (i) for a period of two years continuing coverage and benefits comparable to all life, health and disability insurance plans which the Company from time to time makes available to its management executives and their families, (ii) a lump-sum payment equal to two times the flexible perquisites amount and (iii) two years additional service credit under the Amended Plan and the Funded Plan, or successors thereto, of the Company applicable to such executive on the date of termination. All unvested stock options held by the executive on the date of the termination shall become immediately vested and all restrictions on "restricted stock" then held by the executive shall terminate, except for awards under the 1998 Performance Plan.
Each employment agreement further provides that, in the event such executive officer's employment is involuntarily terminated within two years of a change of control or if the executive officer's employment is voluntarily terminated within two years of a change of control "for good reason," as defined in each of the employment agreements, he shall be paid within ten days of such termination (i) a lump-sum payment equal to three times his base salary at the then current rate; (ii) a lump-sum payment equal to the sum of (a) three times the sum of the target bonuses under all of the Company's incentive bonus plans applicable to such executive for the year in which the termination occurs or the year in which the change of control occurred, whichever is greater, and (b) if termination occurs in the fourth quarter of a calendar year, the sum of the target bonuses under all of the Company's incentive bonus plans applicable to such executive for the year in which the termination occurs prorated daily based on the number of days from the beginning of the calendar year in which the termination occurs to and including the date of termination; and (iii) a lump-sum payment equal to the amount of any accrued but unpaid bonuses. The Company (or its successor) shall also provide (i) for a period of three years continuing coverage and benefits comparable to all life, health and disability plans of the Company in effect at the time a change of control is deemed to have occurred; (ii) a lump-sum payment equal to three times the flexible perquisites amount; and (iii) three years additional service credit under the Amended Plan and the Funded Plan, or successors thereto, of the Company applicable to such executive on the date of termination. A change in control shall be deemed to have occurred if (i) there shall be consummated (a) any consolidation or merger of the Company in which the Company is not the continuing or surviving corporation or pursuant to which shares of the Company's Common Stock would be converted into cash, securities or other property, other than a merger of the Company where a majority of the Board of Directors of the surviving corporation are, and for a two-year period after the merger continue to be, persons who were directors of the Company immediately prior to the merger or were elected as directors, or nominated for election as director, by a vote of at least two-thirds of the directors then still in office who were directors of the Company immediately prior to the merger, or (b) any sale, lease, exchange or transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of the Company, or (ii) the shareholders of the Company shall approve any plan or proposal for the liquidation or dissolution of the Company, or (iii)(A) any "person" (as such term is used in Sections 13(d) and 14(d)(2) of the Exchange Act) other than the Company or a subsidiary thereof or any employee benefit plan sponsored by the Company or a subsidiary thereof, shall become the beneficial owner (within the meaning of Rule 13d-3 under the Exchange Act) of securities of the Company representing 20 percent or more of the combined voting power of the Company's then outstanding securities ordinarily (and apart from rights accruing in special circumstances) having the right to vote in the election of directors, as a result of a tender or exchange offer, open market purchases, privately negotiated purchases or otherwise, and (B) at any time during a period of two years thereafter, individuals who immediately prior to the beginning of such period constituted the Board of Directors of the Company shall cease for any reason to constitute at least a majority thereof, unless the election or the nomination by the Board of Directors for election by the Company's shareholders of each new director during such period was approved by a vote of at least two-thirds of the directors then still in office who were directors at the beginning of such period.
Each employment agreement further provides that if remuneration or benefits of any form paid to them by the Company or any trust funded by the Company during or after their employment with the Company are excess parachute payments as defined in Section 280G of the Code, and are subject to the 20 percent excise tax imposed by Section 4999 of the Code, the Company shall pay Mr. Smith, Mr. Van Kleef and Mr. Reed a bonus no later than seven days prior to the due date for the excise tax return in an amount equal to the excise tax payable as a result of the excess parachute payment and any additional federal income taxes (including any additional excise taxes) payable by them as a result of the bonus, assuming that they will be subject to federal income taxes at the highest individual margin rate.
The Company has separate Management Stability Agreements ("Stability Agreements") with Mr. Wormington and Mr. Oliver which are only operative in the event of a change of control of the Company. The Stability Agreements provide that, if Mr. Wormington's or Mr. Oliver's employment is involuntarily terminated within two years of a change of control or if Mr. Wormington's or Mr. Oliver's employment is voluntarily terminated within two years of a change of control "for good reason," as defined in the Stability Agreements, he shall be paid within ten days of such termination (i) a lump-sum payment equal to two times his base salary at the then current rate and (ii) a lump-sum payment equal to the sum of (a) two times the sum of the target bonuses under all of the Company's incentive bonus plans applicable to Mr. Wormington and Mr. Oliver for the year in which the termination occurs or the year in which the change of control occurred, whichever is greater, and (b) if termination occurs in the fourth quarter of a calendar year, the sum of the target bonuses under all of the Company's incentive bonus plans applicable to Mr. Wormington and Mr. Oliver for the year in which the termination occurs prorated daily based on the number of days from the beginning of the calendar year in which the termination occurs to and including the date of termination. The Company (or its successor) shall also provide continuing coverage and benefits comparable to all life, health and disability plans of the Company for a period of 24 months from the date of termination and Mr. Wormington and Mr. Oliver would each receive two years additional service credit under the Amended Plan and the Funded Plan, or successors thereto, of the Company applicable to such executive on the date of termination. A change of control shall be deemed to have occurred if (i) there shall be consummated (a) any consolidation or merger of the Company in which the Company is not the continuing or surviving corporation or pursuant to which shares of the Company's Common Stock would be converted into cash, securities or other property, other than a merger of the Company where a majority of the Board of Directors of the surviving corporation are, and for a two-year period after the merger continue to be, persons who were directors of the Company immediately prior to the merger or were elected as directors, or nominated for election as director, by a vote of at least two-thirds of the directors then still in office who were directors of the Company immediately prior to the merger, or (b) any sale, lease, exchange or transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of the Company, or (ii) the shareholders of the Company shall approve any plan or proposal for the liquidation or dissolution of the Company, or (iii)(A) any "person" (as such term is used in Sections 13(d) and 14(d)(2) of the Exchange Act) other than the Company or a subsidiary thereof or any employee benefit plan sponsored by the Company or a subsidiary thereof, shall become the beneficial owner (within the meaning of Rule 13d-3 under the Exchange Act) of securities of the Company representing 20 percent or more of the combined voting power of the Company's then outstanding securities ordinarily (and apart from rights accruing in special circumstances) having the right to vote in the election of directors, as a result of a tender or exchange offer, open market purchases, privately negotiated purchases or otherwise, and (B) at any time during a period of one year thereafter, individuals who immediately prior to the beginning of such period constituted the Board of Directors of the Company shall cease for any reason to constitute at least a majority thereof, unless the election or the nomination by the Board of Directors for election by the Company's shareholders of each new director during such period was approved by a vote of at least two-thirds of the directors then still in office who were directors at the beginning of such period, or (iv) there shall be, in the cases of Mr. Wormington or Mr. Oliver, the Company's refining and marketing business or exploration and production business, respectively, (A) a direct or indirect sale of all or substantially all of the assets of the Company's refining and marketing business or exploration and production business, or (B) the sale of stock of a subsidiary (or affiliate) of the Company that conducts all or substantially all of the Company's refining and marketing business or exploration and production business, or (C) a merger, joint venture or other business combination
involving the Company's refining and marketing business or exploration and production business, and as a result of such sale of assets, sale of stock, merger, joint venture or other business combination, the Company shall cease to have the power to elect a majority of the Board of Directors (or the other equivalent governing or managing body) of the entity which acquires, or otherwise controls or conducts, the Company's refining and marketing business or exploration and production business.
In order to participate in the 1998 Performance Plan, the parties to the employment agreements and management stability agreements described above are required to acknowledge that the rights and benefits under the 1998 Performance Plan shall not be deemed an "incentive bonus plan" or other bonus or compensation arrangement which shall be accelerated, multiplied or otherwise required to be provided or enhanced under the employment agreement or management stability agreement.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
At the beginning of the 1998 fiscal year, the Compensation Committee was comprised of four members: Raymond K. Mason, Sr., Alan J. Kaufman, Patrick J. Ward and William J. Johnson. In July 1998, following the annual meeting of stockholders, Mr. Grapstein was added to the Compensation Committee. No members of the Compensation Committee served or had formerly served as an executive officer of the Company or had any relationships or related transactions as described in Item 13 hereof.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
The following table sets forth information based on filings made with the SEC as to each person or group who on March 1, 1999, beneficially owned more than 5 percent of the outstanding shares of Common Stock of the Company.
- --------------- (a) According to Amendment No. 3 to a Schedule 13G ("Amendment No. 3") filed with the SEC, Wanger Asset Management, L.P. ("WAM"), states that it is a Delaware limited partnership and an Investment Adviser registered under Section 203 of the Investment Advisers Act of 1940 and Wanger Asset Management Ltd. states that it is a Delaware corporation and the General Partner of the Investment Adviser. Amendment No. 3 indicates that the shares reported therein have been acquired on behalf of discretionary clients of WAM and that persons other than WAM are entitled to receive all dividends from, and proceeds from the sale of, those shares. According to Amendment No. 3, within the meaning of Rule 13d-3 of the Exchange Act, WAM beneficially owns the shares shown in the table above and possesses shared power to vote or to direct the vote and shared power to dispose or direct the disposition of these shares.
(b) According to a Schedule 13G filed with the SEC, Dimensional Fund Advisors Inc. ("Dimensional") states that it is a Delaware corporation and an investment adviser registered under the Investment Advisers Act of 1940. In the Schedule 13G, Dimensional states that it furnishes investment advice to four investment companies registered under the Investment Company Act of 1940 and serves as investment
manager to certain other investment vehicles, including commingled group trusts. These investment companies and investment vehicles are the "Portfolios." In the Schedule 13G, Dimensional states that in its role as investment adviser and investment manager, Dimensional possesses both voting and investment power over the 1,857,700 shares of Common Stock that are owned by the Portfolios. Dimensional states that the 1,857,700 shares of Common Stock are owned by the Portfolios and disclaims beneficial ownership of such securities.
(c) In a Schedule 13G filed with the SEC, Boston Partners Asset Management, L.P. ("BPAM") states that is a Delaware limited partnership; Boston Partners, Inc. ("Boston Partners") states that it is a Delaware corporation; and Desmond John Heathwood states that he is a United States citizen. According to the Schedule 13G, BPAM, Boston Partners and Mr. Heathwood (collectively, the "Reporting Persons") may be deemed to own beneficially 1,795,700 shares of Common Stock (including 845,500 shares of Common Stock issuable upon conversion of 1,000,000 shares of PIES). The Schedule 13G states that BPAM owns 950,200 shares of Common Stock and 1,000,000 shares of PIES. Because each PIES is convertible into 0.8455 shares of Common Stock, BPAM may be deemed to own beneficially 845,500 shares of Common Stock related thereto. According to the Schedule 13G, BPAM may be deemed to own beneficially a total of 1,795,700 shares of Common Stock; as sole general partner of BPAM, Boston Partners may be deemed to own beneficially all of the shares of Common Stock that BPAM may be deemed to own beneficially; as principal stockholder of Boston Partners, Mr. Heathwood may be deemed to own beneficially all of the Common Stock that Boston Partners may be deemed to own beneficially; and, therefore, each of the Reporting Persons may be deemed to own beneficially 1,795,700 shares of Common Stock of Tesoro. The Schedule 13G states that all Reporting Persons have shared power to dispose or to direct the disposition of and shared power to vote or to direct the vote of 1,795,700 shares. In the Schedule 13G, each of Boston Partners and Mr. Heathwood expressly disclaims beneficial ownership of any shares of Common Stock of Tesoro. According to the Schedule 13G, BPAM holds all of the above 1,795,700 shares under management for its clients, who have the right to direct the receipt of dividends, to receive dividends from such shares and to receive the proceeds from the sale of such shares.
SECURITY OWNERSHIP OF MANAGEMENT AND DIRECTORS
The following table shows the beneficial ownership of the Company's Common Stock reported to the Company as of March 1, 1999, including shares as to which a right to acquire ownership exists (for example, through the exercise of stock options or stock awards or conversion of PIES) within the meaning of Rule 13d-3(d)(1) under the Exchange Act for each director and the named executive officers and, as a group, such persons and other executive officers. Unless otherwise indicated, each person or member of the group listed has sole voting and investment power with respect to the shares of Common Stock listed. The PIES, which represent fractional interests in the Company's 7.25% Mandatorily Convertible Preferred Stock, have no voting rights.
- --------------- (a) The shares shown for Mr. Grapstein, Mr. Mason and Dr. Weidenbaum include 9,000 shares each which such directors had the right to acquire through the exercise of stock options on March 1, 1999, or within 60 days thereafter. The shares shown for Mr. Johnson, Dr. Kaufman and Mr. Ward include 7,000 shares, 8,000 shares and 8,000 shares, respectively, which such directors had the right to acquire though the exercise of stock options on March 1, 1999, or within 60 days thereafter. In addition, the shares shown for each director include 510 shares of restricted Common Stock as payment of one-half of each director's annual retainer for fiscal year 1998 (see "Compensation of Directors" discussed above). Units of phantom stock payable in cash which have been credited to the directors under the Phantom Stock Plan and to Mr. Smith, Mr. Van Kleef and Mr. Reed under the 1998 Performance Plan are not included in the shares shown above.
(b) The shares shown include 846,300 shares of the Company's Common Stock owned by Oakville. Mr. Grapstein is an officer of Oakville. As an officer, Mr. Grapstein shares voting and investment power with respect to such shares. The shares shown also include 3,382 shares of Common Stock which could be obtained upon the conversion of 4,000 PIES into Common Stock at March 1, 1999, for which Mr. Grapstein disclaims beneficial ownership, held in accounts for his minor children. Each PIES is convertible into 0.8455 shares of Common Stock.
(c) The shares shown include 9,000 shares held in the name of Dr. Kaufman's spouse for which he disclaims beneficial ownership, and 20,000 shares owned by the Kaufman Children's Trust for which Dr. Kaufman has sole power to vote and direct the disposition thereof.
(d) The shares shown include 3,311 shares credited to Mr. Smith's account under the Company's Thrift Plan and 330,134 shares which Mr. Smith had the right to acquire through the exercise of stock options on March 1, 1999, or within 60 days thereafter.
(e) The shares shown include 6,000 shares owned by the P&L Family Partnership Ltd. which Mr. Ward and his spouse control through 90% ownership.
(f) The shares shown include 2,344 shares credited to Mr. Van Kleef's account under the Company's Thrift Plan and 124,706 shares which Mr. Van Kleef had the right to acquire through the exercise of stock options or stock awards on March 1, 1999, or within 60 days thereafter.
(g) The shares shown include 1,352 shares credited to Mr. Reed's account under the Company's Thrift Plan and 92,384 shares which Mr. Reed had the right to acquire through the exercise of stock options on March 1, 1999, or within 60 days thereafter.
(h) The shares shown include 1,474 shares credited to Mr. Wormington's account under the Company's Thrift Plan and 144,916 shares which Mr. Wormington had the right to acquire through the exercise of stock options on March 1, 1999, or within 60 days thereafter.
(i) The shares shown include 586 shares credited to Mr. Oliver's account under the Company's Thrift Plan and 112,916 shares which Mr. Oliver had the right to acquire through the exercise of stock options on March 1, 1999, or within 60 days thereafter. The shares shown also include 1,000 shares held in the name of Mr. Oliver's spouse for which he disclaims beneficial ownership.
(j) The shares shown include 13,215 shares credited to the accounts of executive officers and directors under the Company's Thrift Plan and 1,103,123 shares which directors and executive officers had the right to acquire through the exercise of stock options or stock awards on March 1, 1999, or within 60 days thereafter. The shares shown also include 3,382 shares which an executive officer could obtain upon the conversion of 4,000 PIES into Common Stock at March 1, 1999. Each PIES is convertible into 0.8455 shares of Common Stock. The shares shown also include 2,334 shares held in the name of executive officers' spouses for which each executive officer disclaims beneficial ownership and 3,000 shares acquired in the name of an executive officer's mother with respect to which such executive officer has voting and investment power.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
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
No financial statement schedules are submitted because of the absence of the conditions under which they are required or because the required information is included in the Consolidated Financial Statements or notes thereto.
3. EXHIBITS
- ---------------
* Filed herewith.
+ Identifies management contracts or compensatory plans or arrangements required to be filed as exhibits hereto pursuant to Item 14(c) of Form 10-K.
** The Financial Data Schedule shall not be deemed "filed" for purposes of Section 11 of the Securities Act of 1933 or Section 18 of the Securities Exchange of 1934, and is included as an exhibit only to the electronic filing of this From 10-K in accordance with Item 601(c) of Regulation S-K and Section 401 of Regulation S-T.
Copies of exhibits filed as part of this Form 10-K may be obtained by stockholders of record at a charge of $0.15 per page, minimum $5.00 each request. Direct inquiries to the Corporate Secretary, Tesoro Petroleum Corporation, 8700 Tesoro Drive, San Antonio, Texas, 78217-6218.
(B) REPORTS ON FORM 8-K
No reports on Form 8-K were filed by the Company during the quarter ended December 31, 1998.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
TESORO PETROLEUM CORPORATION
March 30, 1999 By: /s/ BRUCE A. SMITH ------------------------------------ Bruce A. Smith Chairman of the Board of Directors, President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
EXHIBIT INDEX
- --------------- * Filed herewith.
+ Identifies management contracts or compensatory plans or arrangements required to be filed as exhibits hereto pursuant to Item 14(c) of Form 10-K.
** The Financial Data Schedule shall not be deemed "filed" for purposes of Section 11 of the Securities Act of 1933 or Section 18 of the Securities Exchange of 1934, and is included as an exhibit only to the electronic filing of this Form 10-K in accordance with Item 601(c) of Regulation S-K and Section 401 of Regulation S-T.