ITEM 1. BUSINESS
Tesoro Petroleum Corporation, together with its subsidiaries ('Tesoro' or the 'Company'), is a natural resource company engaged in refining and marketing, exploration and production of natural gas, and wholesale marketing of fuel and lubricants. The Company was incorporated in Delaware in 1968 (a successor by merger to a California corporation incorporated in 1939). For financial information relating to industry segments, see Management's Discussion and Analysis of Financial Condition and Results of Operations in Item 7 and Note N of Notes to Consolidated Financial Statements in Item 8.
RECENT EVENTS
In February 1994, the Company completed a recapitalization plan ('Recapitalization') which was approved by the Board of Directors during 1993. Among other things, the Recapitalization included the exchange by holders of $44.1 million principal amount of the Company's 12 3/4% Subordinated Debentures ('Subordinated Debentures') for a like amount of new 13% Exchange Notes and the approval by holders of the Company's $2.16 Cumulative Convertible Preferred Stock ('$2.16 Preferred Stock') to reclassify such stock (including accrued and unpaid dividends thereon of approximately $9.5 million) into an aggregate of 6,465,859 shares of the Company's Common Stock. In addition, the Company also agreed to issue 131,956 shares of its Common Stock on behalf of the holders of $2.16 Preferred Stock to pay certain of their legal fees and expenses in connection with the settlement of the litigation discussed below.
In connection with the Recapitalization, the Company also entered into an agreement with MetLife Security Insurance Company of Louisiana ('MetLife') ('Amended MetLife Memorandum'), pursuant to which MetLife, the sole holder of the outstanding shares of the Company's $2.20 Cumulative Convertible Preferred Stock ('$2.20 Preferred Stock'), agreed, among other things, to waive the annual $2.20 Preferred Stock mandatory redemption requirements, to consider all accrued and unpaid dividends on the $2.20 Preferred Stock as of the effective date of the Recapitalization (aggregating approximately $21.2 million) to have been paid, to allow the Company to pay future dividends on the $2.20 Preferred Stock in Common Stock in lieu of cash, to waive or refrain from the exercise of other rights under the $2.20 Preferred Stock, and to grant the Company a three-year option to purchase all shares of $2.20 Preferred Stock and Common Stock held by MetLife as of the effective date of the Recapitalization for an aggregate option price of $53 million at February 9, 1994, subject to certain adjustments. The unpaid option price will be increased by 3% on the first day of each calendar quarter through December 31, 1995 and by 3 1/2% of the unpaid option price on the first day of each quarter thereafter. Pursuant to the Amended MetLife Memorandum, the Company agreed to issue MetLife 1,900,075 shares of Common Stock at the time of the reclassification of the $2.16 Preferred Stock. Upon shareholders' approval of the Recapitalization, MetLife owned 2,875,000 shares of $2.20 Preferred Stock and 4,084,160 shares of Common Stock, including the 1,900,075 shares of Common Stock issued to MetLife in connection with the Recapitalization.
Consummation of the Recapitalization has improved the short-term and long-term liquidity of the Company and has increased the Company's equity capital. The exchange of the $44.1 million principal amount of Subordinated Debentures will satisfy annual sinking fund requirements on the Subordinated Debentures for approximately four years. The Recapitalization is also intended to improve the financial condition of the Company and allow the Company to continue its new strategy of improving its refining and marketing operations and accelerating its oil and gas exploration and development activities, as discussed in more detail below. For information on the pro forma effects of the Recapitalization, see Note B of Notes to Consolidated Financial Statements in Item 8.
In October 1993, Croyden Associates, a holder of shares of the Company's $2.16 Preferred Stock, filed a class action suit in Delaware Chancery Court on behalf of itself and all other holders of the $2.16 Preferred Stock. The suit alleged that the Company and its directors breached their fiduciary duties to the holders of the $2.16 Preferred Stock based on the terms of the proposed recapitalization as described in the Company's Proxy Statement, Prospectus and Consent Solicitation ('Proxy Statement -- Prospectus') as originally filed with the Securities and Exchange Commission on September 2, 1993, which provided for the reclassification of each share of $2.16 Preferred Stock into 3.5 shares of Common Stock or, at the holder's option, 2.75 shares of Common Stock and .25 share of a new issue of preferred stock. The suit sought, among other things, monetary damages and to enjoin the recapitalization. After Croyden Associates filed the lawsuit, representatives of the Company and representatives of Croyden Associates, including the attorneys for the holders of $2.16 Preferred Stock, had numerous discussions over a period of four months concerning the possible settlement of the litigation. During the course of such discussions, various rates for exchanging the $2.16 Preferred Stock into Common Stock were proposed by the parties, ranging from four shares to six shares of Common Stock for each share of $2.16 Preferred Stock. In addition, the parties discussed the possibility of issuing shares of Common Stock based on the market price for such shares during a period immediately before or after consummation of the Recapitalization. During the course of such discussions, Croyden Associates proposed a fixed rate of five shares of Common Stock per share of $2.16 Preferred Stock and the parties ultimately reached agreement on such rate. Discussions then took place between attorneys for the Company and the attorneys for the holders of the $2.16 Preferred Stock with respect to payment of fees and expenses of the attorneys for the holders of the $2.16 Preferred Stock, which fees and expenses are the obligations of the holders of the $2.16 Preferred Stock, the class benefiting from the services of such counsel. As a result of these discussions, the Company agreed to pay up to $500,000 in cash of the fees and expenses awarded by the Chancery Court, and the attorneys for the holders of the $2.16 Preferred Stock agreed to limit their fee application to $500,000 in cash plus .1 share of Common Stock for each share of $2.16 Preferred Stock. Out of the five shares of Common Stock the Company agreed to issue for each share of $2.16 Preferred Stock, the Company agreed to issue .1 share on behalf of the holders of $2.16 Preferred Stock so that such shares will be available to pay the fees and expenses of such attorneys if awarded by the Chancery Court. On February 4, 1994, Croyden Associates and the Company entered into an agreement seeking court approval of a settlement based upon the terms set forth in the Proxy Statement -- Prospectus. By order dated February 7, 1994, the Delaware Chancery Court scheduled a hearing, to be held on April 13, 1994, to determine whether to approve the terms of the settlement and enter a final judgment dismissing the action.
In March 1994, the Company's Board of Directors authorized management of the Company to investigate the feasibility of a future equity offering of additional shares of the Company's Common Stock together with a future public debt offering. The proceeds from these offerings would be used to finance the Company's option to acquire all of the Company's outstanding Common Stock and $2.20 Preferred Stock held by MetLife and to refinance all or a portion of the Company's outstanding long-term debt.
The Company transports its crude oil and a substantial portion of its refinery products over Kenai Pipe Line Company's ('KPL') pipeline and marine terminal facilities in Nikiski, Alaska. KPL's common carrier pipeline is subject to rate regulation by the Federal Energy Regulatory Commission ('FERC') and the Alaska Public Utilities Commission. On March 1, 1994, KPL filed a revised tariff with the FERC, with a proposed effective date of April 1, 1994, to regulate certain dock loading services KPL had previously provided pursuant to a private contract with the Company which KPL has terminated. KPL's proposed FERC rate for this dock loading service would have increased the Company's annual cost of transporting products through KPL's facilities from $1.2 million to $11.2 million or an increase of $10 million per year. The Company considered the proposed KPL rate clearly excessive and on March 21, 1994, filed a motion to reject or suspend the
rate with the FERC. On March 29, 1994, the FERC rejected KPL's revised tariff; however, under FERC regulations, KPL has the right to file a new tariff.
The Company has recently initiated discussions with KPL to acquire the facilities or an interest therein. In connection therewith, KPL has agreed not to file a new tariff with the FERC for a period of at least 30 days and the Company has agreed to negotiate a rate with KPL for that period. While the Company is unable to predict the purchase price for the facility, or an interest therein, if a purchase with KPL is negotiated, the Company does not believe that any negotiated purchase price will have a material effect on the Company's financial condition or liquidity. The Company also cannot predict (i) whether it will ultimately be able to negotiate the acquisition of the facilities or an interest therein, (ii) the rate of any new tariff that may be filed by KPL, or approved by the FERC, if the Company is unable to negotiate an acquisition of the facilities or an interest therein, and (iii) whether any new rate that may be filed by KPL or the ultimate resolution of this matter by the FERC if the Company is unable to negotiate an acquisition of the facilities or an interest therein will have a material adverse effect upon the financial condition of the Company.
REFINING AND MARKETING
REFINING AND MARKETING
The Company conducts refining operations in Alaska and sells products to a wide variety of customers in Alaska, in the area west of the Rocky Mountains and in certain Far Eastern markets. During 1993, products from the Company's Alaska refinery accounted for approximately 75% of such sales, including products received on exchange in the West Coast market, with the remaining 25% being purchased from other refiners and suppliers.
The refinery, which is located in Kenai, Alaska, has a rated throughput capacity of 72,000 barrels per day and is capable of producing liquefied petroleum gas, gasoline, jet fuel, diesel fuel, heating oil and residual fuel oil. The refinery is designed to process crude oil with a sulphur content of up to 1%. Alaska North Slope ('ANS') and Cook Inlet crude oils, the primary crude oils currently used as feedstock for the refinery, are below this limit. To assure the availability of crude oil to the refinery, the Company has a royalty crude oil purchase contract with the State of Alaska ('State')(see 'Crude Oil Supply' discussed below). During the second quarter of 1993, the Company implemented a market-driven operational strategy for its refining and marketing operations. This strategy includes reducing refinery throughput and upgrading the mix of feedstocks, which is intended to enable the Company to match its refined product yield more closely to the product demand in Alaska, its primary market, and reduce shipments of refined products to less profitable markets. The strategy is also intended to reduce the Company's working capital requirements and reduce the volume of residual fuel oil produced by the Company's Alaska refinery. Implementation of this strategy has resulted in a decrease in total refinery production from 60,900 barrels per day in 1992 to 49,000 barrels per day during 1993, including a decrease in the level of residual fuel oil production from approximately 23,400 barrels per day in 1992 to approximately 17,600 barrels per day during 1993. The Company's ability to further reduce production of residual fuel oil, other than by further reducing total refinery production, is currently limited by the availability of lighter feedstocks and by the configuration of the refinery hardware. There can be no assurance that the new strategy will ultimately prove successful. 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.
In March 1994, the Company's Board of Directors approved the construction of a vacuum processing unit at the refinery. This unit, estimated to cost approximately $24 million, will reduce the amount of residual fuel oil by further processing this product into additional higher-valued products.
During 1993, the refinery processed approximately 72% ANS crude oil, 22% Cook Inlet crude oil and 6% of other refinery feedstocks, which yielded refined products consisting of approximately 25% gasoline, 25% jet fuel, 14% diesel fuel and other distillates and 36% residual fuel oil. Of the refinery production in 1993, the Company distributed approximately 89% of the gasoline to end-users in the State, either by retail sales through 33 of its 7-Eleven convenience store locations, by wholesale sales through 68 branded and 25 unbranded dealers and jobbers or by exchange deliveries to major oil companies, with the remaining 11% being transported to the West Coast. Virtually all of the jet fuel production is marketed in Alaska to commercial airlines through sales or exchange deliveries. Substantially all of the diesel fuel and other distillates production is marketed through exchange deliveries or sales in Alaska. In recent years, sales of residual fuel oil have been increasingly unprofitable. During 1993, under its new marketing strategy, the Company commenced selling and transporting a substantial volume of its residual fuel oil production to customers on the West Coast.
In addition to its own refining capacity, the Company estimates the other refiners in Alaska have the capacity to process approximately 156,000 barrels of crude oil per day, all of which is ANS crude oil. After processing the crude oil and removing the lighter-end products, such as gasoline and jet fuel, which represent approximately 30% of each barrel processed, these refiners are permitted, by paying a fee and because of their proximity to the Trans Alaska Pipeline System, to return the remainder of the processed crude back into the pipeline system as 'return oil.'
During 1993, the production of gasoline by all refiners in Alaska, including the Company, exceeded the market demand by approximately 1,400 barrels per day. The excess production was exported from Alaska, generally during the winter months when the demand for gasoline in Alaska is lowest. The demand for jet fuel in Alaska currently exceeds the production of the refiners in the State, and several marketers, including the Company, import jet fuel into the State to meet this excess demand. The primary market for diesel fuel in Alaska is the commercial fishing fleet. Generally, the production of diesel fuel by refiners in Alaska and the demand for such diesel fuel is in balance; however, because of the high variability of the demand, there are occasions when diesel fuel is imported into or exported from the State. The Company is the only producer in Alaska of residual fuel oil for sale. Since there is no current demand for residual fuel oil in Alaska, the residual fuel oil was exported from the State, primarily to other refiners on the West Coast during 1993, where it was generally used as a refinery feedstock.
The Company conducts domestic wholesale marketing operations primarily in California, Oregon and Washington, with its principal office in Long Beach, California. During 1993, this operation sold approximately 27,800 barrels per day of refined products, of which approximately 30% was received from major oil companies in exchange for refined products from the Company's Alaska refinery, approximately 5% was received directly from the Company's Alaska refinery and the balance was purchased from other suppliers. The Company sells these refined products in the bulk market and through 25 terminal locations, of which four are owned by the Company.
The Company holds an exclusive license agreement for all 7-Eleven convenience stores in Alaska and operates such stores in 39 locations, 33 of which sell Company branded gasoline. During 1993, these convenience stores sold a total of 63,000 gallons of gasoline per day.
The following table summarizes the Company's refinery throughput and product sales for the years ended December 31, 1993, December 31, 1992 and September 30, 1991:
1993 1992 1991 (AVERAGE DAILY BARRELS) Refinery Throughput------------------ 49,753 61,425 68,192 Refining and Marketing Product Sales: Gasoline------------------------- 22,466 25,196 25,883 Jet fuel------------------------- 11,305 19,060 15,055 Other distillates---------------- 18,049 19,253 20,488 Residual fuel oil---------------- 16,945 23,931 28,729 Total------------------------ 68,765 87,440 90,155
CRUDE OIL SUPPLY
The Company has a contract through 1994 with the State which provides for the purchase of certain quantities of the State's Prudhoe Bay North Slope royalty crude oil, based on a percentage of all Prudhoe Bay North Slope royalty crude oil produced. At current levels of Prudhoe Bay production, this contract provides for the purchase of approximately 37,500 barrels per day at the weighted average net-back price of all North Slope producers at Pump Station No. 1. In connection with its anticipated reduction in refinery throughput, effective January 1, 1993, the Company exercised its right under this contract to reduce purchases to approximately 27,500 barrels per day.
The Company's present and certain past contracts with the State contained provisions which would have required the Company to pay the State additional retroactive amounts if the State prevailed in the ANS ROYALTY LITIGATION against the producers of North Slope crude oil ('Producers'). The State settled with each of the Producers, with the last settlement occurring in April 1992. As a result of the settlements between the State and the Producers, the State claimed that the crude oil it sold to the Company and others was undervalued to the extent that the Producers undervalued their oil. The State's claim against the Company amounted to $141.9 million (including interest), of which $44.8 million (the 'Chevron Portion') was reimbursable to the Company under a crude oil purchase/sale agreement with Chevron U.S.A. Inc. ('Chevron').
In January 1993, the Company entered into an agreement with the State ('ANS Agreement') that settled this contractual dispute. The ANS Agreement provided that $97.1 million (which did not include the Chevron Portion) was owed to the State by the Company and that the Company would cooperate with the State in seeking to recover the Chevron Portion. Under the ANS Agreement, the State released the Company from liability for the Chevron Portion.
Under the ANS Agreement, the Company paid the State $10.3 million in January 1993 and agreed to make variable monthly payments to the State over the nine years following the date of the settlement based on a per barrel charge that increases over the nine-year term from 16 cents to 33 cents on the volume of feedstock processed at the Company's Alaska refinery. In 1993, the Company's variable payments to the State totaled $2.6 million. At the end of the nine-year period, the Company is obligated to pay the State $60 million; provided, however, that such payment may be deferred indefinitely by continuing the variable monthly payments to the State beginning at 34 cents per barrel and increasing one cent per barrel annually thereafter. Variable monthly payments made after the nine-year period will not reduce the $60 million obligation to the State. The $60 million obligation is evidenced by a security bond, and the bond and the variable monthly payments are secured by a second mortgage on the Alaska refinery. The Company's obligations under the ANS Agreement and the mortgage may be subordinated to current and future senior debt obligations (including, without limitation, principal, interest and related expenses) of up to $175 million, plus any indebtedness incurred in the future to improve the Alaska refinery. For further information concerning the Company's settlement with the State, see Note I of Notes to Consolidated Financial Statements in Item 8.
Additional ANS crude oil, other than that which is purchased from the State, is acquired by the Company through various purchase and exchange agreements with the Producers. All ANS crude oil is delivered to the refinery by tanker through the Kenai Pipeline Company marine terminal. In addition, the Company obtains available Cook Inlet crude oil, which is delivered by tanker or through an existing pipeline to the refinery. This Cook Inlet crude oil is acquired through term contracts and spot purchases.
From time to time the Company evaluates the economic viability of processing foreign crude oil in its Alaska refinery and occasionally purchases spot quantities to supplement its normal crude oil supply. This foreign crude oil is also delivered to the refinery by tanker through the Kenai Pipeline Company marine terminal.
TRANSPORTATION
The Company charters an American flag vessel, the OVERSEAS WASHINGTON, under an agreement expiring in 1994 with a two-year renewal option. The OVERSEAS WASHINGTON is used primarily to transport North Slope crude oil from the Trans Alaska Pipeline System terminal at Valdez, Alaska to the Company's Alaska refinery. The Company also has a charter for an American flag vessel, the BALTIMORE TRADER, under a six-month agreement expiring in July 1994 with a six-month renewal option remaining. The BALTIMORE TRADER is used primarily to transport residual fuel oil to California and occasionally to transport feedstocks to the Company's Alaska refinery. From time to time, the Company also charters tankers and ocean-going barges to transport petroleum products to its customers within Alaska, on the West Coast and in the Far East.
The Company operates a common carrier petroleum products pipeline from the Company's Alaska refinery to its terminal in Anchorage. This ten-inch diameter pipeline removes the uncertainty of transporting light products in the winter months when icing conditions in the Cook Inlet restrict marine transportation. During 1993, the pipeline transported an average of approximately 22,300 barrels of petroleum products per day, all of which were transported for the Company. The pipeline has a capacity of approximately 40,000 barrels of petroleum products per day.
For further information on transportation in Alaska, see 'Government Regulation and Legislation -- Environmental Controls.'
EXPLORATION AND PRODUCTION
UNITED STATES
During 1993, the Company concentrated its activities in the Bob West Field, which is located in the southern part of the Wilcox Trend, Starr and Zapata Counties, Texas. Continued successful development of this field, discovered in 1990, has resulted in net proven natural gas reserves increasing from 74 billion cubic feet at December 31, 1992 to 120 billion cubic feet at December 31, 1993. Fifteen development wells were drilled and completed in this field during 1993, bringing the number of producing wells to 25 at December 31, 1993 with an additional two wells being drilled and one well awaiting completion at year-end. Thirty-nine additional well locations have been selected for further development of this 4,000 acre field, of which 25 are expected to be drilled during 1994. At 1993 year-end, net production from the Bob West Field wells averaged 58 million cubic feet per day. The Company, which does not operate the field, owns an average 50% revenue interest in approximately two-thirds of the field and a 28% revenue interest in the remainder. The Company owns a 70% interest in the central gas processing facility which is currently capable of handling approximately 120 million cubic feet of production per day. The Company owns a 70% interest in Starr County Gathering System's two ten-inch diameter pipelines which transport gas eight miles from the field to common carrier pipeline facilities. In February 1994, the common carrier pipeline facilities were at capacity and production subject to spot market prices was being curtailed. New common carrier pipeline facilities are being constructed by Coastal States Gas Transmission Company which will provide transportation for increased gas production from the Bob West Field in the second quarter of 1994.
In addition to the continued development of the Bob West Field, during 1993 the Company also participated in the drilling of four exploratory wells in other areas of South Texas. The first exploratory well was completed as a producing gas well, the second was a dry hole and, at December 31, 1993, the third was awaiting completion and has subsequently been evaluated as a gas discovery. The fourth well was still being drilled at 1993 year-end but was subsequently evaluated as a dry hole in January 1994. A delineation well, which was drilling at December 31, 1993 on the acreage where the first exploratory well was drilled, was evaluated as a dry hole in January 1994.
Two producing acreage units within the Bob West Field, each consisting of 352 acres, are subject to a gas purchase contract expiring in January 1999 with Tennessee Gas Pipeline Company ('Tennessee Gas') pursuant to which Tennessee Gas is currently paying in excess of $7.70 per mcf of gas, which is greatly in excess of the spot market price for natural gas ($2.31 per mcf for the month of December 1993). The gas purchase contract is presently the subject of litigation with Tennessee Gas. See Legal Proceedings in Item 3 and Notes K and P of Notes to Consolidated Financial Statements in Item 8.
BOLIVIA
The Company is the operator of a joint venture which holds two Contracts of Operation with YPFB, the Bolivian state-owned oil and gas company. The Company has a 75% interest in a Contract of Operation, which expires in 2007, covering approximately 93,000 acres in Block XVIII. The Company and its joint venture participant are entitled to receive a quantity of hydrocarbons equal to 40% of the total production, net of Bolivian taxes on production. After payment of taxes on production, YPFB is entitled to the remainder. Under the sales contract with YPFB covering hydrocarbons produced from the La Vertiente, Escondido and Taiguati Fields in this block, the Company and its joint venture participant have contracted to sell approximately 18,000 mcf, after Bolivian taxes, of natural gas per day to YPFB. At December 31, 1993, the Company was receiving $1.25 per mcf for gas sold under this contract. This contract, including the pricing provision, is subject to renegotiation in April 1994 for another two-year period. During 1993, the condensate produced in association with the natural gas was sold to YPFB. The Company's natural gas production from Bolivia as presented in 'Operating Statistics' below represents the Company's net production before Bolivian taxes.
The Company has a 72.6% interest in a Contract of Operation, which expires in 2008, covering approximately 1.2 million acres in Block XX. The Company and its joint venture participant are entitled to receive a quantity of hydrocarbons equal to 50% of the total production, net of Bolivian taxes on production, with YPFB receiving the remainder. Prior to 1993, one successful commercial gas discovery well, the Los Suris No. 1, was drilled on the block and is shut-in pending the approval by the Government of Bolivia of a commercialization agreement. A plan of development for Block XX has been approved by YPFB and the Government of Bolivia. Under the plan of development, the Company drilled a well, the Los Suris No. 2, which was completed in February 1994 and tested gross production potential of approximately 9 million cubic feet of gas per day and approximately 120 barrels of condensate per day from two intervals. The Los Suris No. 2 is also shut-in pending the approval of the commercialization agreement. The plan provides that, in order to postpone the relinquishment of inactive acreage until July 15, 1995, the drilling of a second exploratory well must be completed by September 30, 1994, and the drilling of a third exploratory well must be started no later than the fourth quarter of 1994 and completed by April 30, 1995. The Company may further postpone the relinquishment of inactive acreage until July 15, 1996, by submitting no later than July 1, 1995, an additional two-well drilling program that is acceptable to YPFB. To guarantee the drilling of the first three exploratory wells, in July 1993 the Company submitted a bank guarantee in the amount of $2 million to YPFB for the drilling of the first exploratory well and, prior to the January 15, 1994 deadline, the Company submitted bank guarantees to YPFB in the aggregate amount of $4 million for the drilling of the second and third wells. Since the Los Suris No. 2 has now been completed, YPFB has released the first $2 million guarantee.
For further information regarding Tesoro Bolivia, see Note F of Notes to Consolidated Financial Statements in Item 8.
OPERATING STATISTICS
The following table summarizes the Company's exploration and production activities for the years ended December 31, 1993, December 31, 1992 and September 30, 1991. Effective May 1, 1992, the Company sold its Indonesian operations.
[CAPTION] 1993 1992 1991 [S] [C] [C] [C] Net Natural Gas Production (average daily mcf): United States-------------------- 38,767 13,960 7,435 Bolivia-------------------------- 19,232 19,421 19,322 Total------------------------ 57,999 33,381 26,757 Net Crude Oil Production (average daily barrels): Bolivia (condensate)------------- 663 660 663 Indonesia------------------------ -- 2,714 3,315 Total------------------------ 663 3,374 3,978 Average Realized Sales Prices -- Natural Gas (dollars per mcf): United States-------------------- $ 3.55* 3.68* 1.88 Bolivia-------------------------- $ 1.22 1.67 3.06 Average Realized Sales Prices -- Crude Oil (dollars per barrel): Bolivia (condensate)------------- $ 14.26 17.65 21.11 Indonesia------------------------ $ -- 18.20 24.39 Average Production Cost (dollars per net equivalent mcf): United States-------------------- $ .48 .74 .44 Bolivia-------------------------- $ .14 .08 .09 Indonesia------------------------ $ -- 1.94 1.35 Depletion Rates (dollars per net equivalent mcf): United States-------------------- $ .78 .95 1.06 Indonesia------------------------ $ -- .15 .22 Net Exploratory Wells Drilled: United States -- Net productive wells------------- .38 1.00 1.46 Net dry holes-------------------- .50 .50 -- Net Development Wells Drilled: Net productive wells -- United States-------------------- 7.87 3.85 1.43 Indonesia------------------------ -- -- 3.00 Total------------------------ 7.87 3.85 4.43 Net dry holes -- United States-------------------- -- -- 1.00 Indonesia------------------------ -- -- 2.00 Total------------------------ -- -- 3.00
* SEE LEGAL PROCEEDINGS IN ITEM 3 AND NOTE K OF NOTES TO CONSOLIDATED FINANCIAL STATEMENTS IN ITEM 8 REGARDING LITIGATION CONCERNING THE TENNESSEE GAS CONTRACT.
ACREAGE AND WELLS
The following table sets forth the Company's gross and net acreage and productive wells at December 31, 1993:
DEVELOPED UNDEVELOPED ACREAGE ACREAGE ACREAGE (IN THOUSANDS) GROSS NET GROSS NET
United States------------------------ 3 2 11 4 Bolivia------------------------------ 38 29 1,210 880 Total---------------------------- 41 31 1,221 884
OIL GAS GROSS AND NET PRODUCTIVE WELLS GROSS NET GROSS NET
United States------------------------ -- -- 26 14.8 Bolivia------------------------------ -- -- 14 10.5 Total*--------------------------- -- -- 40 25.3
* INCLUDED IN TOTAL PRODUCTIVE WELLS ARE 1 GROSS (.6 NET) WELL IN THE UNITED STATES AND 8 GROSS (6.0 NET) WELLS IN BOLIVIA WITH MULTIPLE COMPLETIONS. AT DECEMBER 31, 1993, THE COMPANY WAS PARTICIPATING IN THE DRILLING OF 6 GROSS (2.3 NET) WELLS IN THE UNITED STATES AND 1 GROSS (.7 NET) WELL IN BOLIVIA.
For further information regarding the Company's exploration and production activities, see Note P of Notes to Consolidated Financial Statements in Item 8.
OIL FIELD SUPPLY AND DISTRIBUTION
WHOLESALE MARKETING OF FUEL AND LUBRICANTS
The Company sells lubricants, fuels and specialty petroleum products primarily to onshore and offshore drilling contractors. The Company's products are sold through six land terminals and 13 marine terminals located in various cities in Texas and Louisiana. These products are used to power and lubricate machinery on drilling and production locations. The Company also provides products for marine, commercial and industrial applications.
ENVIRONMENTAL REMEDIATION PRODUCTS AND SERVICES
The Company's environmental remediation products and services operation continues to experience losses and is being evaluated as to its long-term economic viability.
COMPETITION
The oil and gas industry is highly competitive in all phases, including the refining and marketing of crude oil and petroleum products and the search for and development of oil and gas reserves. This industry also competes with industries that supply the energy and fuel requirements of industrial, commercial, individual and other consumers. The Company competes with a substantial number of major integrated oil companies and other companies having materially greater financial and other resources. These competitors have a greater ability to bear the economic risks inherent in all phases of this industry. In addition, unlike the Company, many competitors also produce large volumes of crude oil which may be used in connection with their operations.
OTHER
A portion of the Company's operations are conducted in foreign countries where the Company is also subject to risks of a political nature and other risks inherent in foreign operations. The Company's operations outside the United States in recent years have been, and in the future may be, materially affected by host governments through increases or variations in taxes, royalty payments, export taxes and export restrictions and adverse economic conditions in the foreign countries, the future effects of which the Company is unable to predict.
GOVERNMENT REGULATION AND LEGISLATION
UNITED STATES
NATURAL GAS REGULATIONS
Historically, all domestic natural gas sold in so-called 'first sales' was subject to federal price regulations under the Natural Gas Policy Act of 1978 (the 'NGPA'), the Natural Gas Act (the 'NGA'), and the regulations and orders issued by the Federal Energy Regulatory Commission (the 'FERC') in implementing such Acts. Under the Natural Gas Wellhead Decontrol Act of 1989, all remaining natural gas wellhead pricing, sales, certificate and abandonment regulation of first sales by the FERC was terminated on January 1, 1993.
The FERC also regulates interstate natural gas pipeline transportation rates and service conditions, which affect the marketing of gas produced by the Company, as well as the revenues received by the Company for sales of such natural gas. Since the latter part of 1985, through its Order Nos. 436, 500 and 636 rulemakings, the FERC has endeavored to make natural gas transportation more accessible to gas buyers and sellers on an open and non-discriminatory basis, and the FERC's efforts have significantly altered the marketing and pricing of natural gas. A related effort has been made with respect to intrastate pipeline operations pursuant to the FERC's authority under Section 311 of the NGPA, under which the FERC establishes rules by which intrastate pipelines may participate in certain interstate activities without becoming subject to full NGA jurisdiction. These Orders have gone through various permutations, but have generally remained intact as promulgated. The FERC considers these changes necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put gas sellers into more direct contractual relations with gas buyers than has historically been the case.
The FERC's latest action in this area, Order No. 636, issued April 8, 1992, reflected the FERC's finding that under the current regulatory structure, interstate pipelines and other gas merchants, including producers, do not compete on an equal basis. The FERC asserted that Order No. 636 was designed to equalize that marketplace. This equalization process is being implemented through negotiated settlements in individual pipeline service restructuring proceedings, designed specifically to 'unbundle' those services (e.g., gathering, transportation, sales and storage) provided by many interstate pipelines so that producers of natural gas may secure services from the most economical source, whether interstate pipelines or other parties. In many instances, the result of the FERC initiatives has been to substantially reduce or bring to an end the interstate pipelines' traditional role as wholesalers of natural gas in favor of providing only gathering, transportation and storage services for others which will buy and sell natural gas. The FERC has issued final orders in all of the individual pipeline restructuring proceedings and all of the interstate pipelines are now operating under new open access tariffs.
Although Order No. 636 does not regulate gas producers, such as the Company, the FERC has stated that Order No. 636 is intended to foster increased competition within all phases of the natural gas industry. It is unclear what impact, if any, increased competition within the natural gas industry under Order No. 636 will have on the Company and its gas marketing efforts. In addition, numerous petitions seeking judicial review of Orders Nos. 636, 636A and 636B and seeking review of FERC's orders approving open access tariffs for the individual pipelines have already been filed. Because the restructuring requirements that emerge from this lengthy process may be significantly different from those of Order No. 636 as originally promulgated, it is not possible to predict what, if any, effect the final rule resulting from Order No. 636 will have on the Company. The Company does not believe, however, it will be affected by any action taken with respect to Order No. 636 any differently than other gas producers and marketers with which it competes.
In late 1993, FERC initiated a proceeding seeking industry-wide comments about its role in regulating natural gas gathering performed by interstate pipelines or their affiliates. Numerous written and oral comments have been received by the FERC concerning whether and how it should
regulate gathering activities, but the Company cannot predict what, if any, action the FERC may take or whether such action will affect access to markets of its gas or its own gas gathering facilities and activities.
The oil and gas exploration and production operations of the Company are subject to various types of regulation at the state and local levels. Such regulation includes requiring drilling permits and the maintenance of bonds in order to drill or operate wells; the regulation of the location of wells, the method of drilling and casing of wells and the surface use and restoration of properties upon which wells are drilled; and the plugging and abandoning of wells. The operations of the Company are also subject to various conservation regulations, including regulation of the size of drilling and spacing units or proration units, the density of wells that may be drilled in a given area and the unitization or pooling of oil and gas properties. In this regard, some states allow the forced pooling or integration of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of crude oil, condensate and natural gas the Company can produce from its wells and the number of wells or the locations at which the Company can drill.
More recently, the enactment of the North American Free Trade Agreement has further streamlined and simplified procedures for the importation and exportation of gas between and among Mexico, the United States and Canada. These changes could provide additional opportunities to export gas to Mexico, but will more likely enhance the ability of Canadian and Mexican producers to export natural gas to the United States, thereby increasing competition in the domestic natural gas market.
Additional proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, the FERC, state regulatory bodies and the courts. The Company cannot predict when or if any such proposals might become effective, or their effect, if any, on the Company's operations. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue indefinitely into the future.
ENVIRONMENTAL CONTROLS
Federal, state, area and local laws, regulations and ordinances relating to the protection of the environment affect all operations of the Company to some degree. One example of a federal environmental law that would 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 may be required to comply with new requirements being adopted and to be promulgated by the U.S. Environmental Protection Agency (the 'EPA') and the states in which the Company operates. These regulations may necessitate the installation of additional controls or other modifications or changes in use for certain emission sources. At this time, the Company cannot estimate when new standards will be imposed by the EPA or relevant state agencies or what technologies or changes in processes the Company may have to install or undertake to achieve compliance with any applicable new requirements.
The passage of the federal Clean Air Act Amendments of 1990 prompted adoption of regulations by the State obligating the Company to produce oxygenated gasoline for delivery to the Anchorage and Fairbanks, Alaska markets starting on November 1, 1992. Controversies surrounding the potential health effects in arctic regions of oxygenated gasoline containing methyl tertiary butyl ether ('MTBE') prompted the early discontinuance of the program in Fairbanks in December 1992. On October 21, 1993, the United States Congress granted the State one additional year of exemption from requiring the use of oxygenated gasoline. However, state and local officials may still require the use of these fuels at their option. In addition, the EPA has been directed to conduct additional studies
of potential health effects of oxygenated fuel in Alaska. Additional federal regulations promulgated on August 21, 1990, and scheduled to go into effect on October 1, 1993, set limits on the quantity of sulphur in on-highway diesel fuels which the Company produces. The State filed an application with the federal government in February 1993 for a waiver from this requirement since only 5% of the diesel fuel sold in Alaska is for on-highway vehicles. The EPA supported the State's position and the formalities for obtaining the exemption were completed on September 27, 1993. The EPA, in a letter to the State dated September 30, 1993, indicated that the EPA was completing the final documentation regarding the waiver and that Alaska would have a low priority for enforcement of the diesel fuel regulations, pending the publication of the final decision. The Company estimates that substantial capital expenditures would be required to enable the Company to produce low-sulphur diesel fuel to meet these federal regulations. If the State is unable to obtain a waiver from the federal regulations, the Company would discontinue the sales of diesel fuel for on-highway use. The Company estimates that such sales accounted for less than 1% of its refined product sales in Alaska during 1993. The Company is unable to predict the outcome of these matters; however, the Company believes that the ultimate resolution of these matters will not have a material impact on the Company's operations.
Regulations promulgated by the EPA on September 23, 1988, require that all underground storage tanks used for storing gasoline or diesel fuel either be closed or upgraded not later than December 22, 1998, in accordance with standards set forth in the regulations. The Company's service stations subject to the upgrade requirements are limited to locations within the State of Alaska, the majority of which are located in non-residential areas. Although the Company continues to monitor, test and make physical improvements in its current operations which result in a cleaner environment, the Company was not required to make any material capital expenditures for environmental control purposes during 1993. The Company may be required to make significant expenditures for removal or upgrading of underground storage tanks at several of its current and former service station locations by December 22, 1998; however, the Company does not expect to make any material capital expenditures for such purposes during 1994 and 1995 and does not expect that such expenditures subsequent to 1995 will have a material adverse effect on the financial condition of the Company. See Legal Proceedings, Item 3(e).
The Company currently charters a vessel to transport crude oil from the Valdez, Alaska pipeline terminal through Prince William Sound and Cook Inlet to its Alaska refinery. In addition, the Company routinely charters, on a term or spot basis, additional tankers and barges for the shipment of crude oil and refined products through Cook Inlet. The Federal Oil Pollution Act of 1990 requires, as a condition of operation, that the Company submit an oil spill contingency plan for its Alaska refinery terminal facility located on Cook Inlet that demonstrates the capability to respond to the 'worst case discharge' to the maximum extent practicable. Alaska law requires a contingency plan for that terminal providing for containment or control, and cleanup, within 72 hours, of a spill equal to the volume of the terminal's largest storage tank. With respect to the charter vessels employed by the Company to transport crude oil through Prince William Sound and Cook Inlet to the Company's Alaska refinery, federal and Alaska law both require contingency plans as a condition of navigation. The Company has obtained State approval for its Cook Inlet Oil Discharge Contingency Plan and conditional approval, which allows operations pending final State review, for a Tanker Spill Prevention and Response Plan for Prince William Sound. The federal plan must demonstrate the capability to respond to the 'worst case discharge' to the maximum extent practicable, while the Alaska plan must be based on containment or control, and cleanup, of a 50,000 barrel discharge within 72 hours. To meet those standards, the Company has entered into a contract with Alyeska Pipeline Service Company ('Alyeska') to provide the initial spill response services in Prince William Sound with the Company to assume those responsibilities after mutual agreement with Alyeska and the State and Federal On-Scene Spill Response Coordinators. The Alaska legislature passed legislation in 1992, providing limited immunity for spill response contractors, which has facilitated access to contract extensions that will not be dependent on further legislative action. The Company has also entered into an agreement with Cook Inlet Spill Prevention & Response Inc. for oil spill response services in
Cook Inlet. The Company believes these contracts provide the additional services necessary to meet the spill response requirements established by Alaska and federal law.
For further information regarding environmental matters, see Legal Proceedings in Item 3.
BOLIVIA
The Company's operations in Bolivia are subject to the Bolivian General Law of Hydrocarbons and various other laws and regulations. The General Law of Hydrocarbons imposes certain limitations on the Company's ability to conduct its operations in Bolivia. In the Company's opinion, neither the General Law of Hydrocarbons nor other limitations imposed by governmental laws, regulations and practices will have a material adverse effect upon its Bolivian operations.
TAXES
UNITED STATES
The Revenue Reconciliation Act of 1993 imposed a new 4.3 cents per gallon 'transportation fuels tax' effective October 1, 1993, and a tax on commercial aviation fuel effective October 1, 1995. The Company does not believe such taxes will have a material adverse effect on the Company's future operations.
BOLIVIA
The Company is subject to Bolivian taxation at the rate of 30% of the gross production of hydrocarbons at the wellhead which is retained and paid by YPFB for the Company's account. In 1987, the Bolivian General Corporate Income Tax Law was replaced by a tax system, including a Value Added Tax, which is not imposed on net income. As a result, it is uncertain whether or not the Company can treat the Bolivian hydrocarbons tax as creditable in the United States for federal income tax purposes. However, due to the Company's net operating loss carryforwards, the Company does not now, or in the near future, expect to use these taxes as credits for federal income tax purposes.
In 1990, the Bolivian Government passed a new General Law of Hydrocarbons containing provisions designed to ensure the creditability, for United States federal income tax purposes, of these hydrocarbon taxes if the Company makes an election which may subject it to a higher Bolivian tax rate in the future. Regulations under this new law have not been issued; however, the Company does not anticipate that this new law will have a material effect on the Company's Bolivian operations.
EMPLOYEES
As of December 31, 1993, the Company employed approximately 900 persons, of which approximately 40 employees are located in foreign countries. None of the Company's employees are represented by a union for collective bargaining purposes. The Company considers its relations with its employees to be satisfactory.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following is a list of the Company's executive officers, their ages and their positions with the Company as of March 1, 1994.
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 his successor shall have been elected or shall have qualified.
All of the Company's executive officers have been employed by the Company or its subsidiaries in an executive capacity for at least the past five years, except for those named below who have had the business experience indicated during that period. Positions, unless otherwise specified, are with the Company.
ITEM 2.
ITEM 2. PROPERTIES
See information appearing under Item 1, Business herein and Schedules V and VI of Financial Statement Schedules in Item 14.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
(a) The Company is selling gas from its Bob West Field to Tennessee Gas under a 1979 Gas Purchase and Sales Agreement ('Gas Contract') which expires in January 1999. The Gas Contract provides that the price of gas shall be the maximum price as calculated in accordance with the then effective Section 102 (b) (2) ('Contract Price') of the NGPA.
In August 1990, Tennessee Gas filed a civil action in the District Court of Bexar County, Texas against the Company and several other companies, seeking a Declaratory Judgment that the Gas Contract is not applicable to the Company's properties. Tennessee Gas claimed, among other things, that certain leases covered by the Gas Contract had terminated and therefore were automatically released from the Gas Contract, eliminating the obligation of Tennessee Gas to purchase gas from the Company. Tennessee Gas also challenged the quantity of gas which can be sold under the Gas Contract and contended that the gas sales price was to be calculated under the provisions of Section 101 of the NGPA rather than the Contract Price. At December 31, 1993, the Section 101 price of $5.01 per mcf was $2.71 per mcf less than the Contract Price, but $2.75 per mcf above spot market prices.
On June 24, 1992, the District Court trial judge returned a verdict in favor of the Company. The District Court's judgment, entered on July 8, 1992, ruled that Tennessee Gas must honor the Gas Contract pursuant to its terms. Tennessee Gas filed a motion for reconsideration in the District Court on the issue of the price to be paid for the gas under the Gas Contract, which was denied by the court. On September 11, 1992, Tennessee Gas appealed the judgment to the Court of Appeals for the Fourth Supreme Judicial District of Texas. On August 25, 1993, the Court of Appeals affirmed the validity of the Gas Contract as to the Company's properties and held that the price payable by Tennessee Gas for the gas was the Contract Price. The Court of Appeals determined, however, (i) that the trial court erred in its summary judgment ruling that the Gas Contract was not an output contract under the Texas Business and Commerce Code ('TBCA') and (ii) that a fact issue exists as to whether the increases in the volumes of gas tendered to Tennessee Gas under the Gas Contract were made in bad faith or were unreasonably disproportionate to prior tenders in contravention of the provisions of Section 2.306 of the TBCA. Accordingly, the Court of Appeals directed that this issue be remanded to the trial court in Bexar County, Texas. The Company filed a motion for
rehearing with the appellate court regarding its decision that the Gas Contract creates an output contract governed by the TBCA. Tennessee Gas also filed a motion for rehearing with the appellate court regarding the portions of its decision upholding the judgment of the trial court. On January 26, 1994, the appellate court rendered its judgment denying all motions for rehearing in this matter and affirming its earlier ruling. The Company has appealed the appellate court ruling on the output contract issue to the Supreme Court of Texas. Tennessee Gas has also appealed to the Supreme Court of Texas that portion of the appellate court ruling denying the remaining Tennessee Gas claims. If the Supreme Court of Texas does not grant the Company's petition for writ of error and affirms the appellate court ruling, then the only issue for trial will be whether the increases in the volumes of gas tendered to Tennessee Gas from the Company's properties may have been made in bad faith or were unreasonably disproportionate. Management of the Company believes its tenders were reasonable under the Gas Contract and the market conditions at the time and will vigorously defend on this issue if put to trial. The Company continues to receive payment from Tennessee Gas based on the Contract Price.
Although the outcome of any litigation is uncertain, management believes that the Tennessee Gas claims are without merit and, based upon advice from outside legal counsel, is confident that the decision of the trial court will ultimately be upheld as to the validity of the Gas Contract and the Contract Price; and that with respect to the output contract issue, the Company believes that, if this issue is tried, the development of its gas properties and the resulting increases in volumes tendered to Tennessee Gas will be found to have been reasonable and in good faith. Accordingly, the Company has recognized revenues, net of production taxes and marketing charges, for natural gas sales through December 31, 1993, under the Gas Contract based on the Contract Price, which net revenues aggregated $16.8 million more than the Section 101 prices and $31.0 million in excess of the spot market prices. An adverse judgment in this case could have a material adverse effect on the Company. If Tennessee Gas ultimately prevails in this litigation, the Company could be required to return to Tennessee Gas $31.0 million, excluding any interest that may be awarded by the court, representing the difference between the spot price for gas and the Contract Price.
(b) In March 1991, the Company entered into a Consent Order with the Alaska Department of Environmental Conservation ('ADEC'), substantially similar to the Consent Orders reached with the EPA in September 1989. These Consent Orders provide for the investigation and cleanup of hydrocarbons in the soil and groundwater at the Company's Alaska refinery which resulted from sewer hub seepage associated with the underground oil/water sewer system. The Consent Orders formalized efforts, which commenced in 1987, to remedy the presence of hydrocarbons in the soil and groundwater and provide for the performance of additional future work. The Company has replaced or rebuilt the drainage hubs and has initiated a subsurface monitoring and interception system designed to identify the extent of hydrocarbons present in the groundwater and to remove the hydrocarbons. The Company estimates that annual expenditures of approximately $1.5 million will be required in the future to operate these subsurface monitoring and interception systems, the majority of which will be covered by insurance through 1995.
(c) In March 1992, the Company received a Compliance Order and Notice of Violation ('Notice') from the EPA alleging possible violations by the Company of the New Source Performance Standards under the Clean Air Act at its Alaska refinery. The Notice alleges that the Company (i) failed to install a fuel gas combustion monitoring device by October 2, 1991; (ii) failed to keep documentation on two storage vessels reflecting quantities of petroleum liquid stored, the period of storage and the maximum true vapor pressure of the liquid stored; (iii) failed to submit documentation on two gas turbines (a) verifying the accuracy of the monitoring system for recording fuel consumption and ratio of fuel to water being fired in the
turbines and (b) monitoring sulphur and nitrogen content of the fuel being fired in the turbines; (iv) failed to conduct a monitoring and repair program under the Standards for Equipment Leaks of Volatile Organic Compounds with respect to one of the refinery units; and (v) failed to (a) equip the Company's south bulk gasoline terminal with a vapor recovery system, (b) assure the loading of liquid products into tanks with a compatible vapor collection system, and (c) conduct performance tests and submit subsequent written reports to the EPA to determine compliance with vapor collection systems installed at the Company's south bulk terminal. The EPA has the statutory authority to assess civil penalties for the alleged violations of up to $25,000 per day for each violation, but the EPA has not assessed a penalty against the Company for its alleged violations to date. The Company is continuing in its efforts to resolve these issues with the EPA; however, no final resolution has been reached. The Company believes that the ultimate resolution of this matter will not have a material adverse effect upon the Company's business or financial condition.
(d) The Company has been identified by the EPA as a potentially responsible party ('PRP') pursuant to the Comprehensive Environmental Response, Compensation and Liability Act ('CERCLA') for the D.L. Mud, Inc. ('Mud') and Gulf Coast Vacuum Services ('Gulf Coast') Superfund sites in Abbeville, Louisiana. These sites are contiguous and at one time were owned by the same company. Over 100 parties have been identified as PRPs for these sites. The Company arranged for the disposal of a minimal amount of materials at these locations. CERCLA imposes joint and several liability on PRPs; each PRP is therefore responsible for 100% of the costs of the response actions necessary to remediate the sites in the event a settlement with the EPA cannot be reached. The EPA is seeking reimbursement for its response costs incurred to date at each site, as well as a commitment from PRPs either to conduct future remedial activities or to finance such activities.
The EPA has completed its investigation of the Gulf Coast site to determine the type and extent of contamination. The EPA issued the Record of Decision and sent out notice letters to PRPs. The Company has entered into a DE MINIMIS settlement with the EPA at the Gulf Coast site. The Company's total liability under the settlement was $2,500.
One of the larger PRPs in the Mud site has taken the lead in investigating the site to determine the extent of contamination. Initial technical reports have been reviewed by the EPA and are undergoing further preparation; however, the reports are not yet available. At this time, the Company is unable to determine the extent of the Company's liability related to the Mud site; however, based on its settlement in the Gulf Coast site, the Company believes that the aggregate amount of such liability, if any, would not have a material adverse effect on the Company.
(e) In September 1990, the Company was identified by the Department of Environmental Resources of Stanislaus County, California ('DER') as a responsible party for hydrocarbon contamination present at a service station location formerly leased and operated by the Company. In February 1993, the DER demanded that the Company and three other entities named as responsible parties undertake action to remediate the contamination. The owner of the location, Briggsmore Plaza Co. ('Briggsmore'), instituted litigation in the California state court seeking compensation from the Company for damages resulting from the contamination. Also named as a defendant was a third party which became the operator of the service station in 1985, and which filed for protection under the federal bankruptcy laws a short time after the lawsuit commenced. In November 1993, a settlement agreement was entered into by the Company and Briggsmore, which provides that the Company will assume responsibility for the management and expense of remediating the location in accordance with DER requirements. It is estimated that remediation to closure will cost the Company $300,000 to $500,000. In addition, the Company has agreed to pay Briggsmore approximately $48,000,
representing past-due rent and property taxes. Briggsmore has released all claims against the Company except the remediation obligations arising under the settlement agreement.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND
RELATED STOCKHOLDER MATTERS
Common stock market prices are included in Note O of Notes to Consolidated Financial Statements in Item 8. The principal markets on which the Company's Common Stock is traded are the New York Stock Exchange and the Pacific Stock Exchange.
In February 1994, all of the Company's outstanding shares of $2.16 Preferred Stock were reclassified into 6,465,859 shares of Common Stock and the holder of the Company's $2.20 Preferred Stock was issued 1,900,075 shares of Common Stock, all pursuant to the Recapitalization. See Management's Discussion and Analysis of Financial Condition and Results of Operations in Item 7 and Note B of Notes to Consolidated Financial Statements in Item 8 for the pro forma effects of the Recapitalization on Common Stock and Other Stockholders' Equity.
As of March 1, 1994, after the Recapitalization, there were approximately 3,800 holders of record of the Company's 22,456,055 outstanding shares of Common Stock. The Company discontinued paying dividends on Common Stock at the end of fiscal 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.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The selected consolidated financial data should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations in Item 7
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
CAPITAL RESOURCES AND LIQUIDITY
In 1993, the Company achieved significant improvement in profitability resulting primarily from the implementation of a market-driven operational strategy along with favorable industry conditions in its refining and marketing segment; higher natural gas production resulting from concentration on the development of the Bob West Field; and a reduction of general and administrative expenses. The improvement in profitability together with the completion of a recapitalization plan during February 1994, as discussed below, have improved the Company's liquidity and enhanced its capital resources.
During February 1994, the Company completed a plan of recapitalization (the 'Recapitalization'), the purpose of which was to improve the Company's short-term and long-term liquidity and increase the Company's equity capital. The Recapitalization, which deferred $44 million of debt service requirements and increased stockholders' equity by approximately $80 million, has provided the Company greater financial flexibility to meet its near-term capital expenditure programs and finance working capital, which are expected to further enhance the Company's operating results.
Significant components of the Recapitalization, which will be recorded in February 1994, are as follows:
* 12 3/4% Subordinated Debentures ('Subordinated Debentures') in the principal amount of $44.1 million were tendered in exchange for a like amount of new 13% Exchange Notes ('Exchange Notes'), which will satisfy approximately four years of sinking fund requirements for the Subordinated Debentures. The Exchange Notes bear interest at 13% and will mature on December 1, 2000.
* The 1,319,563 outstanding shares of $2.16 Cumulative Convertible Preferred Stock ('$2.16 Preferred Stock') of the Company, together with accrued and unpaid dividends of $9.5 million at February 9, 1994, were reclassified into 6,465,859 shares of Common Stock of the Company. The Company also agreed to issue 131,956 shares of Common Stock on behalf of the holders of $2.16 Preferred Stock to pay certain of their legal fees and expenses in connection with the settlement of litigation.
* The agreement between the Company and MetLife Security Insurance Company of Louisiana ('MetLife'), the holder of all the Company's outstanding $2.20 Cumulative Convertible Preferred Stock ('$2.20 Preferred Stock'), was amended with regard to such preferred shares to waive all existing mandatory redemption requirements, to consider all accrued and unpaid dividends thereon (aggregating approximately $21.2 million as of February 9, 1994) to have been paid, to allow the Company to pay future dividends in Common Stock in lieu of cash, to waive or refrain from exercising other rights of the $2.20 Preferred Stock and to grant to the Company an option to purchase during the next three years all shares of the $2.20 Preferred Stock and Common Stock held by MetLife for approximately $53 million (amount at February 9, 1994, increasing by 12% to 14% annually), all in consideration for, among other things, the issuance by the Company to MetLife of 1,900,075 shares of Common Stock. Such additional shares will be subject to the option granted by MetLife. The Company will be required to pay dividends when due on the $2.20 Preferred Stock in order for the option to remain outstanding.
The following table presents the capitalization of the Company as of December 31, 1993 as reported and on a pro forma basis assuming the Recapitalization had occurred on that date (in millions):
DECEMBER 31, 1993 AS REPORTED PRO FORMA
Long-Term Debt and Other Obligations, Including Current Portion----------- $ 185.5 189.7 $2.20 Preferred Stock (Redeemable)----------------------- 78.1 -- Common Stock and Other Stockholders' Equity----------------------------- 58.5 137.7 Total Capitalization------------- $ 322.1 327.4 Ratio of Long-Term Debt and Redeemable Preferred Stock to Total Capitalization--------------------- 82% 58%
For further information regarding the pro forma effects of the Recapitalization, refer to Note B of Notes to Consolidated Financial Statements in Item 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEPENDENT AUDITORS' REPORT
Board of Directors and Stockholders Tesoro Petroleum Corporation
We have audited the accompanying consolidated balance sheets of Tesoro Petroleum Corporation and subsidiaries as of December 31, 1993 and 1992, and the related consolidated statements of operations, common stock and other stockholders' equity and cash flows for the years ended December 31, 1993, December 31, 1992 and September 30, 1991 and for the three-month period ended December 31, 1991. Our audits also included the consolidated financial statement schedules listed in the Index at Item 14. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules 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, 1993 and 1992, and the results of their operations and their cash flows for the years ended December 31, 1993, December 31, 1992 and September 30, 1991 and for the three-month period ended December 31, 1991, in conformity with generally accepted accounting principles. Also, in our opinion, such consolidated financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.
As discussed in Note A of Notes to Consolidated Financial Statements, in 1992 the Company changed its methods of accounting for postretirement benefits other than pensions and accounting for income taxes.
DELOITTE & TOUCHE
San Antonio, Texas February 10, 1994
TESORO PETROLEUM CORPORATION STATEMENTS OF CONSOLIDATED OPERATIONS (DOLLARS IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
The accompanying notes are an integral part of these consolidated financial statements.
TESORO PETROLEUM CORPORATION CONSOLIDATED BALANCE SHEETS (DOLLARS IN THOUSANDS)
DECEMBER 31, 1993 1992 ASSETS Current Assets: Cash and cash equivalents (includes restricted cash of $25,420 in 1993 as collateral for letters of credit)--------- $ 36,596 46,869 Short-term investments----------- 5,952 20,021 Receivables, less allowance for doubtful accounts of $2,487 ($2,587 in 1992)--------------- 69,637 77,173 Inventories: Crude oil, refined products and merchandise------------ 71,011 70,875 Materials and supplies------- 3,175 3,636 Prepaid expenses and other------- 10,136 9,803 Total Current Assets--------- 196,507 228,377 Property, Plant and Equipment: Refining and marketing----------- 282,286 275,213 Exploration and production, full-cost method of accounting: Properties being amortized------------------ 74,684 45,182 Properties not yet evaluated------------------ 1,959 1,482 Oil field supply and distribution------------------- 15,413 16,365 Corporate------------------------ 11,121 10,431 385,463 348,673 Less accumulated depreciation, depletion and amortization----- 172,312 150,191 Net Property, Plant and Equipment------------------ 213,151 198,482 Other Assets: Investment in Tesoro Bolivia Petroleum Company-------------- 6,310 2,786 Other---------------------------- 18,554 17,077 Total Other Assets----------- 24,864 19,863 $ 434,522 446,722
The accompanying notes are an integral part of these consolidated financial statements.
TESORO PETROLEUM CORPORATION CONSOLIDATED BALANCE SHEETS (DOLLARS IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
DECEMBER 31, 1993 1992 LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities: Accounts payable----------------- $ 43,192 49,120 Accrued liabilities-------------- 24,017 30,387 Current portion of long-term debt and other obligations---------- 4,805 26,287 Total Current Liabilities---- 72,014 105,794 Other Liabilities-------------------- 45,272 43,107 Long-Term Debt and Other Obligations, Less Current Portion--------------- 180,667 175,461 Commitments and Contingencies (Note K) $2.20 Redeemable Cumulative Convertible Preferred Stock and Accrued Dividends; $1 stated value; 2,875,000 shares issued and outstanding; redemption and liquidation value of $78,056 ($71,731 in 1992)------------------ 78,051 71,695 Common Stock and Other Stockholders' Equity: Preferred stock, no par value; authorized 5,000,000 shares including redeemable preferred shares: $2.16 Cumulative convertible preferred stock; $1 stated value; 1,319,563 shares issued and outstanding; liquidation value of $42,134 ($39,283 in 1992)---------------------- 1,320 1,320 Common stock, par value $.16 2/3; authorized 50,000,000 shares; 14,089,236 shares issued and outstanding (14,071,040 in 1992)-------------------------- 2,348 2,345 Additional paid-in capital------- 86,985 86,992 Retained earnings (deficit)------ (31,898) (39,647) 58,755 51,010 Less deferred compensation------- 237 345 58,518 50,665 $ 434,522 446,722
The accompanying notes are an integral part of these consolidated financial statements.
TESORO PETROLEUM CORPORATION STATEMENTS OF CONSOLIDATED COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY (DOLLARS IN THOUSANDS)
TESORO PETROLEUM CORPORATION STATEMENTS OF CONSOLIDATED CASH FLOWS (DOLLARS IN THOUSANDS)
TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE A -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION AND PRESENTATION
The Consolidated Financial Statements include the accounts of Tesoro Petroleum Corporation and its subsidiaries (collectively the 'Company' or 'Tesoro') after elimination of significant intercompany balances and transactions. Certain prior period amounts have been reclassified to conform with the 1993 presentation.
Effective January 1, 1992, the Company changed its fiscal year-end from September 30 to December 31. Unless otherwise indicated, the information contained herein addresses the Company's results of operations for the year ended December 31, 1993, compared to the year ended December 31, 1992 and the year ended September 30, 1991 and its financial condition as of December 31, 1993 and December 31, 1992. The results of operations for the three-month period ended December 31, 1991 are discussed separately.
CASH AND CASH EQUIVALENTS AND SHORT-TERM INVESTMENTS
The Company considers all highly liquid investments purchased with a maturity of three months or less to be cash equivalents. During 1992, the Company began investing in short-term debt securities with original maturities in excess of 90 days. These investments are classified as short-term investments in the Company's Consolidated Balance Sheets. Cash equivalents and short-term investments are stated at cost, which approximates market value. For information regarding restricted cash, see Note I.
INVENTORIES
The Company follows the lower of cost (last-in, first-out basis -- LIFO) or market method for valuing inventories of crude oil and wholesale refined products. All other inventories are valued principally at the lower of cost (generally on a first-in, first-out or weighted average basis) or market.
FUTURES AND OPTIONS HEDGE CONTRACTS
The Company uses commodity futures and options contracts primarily to hedge the impact of price fluctuations on anticipated purchases of crude oil. Gains and losses on commodity futures and options hedge contracts are deferred until recognized in income when the related crude oil is charged to costs of sales.
PROPERTY, PLANT AND EQUIPMENT
The Company uses the full-cost method of accounting for oil and gas properties. Under this method, all costs associated with property acquisition and exploration and development activities are capitalized into cost centers that are established on a country-by-country basis. For each cost center, the capitalized costs are subject to a limitation so as not to exceed the present value of future net revenues from estimated production of proved oil and gas reserves net of income tax effect plus the lower of cost or estimated fair value of unproved properties included in the cost center. Capitalized costs within a cost center, together with estimates of costs for future development, dismantlement and abandonment, are amortized on a unit-of-production method using the proved oil and gas reserves for each cost center. The Company's investment in certain oil and gas properties is excluded from the amortization base until the properties are evaluated. No gain or loss is recognized on the sale of oil and gas properties except in the case of the sale of properties involving significant remaining reserves. Proceeds from the sale of insignificant reserves and undeveloped properties are applied to reduce the costs in the cost centers.
TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
Assets recorded under capital leases have been capitalized in accordance with promulgations from the Financial Accounting Standards Board. Amortization of such assets is recorded over the shorter of lease terms or useful lives under methods which are consistent with the Company's depreciation policy for owned assets.
Depreciation of other property is provided using primarily the straight-line method with rates based on the estimated useful lives of the properties and with an estimated salvage value of 20% for refinery assets and generally 10% for other assets. Amortization of leasehold improvements is provided using the straight-line method over the term of the respective lease or the useful life of the asset, whichever period is less.
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
The Company accounts for postretirement benefits other than pensions in accordance with Statement of Financial Accounting Standards No. 106, 'Employers' Accounting for Postretirement Benefits Other Than Pensions' ('SFAS No. 106'). The projected future cost of providing postretirement benefits other than pensions, such as health care and life insurance, are expensed as employees render service instead of when benefits are paid. Prior to the adoption of SFAS No. 106, the Company had expensed these benefits on a pay-as-you-go basis. The adoption of SFAS No. 106, effective January 1, 1992, resulted in a net charge of $21.6 million, or $1.54 per share, for the cumulative effect of the change in accounting principle for periods prior to 1992, which were not restated. In addition, the adoption of SFAS No. 106 resulted in an increase of $1.2 million, or $.09 per share, in the 1992 net loss before cumulative effect of accounting changes.
INCOME TAXES
The Company accounts for income taxes in accordance with Statement of Financial Accounting Standards No. 109, 'Accounting for Income Taxes' ('SFAS No. 109'). Deferred tax assets and liabilities are recognized for future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Measurement of deferred tax assets and liabilities is based on enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Under SFAS No. 109, the effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. The Company adopted SFAS No. 109 effective January 1, 1992 by recognizing a net benefit of $1.0 million, or $.07 per share, for the cumulative effect of the accounting change. Periods prior to 1992 were not restated. The adoption of SFAS No. 109 did not have a significant effect on 1992 results of operations.
ENVIRONMENTAL EXPENDITURES
Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and which do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or remedial efforts are probable, and the cost can be reasonably estimated. Generally, the timing of these accruals coincides with completion of a feasibility study or the Company's commitment to a formal plan of action.
DEFERRED COMPENSATION
Deferred compensation represents the excess of market value over the sales price of restricted common stock awarded to certain employees of the Company. The deferred compensation is being amortized over the period from the date of award to the dates the shares become unrestricted (the period for which the payment for services is being made).
TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
EARNINGS (LOSS) PER SHARE
Primary earnings (loss) per share is calculated on net earnings (loss) after deducting dividend requirements on preferred stocks and is based on the weighted average number of common and common equivalent shares outstanding during the period. Fully diluted earnings (loss) per share is the same as primary earnings (loss) per share since the assumed conversion of preferred stocks to common shares would be anti-dilutive.
NOTE B -- SUBSEQUENT EVENT -- RECAPITALIZATION
In February 1994, the Company consummated exchange offers and adopted amendments to its Restated Certificate of Incorporation pursuant to which the Company's outstanding debt and preferred stock were restructured (the 'Recapitalization'). The objectives of the Recapitalization were to improve the Company's financial condition, facilitate the development of long-term financing and allow the Company to execute its strategy for further improving its refining and marketing operations and accelerating the development of its South Texas natural gas field.
The significant components of the Recapitalization, together with the applicable accounting effects, are as follows:
* The Company offered to exchange up to $54.5 million aggregate principal amount of new 13% Exchange Notes ('Exchange Notes') due December 1, 2000 for a like amount of 12 3/4% Subordinated Debentures ('Subordinated Debentures') due March 15, 2001. Holders of $44.1 million principal amount of Subordinated Debentures accepted this offer resulting in the issuance of $44.1 million of Exchange Notes. This exchange will satisfy approximately four years of sinking fund requirements of the Subordinated Debentures.
The exchange of the Subordinated Debentures will be accounted for as an early extinguishment of debt in the first quarter of 1994 and the Company will recognize a charge of $4.8 million as an extraordinary loss on this transaction, representing the excess of the estimated market value of the Exchange Notes over the carrying value of the Subordinated Debentures. The carrying value of the Subordinated Debentures exchanged has been reduced by applicable unamortized debt issue costs. No tax benefit is available to offset the extraordinary loss as the Company has provided a 100% valuation allowance to the extent of its deferred tax assets.
* Each outstanding share of the Company's $2.16 Cumulative Convertible Preferred Stock ('$2.16 Preferred Stock'), which has a $25 per share liquidation preference plus accrued and unpaid dividends aggregating $9.5 million at February 9, 1994, was reclassified into 4.9 shares of the Company's Common Stock resulting in the issuance of 6,465,859 of the Company's Common Stock in 1994. In addition, the Company agreed to issue .1 share of Common Stock for each share of $2.16 Preferred Stock, or an aggregate of 131,956 shares of Common Stock, on behalf of the holders of $2.16 Preferred Stock to pay certain of their legal fees and expenses in connection with the settlement of litigation.
The issuance of the Common Stock in connection with the reclassification and settlement of litigation will be recorded in 1994 as an increase of approximately $1 million in Common Stock equal to the aggregate par value of the Common Stock to be issued and an increase in Additional Paid-In Capital of approximately $9 million.
* The agreement between the Company and MetLife Security Insurance Company of Louisiana ('MetLife'), the holder of the Company's outstanding $2.20 Cumulative Convertible Preferred Stock ('$2.20 Preferred Stock'), was amended with regard to the $2.20 Preferred Stock to waive all existing mandatory redemption requirements, to consider all accrued and unpaid dividends thereon (aggregating $21.2 million at February 9, 1994) to have been paid, to allow
TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED the Company to pay future dividends on such Preferred Stock in Common Stock in lieu of cash, to waive or refrain from exercising other rights of the $2.20 Preferred Stock, and to grant to the Company an option to purchase, during the next three years, all shares of the $2.20 Preferred Stock and Common Stock held by MetLife for approximately $53 million (amount at February 9, 1994, increasing by 12% to 14% annually), all in consideration for, among other things, the issuance by the Company to MetLife of 1,900,075 shares of Common Stock. Such additional shares will be subject to the option granted by MetLife. These actions have resulted in the reclassification of the $2.20 Preferred Stock into equity capital at its aggregate liquidation preference of $57.5 million and the recording of an increase in Additional Paid-In Capital of approximately $21 million in February 1994.
The following table presents the capitalization of the Company as of December 31, 1993 as reported and on a pro forma basis assuming the Recapitalization had occurred on that date (in millions):
DECEMBER 31, 1993 AS REPORTED PRO FORMA (UNAUDITED) Long-Term Debt and Other Obligations, Including Current Portion: Subordinated Debentures---------- $ 98.2 58.3 Exchange Notes------------------- -- 44.1 Liability to State of Alaska----- 61.7 61.7 Liability to Department of Energy------------------------- 13.2 13.2 Other---------------------------- 12.4 12.4 Total Long-Term Debt and Other Obligations---------- 185.5 189.7 $2.20 Preferred Stock (Redeemable)----------------------- 78.1 -- Common Stock and Other Stockholders' Equity: $2.20 Preferred Stock------------ -- 57.5 $2.16 Preferred Stock------------ 1.3 -- Common Stock--------------------- 2.3 3.7 Additional Paid-In Capital------- 87.0 113.4 Accumulated Deficit-------------- (31.9) (36.7) Deferred Compensation------------ (.2) (.2) Total Common Stock and Other Stockholders' Equity------- 58.5 137.7 Total Capitalization------------- $ 322.1 327.4 Ratio of Long-Term Debt and Redeemable Preferred Stock to Total Capitalization--------------------- 82% 58%
TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
The pro forma effects of the Recapitalization on the Company's results of operations assuming the Recapitalization had occurred on January 1, 1993, are as follows (in millions except per share amounts):
YEAR ENDED DECEMBER 31, 1993 AS REPORTED PRO FORMA (UNAUDITED) Total Revenues----------------------- $ 834.9 834.9 Earnings Before Extraordinary Loss------------------------------- $ 17.0 16.9 Extraordinary Loss------------------- -- 4.8 Net Earnings------------------------- 17.0 12.1 Preferred Stock Dividend Requirements----------------------- 9.2 6.3 Net Earnings Applicable to Common Stock------------------------------ $ 7.8 5.8 Earnings (Loss) Per Primary and Fully Diluted* Share: Earnings Before Extraordinary Loss--------------------------- $ .54 .46 Extraordinary Loss--------------- -- (.21) Net Earnings--------------------- $ .54 .25 Average Common and Common Equivalent Shares Outstanding: Primary-------------------------- 14,290 22,788 Fully Diluted-------------------- 19,065 25,288
* ANTI-DILUTIVE
See Notes I, L and M for further information on the Company's long-term debt and equity, including restrictions on dividend payments.
TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
NOTE C -- CHANGE IN FISCAL YEAR-END
The Company changed its fiscal year-end from September 30 to December 31, effective January 1, 1992. The Statement of Consolidated Operations and the Statement of Consolidated Cash Flows for the three months ended December 31, 1991 are presented in the accompanying Consolidated Financial Statements. Comparative financial information is presented below (in thousands except per share amounts):
STATEMENTS OF CONSOLIDATED OPERATIONS
THREE MONTHS ENDED DECEMBER 31, 1991 1990 (UNAUDITED) Revenues: Gross operating revenues--------- $ 240,586 334,098 Interest income------------------ 682 1,410 Gain on sales of assets---------- 9 177 Other---------------------------- 2,596 499 Total Revenues--------------- 243,873 336,184 Costs and Expenses: Costs of sales and operating expenses----------------------- 228,569 312,047 General and administrative------- 2,849 4,033 Depreciation, depletion and amortization------------------- 4,225 3,058 Interest expense----------------- 4,966 4,639 Other---------------------------- 722 761 Total Costs and Expenses----- 241,331 324,538 Earnings before Income Taxes--------- 2,542 11,646 Income Tax Provision----------------- 2,958 6,793 Net Earnings (Loss)------------------ $ (416) 4,853 Net Earnings (Loss) Applicable to Common Stock----------------------- $ (2,717) 2,552 Earnings (Loss) Per Primary and Fully Diluted* Share--------------------- $ (.19) .18
* ANTI-DILUTIVE
TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
STATEMENTS OF CONSOLIDATED CASH FLOWS
THREE MONTHS ENDED DECEMBER 31, 1991 1990 (UNAUDITED) Cash Flows From (Used In) Operating Activities: Net earnings (loss)-------------- $ (416) 4,853 Adjustments to reconcile net earnings (loss) to net cash used in operating activities: Depreciation, depletion and amortization--------------- 4,225 3,058 Gain on sales of assets------ (9) (177) Other------------------------ 599 836 Changes in assets and liabilities: Receivables-------------- 6,524 14,313 Inventories-------------- (10,620) (24,687) Investment in Tesoro Bolivia Petroleum Company---------------- 8,756 (4,383) Other assets------------- (4,748) (3,325) Accounts payable and other current liabilities------------ (3,877) (8,307) Other liabilities and obligations------------ (774) 1,105 Net cash used in operating activities------------- (340) (16,714) Cash Flows From (Used In) Investing Activities: Capital expenditures------------- (3,858) (6,136) Proceeds from sales of assets---- 35 692 Other---------------------------- 1 (829) Net cash used in investing activities------------- (3,822) (6,273) Cash Flows From (Used In) Financing Activities: Payments of long-term debt------- (512) (409) Issuance of long-term debt------- 3,000 -- Dividends on preferred stocks---- -- (2,294) Other---------------------------- (7) 2 Net cash from (used in) financing activities------------- 2,481 (2,701) Decrease in Cash and Cash Equivalents------------------------ (1,681) (25,688) Cash and Cash Equivalents at Beginning of Period---------------- 62,710 78,785 Cash and Cash Equivalents at End of Period----------------------------- $ 61,029 53,097 Supplemental Cash Flow Disclosures: Interest paid-------------------- $ 234 218 Income taxes paid---------------- $ 3,425 2,663
NOTE D -- INVENTORIES
Inventories valued by the LIFO method amounted to approximately $63.0 million and $63.7 million at December 31, 1993 and 1992, respectively. At December 31, 1993, inventories valued using LIFO approximated replacement cost. At December 31, 1992 inventories valued using LIFO were lower than replacement cost by approximately $9.6 million.
NOTE E -- PROPERTY, PLANT AND EQUIPMENT
Effective May 1, 1992, the Company's subsidiaries, Tesoro Indonesia Petroleum Company and Tesoro Tarakan Petroleum Company (collectively 'Tesoro Indonesia'), sold their 100% interest in
TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED two separate contracts of operations with Pertamina, the state-owned petroleum company of Indonesia. The sales included all of Tesoro Indonesia's interests in fixtures, wells, pipelines, tanks, compressors, rigs and other equipment in the contract areas, and inventories of crude oil and materials and supplies. The consideration received by Tesoro Indonesia totaled $6.6 million in cash and the assumption by the purchaser of liabilities of approximately $6.3 million and all remaining expenditure commitments. During 1992, these sales transactions resulted in pretax net gains to the Company of approximately $5.8 million after related expenses.
In 1992, the Company sold its corporate airplane and related assets for $3.3 million in cash with no significant pretax gain to the Company. The Company also sold certain oil and gas properties in South Texas for $2.1 million in cash, which proceeds reduced the carrying value of the Company's oil and gas properties and no gain or loss was recognized. In addition, the Company sold its remaining drilling rigs for cash proceeds of $1.6 million resulting in a pretax loss of $1.1 million during 1992.
NOTE F -- INVESTMENT IN TESORO BOLIVIA PETROLEUM COMPANY
The Company's subsidiary, Tesoro Bolivia Petroleum Company ('Tesoro Bolivia'), holds an interest in a joint venture agreement to explore for and produce hydrocarbons in Bolivia. The joint venture has an agreement with the Bolivian Government and YPFB, the Bolivian state-owned oil company, for collection of receivables for sales of natural gas and condensate to YPFB, which in turn sells the natural gas to the Republic of Argentina. The agreement provided, among other things, that receipts from natural gas sales subsequent to December 31, 1987 would be placed in a restricted bank account ('Restricted Account') from which only payments for investments and expenses in Bolivia could be made until April 1992, or until cumulative deposits to the Restricted Account equal $90.0 million. Cumulative deposits to the Restricted Account have totaled $90.0 million and receipts for natural gas sales are now free of restrictions to the joint venture. The increase in the book value of this investment during 1993 represented earnings and cash invested in Tesoro Bolivia reduced by cash received free of restrictions.
NOTE G -- ACCRUED LIABILITIES
The Company's current accrued liabilities as shown in the Consolidated Balance Sheets include the following (in thousands):
DECEMBER 31, 1993 1992 Accrued Interest--------------------- $ 5,185 14,401 Accrued Environmental Costs---------- 6,171 4,632 Other-------------------------------- 12,661 11,354 Accrued Liabilities-------------- $ 24,017 30,387
Other liabilities classified as noncurrent in the Consolidated Balance Sheets consist of the following (in thousands):
DECEMBER 31, 1993 1992 Accrued Postretirement Benefits------ $ 27,270 25,088 Accrued Dividends on $2.16 Preferred Stock------------------------------ 9,145 6,294 Deferred Income Taxes---------------- 3,792 7,402 Other-------------------------------- 5,065 4,323 Other Liabilities---------------- $ 45,272 43,107
TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
NOTE H -- INCOME TAXES
The income tax provision includes the following (in thousands):
During 1993, the Company resolved several outstanding issues with state taxing authorities resulting in a reduction of $3.0 million in state income tax expense and $5.2 million in related interest expense.
Deferred income taxes and benefits are provided for differences between financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Temporary differences and the resulting deferred tax assets and liabilities are summarized as follows (in thousands):
DECEMBER 31, 1993 1992 Deferred Tax Assets: Net operating losses available for utilization through the year 2008---------------------- $ 24,890 21,501 Settlement with the State of Alaska------------------------- 21,583 24,476 Accrued postretirement benefits----------------------- 8,359 6,947 Settlement with Department of Energy------------------------- 4,443 4,616 Other---------------------------- 7,220 12,137 Total Deferred Tax Assets---- 66,495 69,677 Deferred Tax Liabilities: Accelerated depreciation and property-related items--------- (45,965) (42,475) Deferred Tax Assets Before Valuation Allowance-------------------------- 20,530 27,202 Valuation Allowance------------------ (20,530) (27,202) Other-------------------------------- (442) (6,660) State Income and Alternative Minimum Taxes------------------------------ (3,350) (742) Net Deferred Tax Liability------- $ (3,792) (7,402)
TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
The following table sets forth the components of the Company's results of operations and a reconciliation of the normal statutory federal income tax with the provision for income taxes (in thousands):
At December 31, 1993, the Company's net operating loss carryforwards were approximately $71.1 million for regular tax and approximately $56.1 million for alternative minimum tax. These tax loss carryforwards are available for future years and, if not used, will begin to expire in the year 2004. Also at December 31, 1993, the Company had approximately $8.2 million of investment tax credits and employee stock ownership credits available for carryover to subsequent years. These credits, if not used, will begin to expire in the year 2001.
If the Company has an 'ownership change' as defined by the Internal Revenue Code of 1986, the Company's use of its net operating loss carryforwards and general business credits after such ownership change will be subject to an annual limit. Under certain interpretations of existing Internal Revenue Service (IRS) regulations, the Recapitalization, as discussed in Note B, will result in an ownership change. The Company intends to take the position that an ownership change under existing law did not occur prior to the Recapitalization and did not occur as a result thereof. Because there are substantial interpretive questions concerning such IRS regulations and there is uncertainty as to events which may occur after the Recapitalization, there can be no assurance that an ownership change did not occur as a result of the Recapitalization or will not occur as a result of future events. If an ownership change is ultimately deemed to have occurred at the time of the Recapitalization, the Company's use of its net operating loss carryforwards and general business credits would be limited to approximately $14.5 million per year.
TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
NOTE I -- LONG-TERM DEBT AND OTHER OBLIGATIONS
Long-term debt and other obligations consist of the following (in thousands):
DECEMBER 31, 1993 1992 12 3/4% Subordinated Debentures due 2001-------------------------------- $ 98,154 107,510 Liability to State of Alaska--------- 61,666 71,989 Liability to Department of Energy---- 13,194 13,194 Exploration and Production Loan------ 5,000 -- Industrial Revenue Bonds------------- 2,752 3,483 Capital Lease Obligations (interest at 11%)---------------------------- 3,934 4,368 Other-------------------------------- 772 1,204 185,472 201,748 Less Current Portion----------------- 4,805 26,287 $ 180,667 175,461
Based on the closing market price, the fair value of the Subordinated Debentures, exclusive of accrued interest, was approximately $108.3 million at December 31, 1993. The carrying value of the other long-term debt and obligations approximated the Company's estimate of the fair value of such items.
As discussed in Note B, approximately four years of sinking fund requirements on the Subordinated Debentures will be satisfied by the exchange offer included in the Recapitalization. After giving effect to the Recapitalization, sinking fund requirements and aggregate maturities of long-term debt and obligations for each of the five years following December 31, 1993 are as follows (in thousands):
LETTER OF CREDIT REQUIREMENTS
On October 29, 1993, the Company elected to terminate its secured Letter of Credit Facility Agreement ('Credit Facility') dated July 27, 1989, which was scheduled to expire in March 1994 and which provided for the issuance of up to $40 million in letters of credit at the date of termination. In the latter half of 1993, the Company negotiated several interim credit arrangements collateralized by either cash or inventory to permit the Company to secure the purchases of crude oil feedstocks and to meet other operating and corporate credit requirements. With respect to these interim credit arrangements, the Company has entered into several uncommitted letter of credit facilities which provide for the issuance of letters of credit on a cash-secured basis. Total availability pursuant to the uncommitted letter of credit arrangements was in excess of $80 million.
At December 31, 1993, the Company had arranged for the issuance of $25 million of outstanding letters of credit which were secured by restricted cash deposits. At 1992 year-end, under the terms of the previous Credit Facility, the Company was required to maintain a minimum $30 million cash balance and specified levels of equity and working capital.
TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
In addition, effective September 30, 1993, the Company entered into a waiver and substitution of collateral agreement ('Substitution Agreement') with the State of Alaska, the Company's largest supplier of crude oil. Under the Substitution Agreement, the Company has pledged the capital stock of Tesoro Alaska Petroleum Company ('Tesoro Alaska'), a wholly-owned subsidiary of the Company, and substantially all of its crude oil and refined product inventory in Alaska to secure its purchases of royalty crude oil. The Substitution Agreement has allowed the Company to reduce its letter of credit requirements to $25 million as of December 31, 1993. This agreement extends through January 1, 1995 and contains various covenants and restrictions customary to inventory financing transactions.
EXPLORATION AND PRODUCTION FINANCING
Effective October 29, 1993, Tesoro Exploration and Production Company ('Tesoro E&P'), a wholly-owned subsidiary of the Company, entered into a $30 million reducing revolving credit facility ('E&P Facility') secured by the capital stock of Tesoro E&P and its natural gas properties in the Bob West Field in South Texas. At December 31, 1993, $5.0 million was outstanding under this facility.
The E&P Facility, which expires December 31, 1996, is guaranteed by the Company, contains certain financial covenants that must be maintained by Tesoro E&P and bears interest at prime plus 1% or, at Tesoro E&P's option, Libor plus 2.5%. The E&P Facility contains restrictions that prohibit borrowings under the facility to be used by Tesoro E&P or the Company for debt service, including interest and principal on the Company's 12 3/4% Subordinated Debentures, or for payment of common or preferred dividends.
12 3/4% SUBORDINATED DEBT AND 13% EXCHANGE NOTES
In 1983, the Company issued $120 million of 12 3/4% Subordinated Debentures at a price of 84.559% of the principal amount, due March 15, 2001. The debentures are redeemable at the option of the Company at 100% of principal amount plus accrued interest. Sinking fund payments sufficient to retire $11.25 million principal amount of debentures annually commenced on March 15, 1993. The Company satisfied the initial sinking fund requirement by purchasing $11.25 million principal amount of debentures at market value on January 26, 1993. The exchange of $44.1 principal amount of Subordinated Debentures for Exchange Notes in February 1994 will satisfy nearly four years of sinking fund requirements (see Note B). At December 31, 1993 and 1992, subordinated debt amounted to $98.2 million (net of discount of $10.6 million) and $107.5 million (net of discount of $12.5 million), respectively. The indenture contains restrictions on payment of dividends on the Company's common stock and purchases or redemptions of common or preferred stocks. Due to losses which have been incurred, the Company must generate approximately $131 million of future net earnings applicable to common stock or from the issuance of capital stock before future dividends can be paid on common stock or before purchases or redemptions can be made of common or preferred stocks.
As part of the Recapitalization discussed in Note B, in February 1994, Subordinated Debentures in the principal amount of $44.1 million were exchanged for a like amount of new 13% Exchange Notes. The Exchange Notes mature on December 1, 2000, and have no sinking fund requirements. The Exchange Notes are redeemable at the option of the Company at 100% of principal amount plus accrued interest except that no optional redemption may be made unless an equal principal amount of, or all the outstanding, Subordinated Debentures, are concurrently redeemed. The Exchange Notes rank PARI PASSU with the other senior debt of the Company and with the Subordinated Debentures, and senior in right of payment of the obligation to the State of Alaska (discussed below) and all other subordinated indebtedness of the Company. The indenture governing the Exchange Notes contains
TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED limitations on dividends which are less restrictive than the limitation under the Subordinated Debentures. For information on the pro forma effects of the exchange, see Note B.
STATE OF ALASKA
In January 1993, the Company and its subsidiary, Tesoro Alaska Petroleum Company ('Tesoro Alaska'), entered into an agreement ('Agreement') with the State of Alaska ('State') that settled Tesoro Alaska's contractual dispute with the State. In addition to $62 million accrued through September 30, 1992, a charge of $10.5 million for the settlement was included in the Company's operations during the fourth quarter of 1992.
Under the Agreement, Tesoro Alaska paid the State $10.3 million in January 1993 and agreed to make variable monthly payments to the State over the next nine years following the date of the settlement based on a per barrel charge that increases over the nine-year term from 16 cents to 33 cents on the volume of feedstock processed at the Company's Alaska refinery. In 1993, the Company's variable payments to the State totaled $2.6 million. At the end of the nine-year period, Tesoro Alaska is obligated to pay the State $60 million; provided, however, that such payment may be deferred indefinitely by continuing the variable monthly payments to the State beginning at 34 cents per barrel and increasing one cent per barrel annually thereafter. Variable monthly payments made after the nine-year period will not reduce the $60 million obligation to the State. The imputed rate of interest used by the Company on the $60 million obligation was 13%. The $60 million obligation is evidenced by a security bond, and the bond and the throughput barrel obligations are secured by a second mortgage on the Company's Alaska refinery. Tesoro Alaska's obligations under the Agreement and the mortgage are subordinated to current and future senior debt of up to $175 million plus any indebtedness incurred in the future to improve the Company's Alaska refinery.
The State's claim against Tesoro Alaska arose out of certain provisions in present and past contracts with the State that required Tesoro Alaska to pay the State additional retroactive amounts if the State prevailed in litigation against the producers of North Slope crude oil ('Producers'). As a result of settlements between the State and the Producers, the State claimed that the royalty oil it sold Tesoro Alaska and others was undervalued to the extent that the Producers undervalued their oil.
DEPARTMENT OF ENERGY
A Consent Order entered into by the Company with the Department of Energy ('DOE') in 1989 settled all issues relating to the Company's compliance with federal petroleum price and allocation regulations from 1973 through decontrol in 1981. The Company has paid $41.3 million to the DOE since 1989. The Company's remaining obligation is to pay $13.2 million, exclusive of interest at 6%, over the next eight years.
INDUSTRIAL REVENUE BONDS AND OTHER
The industrial revenue bonds mature in 1998 and require semiannual payments of approximately $365,000. The bonds bear interest at a variable rate (4 1/2% at December 31, 1993) which is equal to 75% of the National Bank of Alaska's prime rate. The bonds are collateralized by the Company's Alaska refinery sulphur recovery unit which had a carrying value of approximately $6.9 million at December 31, 1993.
CAPITAL LEASE OBLIGATIONS
The Company is the lessee of certain buildings and equipment under capital leases with remaining lease terms of 4 to 25 years. These buildings and equipment are used in the Company's convenience store operations in Alaska. The assets and liabilities under capital leases are recorded at
TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED the present value of the minimum lease payments. Property, plant and equipment at December 31, 1993 included assets held under capital leases of $6.0 million with a net book value of $2.6 million.
NOTE J -- EMPLOYEE BENEFIT PLANS
RETIREMENT PLAN
For all eligible employees, the Company provides a qualified noncontributory retirement plan. Plan benefits are based on years of service and compensation. It is the Company's policy to fund costs accrued to the extent such costs are tax deductible. The components of net pension expense (income) for the Company's retirement plan are presented below (in thousands):
YEARS ENDED YEAR ENDED DECEMBER 31, SEPTEMBER 30, 1993 1992 1991 Service Costs------------------------ $ 931 717 762 Interest Cost------------------------ 3,513 3,492 3,482 Actual Return on Plan Assets--------- (5,695) (1,763) (7,646) Net Amortization and Deferral-------- 1,488 (2,231) 3,167 Net Pension Expense (Income)----- $ 237 215 (235)
For the three months ended December 31, 1991, net pension expense for the Company's retirement plan totaled $90,000.
In addition to the retirement plan pension expense above, during 1992 the Company recognized a curtailment gain of $1.0 million for employee terminations in conjunction with a cost reduction program.
The funded status of the Company's retirement plan and amounts included in the Company's Consolidated Balance Sheets are set forth in the following table (in thousands):
DECEMBER 31, SEPTEMBER 30, 1993 1992 1991 Actuarial Present Value of Benefit Obligation: Vested benefit obligation-------- $ 41,200 34,806 33,959 Accumulated benefit obligation--------------------- $ 43,694 36,460 35,556 Plan Assets at Fair Value------------ $ 40,718 39,326 39,772 Projected Benefit Obligation--------- 48,700 40,989 40,305 Plan Assets Less Than Projected Benefit Obligation----------------- (7,982) (1,663) (533) Unrecognized Net Loss---------------- 11,997 7,222 5,889 Unrecognized Prior Service Costs----- (518) (588) (779) Unrecognized Net Transition Asset---- (6,883) (8,120) (9,664) Accrued Pension Expense Liability---------------------- $ (3,386) (3,149) (5,087)
Retirement plan assets are primarily comprised of common stock and bond funds. Actuarial assumptions used to measure the projected benefit obligation at December 31, 1993 included a discount rate of 7% and a compensation increase rate of 4 1/2%. At December 31, 1992, the discount rate used was 9% and the compensation increase rate used was 6%. The expected long-term rate of return on assets was 9% for 1993 and 1992.
TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
EXECUTIVE SECURITY PLAN
The Company's executive security plan ('ESP') provides executive officers and other key personnel with supplemental death or retirement benefits in addition to those benefits available under the Company's group life insurance and retirement plans. These supplemental retirement benefits are provided by a nonqualified, noncontributory plan and are based on years of service and compensation. Funding is provided based upon the estimated requirements of the plan. The components of net pension expense for the ESP are presented below (in thousands):
YEARS ENDED YEAR ENDED DECEMBER 31, SEPTEMBER 30, 1993 1992 1991 Service Costs------------------------ $ 426 293 581 Interest Cost------------------------ 291 353 546 Actual Return on Plan Assets--------- (256) (1,004) (628) Net Amortization and Deferral-------- 295 994 590 Net Pension Expense-------------- $ 756 636 1,089
For the three months ended December 31, 1991, net pension expense for the ESP totaled $242,000.
During 1993 and 1992, the Company incurred additional ESP expense of $.5 million and $3.5 million, respectively, for settlement losses and other benefits resulting from a cost reduction program, other employee terminations and sales of assets.
The funded status of the ESP and amounts included in the Company's Consolidated Balance Sheets are set forth in the following table (in thousands):
DECEMBER 31, SEPTEMBER 30, 1993 1992 1991 Actuarial Present Value of Benefit Obligation: Vested benefit obligation-------- $ 2,394 2,410 6,368 Accumulated benefit obligation--------------------- $ 2,792 2,464 6,420 Plan Assets at Fair Value------------ $ 3,139 2,924 6,658 Projected Benefit Obligation--------- 3,069 2,738 6,420 Plan Assets in Excess of Projected Benefit Obligation----------------- 70 186 238 Unrecognized Net Loss---------------- 1,177 1,409 2,147 Unrecognized Prior Service Costs----- 619 679 1,287 Unrecognized Net Transition Obligation------------------------- 1,110 1,254 2,412 Prepaid Pension Asset------------ $ 2,976 3,528 6,084
Assets of the ESP consist of a group annuity contract. Actuarial assumptions used to measure the projected benefit obligation at December 31, 1993 included a discount rate of 7% and a compensation rate increase of 4 1/2%. At December 31, 1992, the discount rate used was 9% and the compensation rate increase used was 5%. The expected long-term rate of return on assets was 9% for 1993 and 1992.
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
In addition to providing pension benefits, the Company provides health care and life insurance benefits to retirees and eligible dependents who were participating in the Company's group insurance program at retirement. These benefits are provided through unfunded defined benefit plans. The
TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED 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.
As discussed in Note A, the Company adopted SFAS No. 106 effective January 1, 1992 and incurred a net charge of $21.6 million ($16.1 million for health care benefits and $5.5 million for life insurance benefits) for the cumulative effect of the change in accounting principle. The components of net periodic postretirement benefits expense, other than pensions, for 1993 and 1992 included the following (in thousands):
Prior to 1992, the costs of providing health care and life insurance benefits to retired employees were expensed as claims were paid. In 1991, the costs of providing retirees with health care benefits amounted to $751,000 and life insurance benefits amounted to $299,000. For the three months ended December 31, 1991, retiree health care and life insurance benefits totaled $191,000 and $59,000, respectively.
The Company continues to fund the cost of postretirement health care and life insurance benefits on a pay-as-you-go basis. The following table shows the status of the plans reconciled with the amounts in the Company's Consolidated Balance Sheets (in thousands):
The weighted average annual assumed rate of increase in the per capita cost of covered health care benefits was assumed to be 12% for 1994 decreasing gradually to 7% by the year 2010 and remains at that level thereafter. This health care cost trend rate assumption has a significant effect on the amount of the obligation and periodic cost reported. For example, an increase in the assumed health care cost trend rates by one percentage point in each year would increase the accumulated postretirement obligation as of December 31, 1993 by $2.9 million and the aggregate of service cost and interest cost components of net periodic postretirement benefits for the year then ended by $.4 million.
Actuarial assumptions used to measure the accumulated postretirement benefit obligation at December 31, 1993 included a discount rate of 7% and a compensation rate increase of 4 1/2%. At December 31, 1992, the discount rate was 8 1/2% and the compensation rate increase was 6%.
TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
THRIFT PLAN
The Company's employee thrift plan provides for contributions by eligible employees into designated investment funds with a matching contribution by the Company of 50% of the employee's basic contribution. The Company's contributions amounted to $482,000, $474,000 and $439,000 during 1993, 1992 and 1991, respectively. For the three months ended December 31, 1991, the Company's contributions amounted to $107,000.
COST REDUCTION PROGRAM AND OTHER EMPLOYEE TERMINATIONS
In addition to the ESP settlement losses and other benefits and the retirement plan curtailment gain discussed above, during 1992 the Company incurred charges of $6.6 million for expenses to implement a cost reduction program and other employee terminations.
NOTE K -- COMMITMENTS AND CONTINGENCIES
OPERATING LEASES
The Company has various noncancellable operating leases related to convenience stores, equipment, property, vessels and other facilities. Lease terms range from one year to 40 years and generally contain multiple renewal options. Future minimum annual payments for operating leases, as of December 31, 1993, are as follows (in thousands):
1994--------------------------------- $ 17,157 1995--------------------------------- 4,946 1996--------------------------------- 3,860 1997--------------------------------- 3,265 1998--------------------------------- 3,125 Thereafter--------------------------- 13,885 Total---------------------------- $ 46,238
Total rental expense was approximately $32.5 million, $24.3 million and $19.9 million for 1993, 1992 and 1991, respectively. Rental expense for 1993, 1992 and 1991 included $22.9 million, $12.0 million and $9.9 million, respectively, related to the lease of vessels used to transport crude oil to or refined products from the Company's Alaska refinery. The lease for one of these vessels extends through October 1994 with a renewal option available through October 1996. The lease for the second vessel extends through July 1994 with a renewal option available through January 1995. For the three months ended December 31, 1991, rental expense amounted to $6.0 million, of which $2.9 million related to the lease of a vessel.
GAS PURCHASE AND SALES CONTRACT
The Company is selling gas from its Bob West Field to Tennessee Gas Pipeline Company ('Tennessee Gas') under a 1979 Gas Purchase and Sales Agreement ('Gas Contract') which expires in January 1999. The Gas Contract provides that the price of gas shall be the maximum price as calculated in accordance with the then effective Section 102(b)(2) ('Contract Price') of the Natural Gas Policy Act of 1978 ('NGPA').
In August 1990, Tennessee Gas filed a civil action in the District Court of Bexar County, Texas against the Company and several other companies, seeking a Declaratory Judgment that the Gas Contract is not applicable to the Company's properties. Tennessee Gas claimed, among other things, that certain leases covered by the Gas Contract terminated and therefore were automatically released from the Gas Contract, eliminating the obligation of Tennessee Gas to purchase gas from the
TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED Company. Tennessee Gas also challenged the quantity of gas which can be sold under the Gas Contract and contended that the gas sales price was to be calculated under the provisions of Section 101 of the NGPA rather than the Contract Price. At December 31, 1993, the Section 101 price of $5.01 per mcf was $2.71 per mcf less than the Contract Price, but $2.75 per mcf above spot market prices.
On June 24, 1992, the District Court trial judge returned a verdict in favor of the Company. The District Court's judgment, entered on July 8, 1992, ruled that Tennessee Gas must honor the Gas Contract pursuant to its terms. Tennessee Gas filed a motion for reconsideration in the District Court on the issue of the price to be paid for the gas under the Gas Contract, which was denied by the court. On September 11, 1992, Tennessee Gas appealed the judgment to the Court of Appeals for the Fourth Supreme Judicial District of Texas. On August 25, 1993, the Court of Appeals affirmed the validity of the Gas Contract as to the Company's properties and held that the price payable by Tennessee Gas for the gas was the Contract Price. The Court of Appeals determined, however, (i) that the trial court erred in its summary judgment ruling that the Gas Contract was not an output contract under the Texas Business and Commerce Code ('TBCA') and (ii) that a fact issue exists as to whether the increases in the volumes of gas tendered to Tennessee Gas under the Gas Contract were made in bad faith or were unreasonably disproportionate to prior tenders in contravention of the provisions of Section 2.306 of the TBCA. Accordingly, the Court of Appeals directed that this issue be remanded to the trial court in Bexar County, Texas. The Company filed a motion for rehearing with the appellate court regarding its decision that the Gas Contract creates an output contract governed by the TBCA. Tennessee Gas also filed a motion for rehearing with the appellate court regarding the portions of its decision upholding the judgment of the trial court. On January 26, 1994, the appellate court rendered its judgment denying all motions for rehearing in this matter and affirming its earlier ruling. The Company has appealed the appellate court ruling on the output contract issue to the Supreme Court of Texas. Tennessee Gas has also appealed to the Supreme Court of Texas that portion of the appellate court ruling denying the remaining Tennessee Gas claims. If the Supreme Court of Texas does not grant the Company's petition for writ of error and affirms the appellate court ruling, then the only issue for trial will be whether the increases in the volumes of gas tendered to Tennessee Gas from the Company's properties may have been made in bad faith or were unreasonably disproportionate. Management of the Company believes its tenders were reasonable under the Gas Contract and the market conditions at the time and will vigorously defend on this issue if put to trial. The Company continues to receive payment from Tennessee Gas based on the Contract Price.
Although the outcome of any litigation is uncertain, management believes that the Tennessee Gas claims are without merit and, based upon advice from outside legal counsel, is confident that the decision of the trial court will ultimately be upheld as to the validity of the Gas Contract and the Contract Price; and that with respect to the output contract issue, the Company believes that, if this issue is tried, the development of its gas properties and the resulting increases in volumes tendered to Tennessee Gas will be found to have been reasonable and in good faith. Accordingly, the Company has recognized revenues, net of production taxes and marketing charges, for natural gas sales through December 31, 1993, under the Gas Contract based on the Contract Price, which net revenues aggregated $16.8 million more than the Section 101 prices and $31.0 million in excess of the spot market prices. An adverse judgment in this case could have a material adverse effect on the Company. If Tennessee Gas ultimately prevails in this litigation, the Company could be required to return to Tennessee Gas $31.0 million, excluding any interest that may be awarded by the court, representing the difference between the spot price for gas and the Contract Price. For further information concerning the effect of the Gas Contract on certain of the Company's revenues and cash flows, see Note P.
TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
OTHER
In March 1992, the Company received a Compliance Order and Notice of Violation from the U.S. Environmental Protection Agency ('EPA') alleging possible violations by the Company of the New Source Performance Standards under the Clean Air Act at its Alaska refinery. The Company is continuing in its efforts to resolve these issues with the EPA; however, no final resolution has been reached. The Company believes that the ultimate resolution of this matter will not have a material adverse effect upon the Company's business or financial condition.
The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, 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. The Company is currently involved with two waste disposal sites in Louisiana at which it has been named a potentially responsible party under the Federal Superfund law. Although this law might impose joint and several liability upon each party at any site, the extent of the Company's allocated financial contribution to the cleanup of these sites is expected to be limited based on the number of companies and the volumes of waste involved. At each site, a number of large companies have also been named as potentially responsible parties and are expected to cooperate in the cleanup. The Company is also involved in remedial response and has incurred cleanup expenditures associated with environmental matters at a number of other sites including certain of its own properties.
At December 31, 1993, the Company had accrued $6.2 million for environmental costs. Based on currently available information, including the participation of other parties or former owners in remediation actions, the Company believes these accruals are adequate. Conditions which require additional expenditures may exist for various Company sites, including, but not limited to, the Company's refinery, service stations (current and closed locations) and petroleum product terminals, and for compliance with the Clean Air Act. The amount of such future expenditures cannot presently be determined by the Company.
NOTE L -- REDEEMABLE PREFERRED STOCK
In March 1983, the Company sold 2,875,000 shares of a series of redeemable preferred stock at $20 per share. The stock is held by MetLife which is a subsidiary of Metropolitan Life Insurance Company. The class of stock, of which there were 2,875,000 shares authorized, issued and outstanding at December 31, 1993 and 1992, has been designated the $2.20 Cumulative Convertible Preferred Stock ('$2.20 Preferred Stock'). This series has one vote per share, is convertible into .8696 shares of Common Stock for each share of Preferred Stock, has a stated value of $1 per share and a liquidation price of $20 per share plus accrued dividends. The $2.20 Preferred Stock ranks in parity with the $2.16 Cumulative Convertible Preferred Stock as to liquidation and dividends.
The redeemable preferred stock was recorded at fair value on the date of issuance less issue costs. The excess of the redemption value over the carrying value is being accreted by periodic charges to retained earnings over the life of the issue. During 1993 and 1992, the carrying value of the redeemable preferred stock was increased for mandatorily redeemable accumulated dividends, not declared or paid, by charges to retained earnings. As of December 31, 1993, dividends in arrears on the $2.20 Preferred Stock amounted to approximately $19.8 million, or $6.87 1/2 per share.
As discussed in Note B, in February 1994, the agreement between the Company and MetLife was amended with regard to such preferred shares to waive all existing mandatory redemption requirements, to consider all accrued and unpaid dividends (aggregating $21.2 million at February 9, 1994) to have been paid, to allow the Company to pay future dividends in Common Stock in lieu of cash, to waive or refrain from exercising other rights of the $2.20 Preferred Stock and to grant to the
TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED Company an option to purchase, during the next three years, all shares of the $2.20 Preferred Stock and Common Stock held by MetLife for approximately $53 million (amount at February 9, 1994, increasing by 12% to 14% annually) subject to certain conditions, in consideration for, among other things, the issuance by the Company to MetLife of 1,900,075 shares of Common Stock. Such additional shares will be subject to the option granted by MetLife. After giving effect to the Recapitalization, MetLife's Common and Preferred Stock holdings approximated 27% of the Company's voting securities. For information on the pro forma effects of these amendments, see Note B.
NOTE M -- COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY
For information regarding the effects of the Recapitalization on the Company's Common Stock and Other Stockholders' Equity, refer to Note B.
$2.16 CUMULATIVE CONVERTIBLE PREFERRED STOCK
The Company has designated a class of preferred stock, of which there were 1,319,563 shares outstanding at December 31, 1993 and 1992 and 200,000 shares reserved for the granting of options under a stock option plan of the Company. This class, designated the $2.16 Cumulative Convertible Preferred Stock ('$2.16 Preferred Stock'), has voting rights, is convertible into Common Stock at the rate of 1.7241 shares of Common Stock for each share of Preferred Stock, has a stated value of $1 per share and a liquidation value of $25 per share, and is repurchasable at the option of the Company at liquidation value plus accrued dividends. The $2.16 Preferred Stock ranks in parity with the $2.20 Preferred Stock as to liquidation and dividends.
During 1993 and 1992, the liability for accumulated dividends, not declared or paid, on the $2.16 Preferred Stock was accrued by charges to retained earnings. As of December 31, 1993, dividends in arrears on the $2.16 Preferred Stock amounted to approximately $8.9 million, or $6.75 per share.
As discussed in Note B, in February 1994, the outstanding shares of the Company's $2.16 Preferred Stock, plus accrued and unpaid dividends thereon (aggregating $9.5 million at February 9, 1994), were reclassified into shares of the Company's Common Stock.
AMENDED INCENTIVE STOCK PLAN OF 1982 ('1982 PLAN')
The Company's 1982 Plan provides for the granting of stock incentives in the form of stock options, stock appreciation rights and stock awards to officers and key employees. The stock options are exercisable in accordance with the option plans and expire no later than ten years from the date of grant.
Stock appreciation rights are exercisable in three to five annual installments, normally beginning with the first anniversary date of the grant, and expire ten years from the date of grant. The stock appreciation rights entitle the employee to receive, without payment to the Company, the incremental increase in market value of the related stock from date of grant to date of exercise, payable in cash. Related compensation expense is charged to earnings over periods earned. During 1993, 1992 and 1991 and the three months ended December 31, 1991, no compensation expense was recognized since the market value of the Company's Common Stock remained below the exercise price.
Stock awards totaling 83,015 common shares, 100,000 common shares and 12,000 common shares were granted at par value to certain employees of the Company in 1993, 1992 and 1991, respectively. Related compensation expense is charged to earnings over the periods that the shares are earned and amounted to $572,000, $142,000, $135,000 and $28,000 for 1993, 1992 and 1991 and the three months ended December 31, 1991, respectively.
TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
At December 31, 1993 and 1992 and September 30, 1991, the Company had 60,002, 392,566 and 852,381 unoptioned shares, respectively, available for granting of options, rights and awards under the 1982 Plan and 6,064,809, 6,084,809 and 6,093,231 shares of unissued Common Stock, respectively, reserved for conversion of preferred stock and the 1982 Plan. During 1988, an amendment to the 1982 Plan was approved which increased the number of shares of Common Stock which may be granted or transferred from 1,500,000 to 2,000,000. The additional shares will be registered with the Securities and Exchange Commission in 1994. The 1982 Plan expires on February 24, 1994 as to issuance of options, rights and awards; however, grants made before such date that have not been fully exercised will remain outstanding pursuant to their terms.
A summary of activity in the 1982 Plan and a prior plan is set forth below:
EXECUTIVE LONG-TERM INCENTIVE PLAN (THE '1993 PLAN')
On February 9, 1994, the Company's shareholders approved the 1993 Plan which permits the issuance of awards in a variety of forms, including restricted stock, incentive stock options, nonqualified stock options, stock appreciation rights and performance share and performance unit awards. The 1993 Plan provides for the grant of up to 1,250,000 shares of the Company's Common Stock and, unless earlier terminated, will expire as to the issuance of awards on September 15, 2003. No grants have been made pursuant to the 1993 Plan.
PREFERRED STOCK PURCHASE RIGHTS
In November 1985, the Company's Board of Directors declared a distribution of one preferred stock purchase right for each share of the Company's Common Stock. Each right will entitle the holder to buy 1/100 of a share of a newly authorized Series A Participating Preferred Stock at an exercise price of $35 per right. The rights become exercisable on the tenth day after public announcement that a person or group has acquired 20% or more of the Company's Common Stock. The rights may be redeemed by the Company prior to becoming exercisable by action of the Board of Directors at a redemption price of $.05 per right. If the Company is acquired by any person after the rights become exercisable, each right will entitle its holder to purchase stock of the acquiring company having a market value of twice the exercise price of each right. At December 31, 1993, there were 14,089,236 rights outstanding which will expire in December 1995. In conjunction with the Recapitalization in 1994 discussed in Note B, the Company issued an additional 8,365,934 rights.
TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
NOTE N -- FINANCIAL INFORMATION BY BUSINESS SEGMENT
Tesoro is primarily engaged in three business segments: crude oil refining and marketing of refined petroleum products; the exploration and production of natural gas; and oil field supply and distribution of fuels and lubricants. Geographically, the refining and marketing operations are concentrated in Alaska and on the West Coast, the exploration and production operations are located in South Texas and Bolivia, and the wholesale marketing of fuel and lubricants is conducted along the Texas and Louisiana Gulf Coast area. The Company sold its Indonesian exploration and production operations in May 1992. Income taxes, interest, general and administrative expenses and certain other corporate items are not allocated to the operating segments.
TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
NOTE O -- QUARTERLY FINANCIAL DATA (UNAUDITED)
The 1993 second and fourth quarters included benefits of $3.0 million and $5.2 million, respectively, for resolution of several state tax issues. A $5.0 million charge for an inventory erosion was recorded in the 1993 third quarter. Included in the 1993 fourth quarter, however, was a $5.7 million offset to the inventory adjustment taken earlier in the year. Inventory levels at the 1993 year-end were greater than projected earlier in the year due to changing market conditions. The 1993 fourth quarter benefited from the decline in crude oil prices, while the Company's refined product margins held steady or improved.
The 1992 first quarter included charges of $20.6 million for the cumulative effect of accounting changes, $2.4 million for a cost reduction program and $1.0 million for asset write-downs. The 1992 third quarter included a $5.8 million gain from the sales of the Company's Indonesian operations. The fourth quarter of 1992 included revenues and operating profit of $5.4 million ($.38 per share) resulting from a change in estimate of the Company's revenues from natural gas production in the South Texas field (see Note K) and additional charges of $10.5 million for the settlement with the State of Alaska and $5.6 million for the cost reduction program and other employee terminations.
TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
NOTE P -- OIL AND GAS PRODUCING ACTIVITIES
The following information regarding the Company's exploration and production activities should be read in conjunction with Notes E and K.
CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES
DECEMBER 31, SEPTEMBER 30, 1993 1992 1991 (IN THOUSANDS) Capitalized Costs: Proved properties---------------- $ 60,489 34,050 29,100 Unproved properties: Properties being amortized------------------ 12,856 11,132 8,511 Properties not being amortized------------------ 1,959 1,482 8,242 75,304 46,664 45,853 Accumulated depreciation, depletion and amortization----- 26,118 15,006 15,713 Net Capitalized Costs-------- $ 49,186 31,658 30,140
COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES
The Company's investment in oil and gas properties included $2.0 million in unevaluated properties which have been excluded from the amortization base as of December 31, 1993. The
TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED Company anticipates that the majority of these costs, substantially all of which were incurred in 1993, will be included in the amortization base during 1994.
RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES
The following table sets forth the results of operations for oil and gas producing activities, in the aggregate by geographic area, with income tax expense computed using the statutory tax rate for the period adjusted for permanent differences, tax credits and allowances.
(1) SEE NOTE K REGARDING LITIGATION INVOLVING A NATURAL GAS SALES CONTRACT.
(2) EXCLUDES CORPORATE GENERAL AND ADMINISTRATIVE AND FINANCING COSTS.
(3) REPRESENTS GAIN FROM THE SALES OF THE COMPANY'S INDONESIAN OPERATIONS EFFECTIVE MAY 1, 1992.
(4) INCLUDES A $2.0 MILLION CHARGE FOR AN ARBITRATION AWARD INVOLVING A ROYALTY DISPUTE ON INDONESIAN CRUDE OIL PRODUCTION.
(5) INCLUDES A $1.3 MILLION CREDIT FOR BOLIVIAN TRANSACTION TAXES.
TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED RESERVES (UNAUDITED)
The following table sets forth the computation of the standardized measure of discounted future net cash flows relating to proved reserves and the changes in such cash flows in accordance with Statement of Financial Accounting Standards No. 69 ('SFAS No. 69'). The standardized measure is the estimated excess future cash inflows from proved reserves less estimated future production and development costs, estimated future income taxes and a discount factor. Future cash inflows represent expected revenues from production of year-end quantities of proved reserves based on year-end prices and any fixed and determinable future escalation provided by contractual arrangements in existence at year-end. Escalation based on inflation, federal regulatory changes and supply and demand are not considered. Estimated future production costs related to year-end reserves are based on year-end costs. Such costs include, but are not limited to, production taxes and direct operating costs. Inflation and other anticipatory costs are not considered until the actual cost change takes effect. Estimated future income tax expenses are computed using the appropriate year-end statutory tax rates. Consideration is given for the effects of permanent differences, tax credits and allowances. A discount rate of 10% is applied to the annual future net cash flows after income taxes.
The methodology and assumptions used in calculating the standardized measure are those required by SFAS No. 69. The standardized measure is not intended to be representative of the fair market value of the Company's proved reserves. The calculations of revenues and costs do not necessarily represent the amounts to be received or expended by the Company.
As indicated in Note K, certain of the Company's South Texas production activities are involved in litigation pertaining to a natural gas sales contract with Tennessee Gas. Although the outcome of any litigation is uncertain, based upon advice from outside legal counsel, management believes that the Company will ultimately prevail in this dispute. Accordingly, the Company has based its calculation of the standardized measure of discounted future net cash flows on the Contract Price which it is currently receiving. However, if Tennessee Gas were to prevail, the impact on the Company's future revenues and cash flows would be significant. Based on the Contract Price, the standardized measure of discounted future net cash flows relating to proved reserves in the United States at December 31, 1993 was $103 million compared to $59 million at spot market prices.
TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
(1) SEE NOTE K REGARDING LITIGATION INVOLVING A NATURAL GAS SALES CONTRACT.
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 QUANTITY INFORMATION (UNAUDITED)
The following estimates of the Company's proved oil and gas reserves are based on evaluations prepared by Netherland, Sewell & Associates, Inc. (except for estimates of reserves at December 31, 1991 for properties in Bolivia and for all periods for properties in Indonesia, which estimates were prepared by the Company's in-house engineers). Reserves were estimated in accordance with guidelines established by the Securities and Exchange Commission and Financial Accounting Standards Board, which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations except by contractual arrangements.
UNITED STATES(2) BOLIVIA TOTAL Proved Gas Reserves (millions of cubic feet)(1): At September 30, 1990------------ 11,118 85,040 96,158 Revisions of previous estimates---------------------- (1,217) 696 (521) Purchase of minerals in-place---- -- 36,545 36,545 Extensions, discoveries and other additions---------------------- 25,950 -- 25,950 Production----------------------- (2,710) (7,052) (9,762) At September 30, 1991------------ 33,141 115,229 148,370 Revisions of previous estimates---------------------- 1,054 (35) 1,019 Extensions, discoveries and other additions---------------------- 3,585 -- 3,585 Production----------------------- (896) (1,729) (2,625) At December 31, 1991------------- 36,884 113,465 150,349 Revisions of previous estimates---------------------- (9,601) 651 (8,950) Extensions, discoveries and other additions---------------------- 53,952 -- 53,952 Production----------------------- (5,110) (7,108) (12,218) Sales of minerals in-place------- (2,372) -- (2,372) At December 31, 1992------------- 73,753 107,008 180,761 Revisions of previous estimates---------------------- 16,304 (693) 15,611 Extensions, discoveries and other additions---------------------- 44,291 -- 44,291 Production----------------------- (14,150) (7,020) (21,170) At December 31, 1993(3)---------- 120,198 99,295 219,493 Proved Developed Gas Reserves included above (millions of cubic feet): At September 30, 1990------------ 5,046 79,623 84,669 At September 30, 1991------------ 18,011 107,765 125,776 At December 31, 1991------------- 21,187 106,036 127,223 At December 31, 1992------------- 34,160 91,376 125,536 At December 31, 1993(3)---------- 65,652 99,295 164,947
TESORO PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
(1) THE COMPANY WAS NOT REQUIRED TO FILE RESERVE ESTIMATES WITH FEDERAL AUTHORITIES OR AGENCIES DURING THE PERIODS PRESENTED.
(2) SEE NOTE K REGARDING LITIGATION INVOLVING A NATURAL GAS SALES CONTRACT.
(3) NO MAJOR DISCOVERY OR ADVERSE EVENT HAS OCCURRED SINCE DECEMBER 31, 1993 THAT WOULD CAUSE A SIGNIFICANT CHANGE IN PROVED RESERVES.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
NONE.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information required under this Item will be contained in the Company's 1994 Proxy Statement which is incorporated herein by reference.
See also Executive Officers of the Registrant under Business in Item 1.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Information required under this Item will be contained in the Company's 1994 Proxy Statement which is incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT
Information required under this Item will be contained in the Company's 1994 Proxy Statement which is incorporated herein by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information required under this Item will be contained in the Company's 1994 Proxy Statement which is incorporated herein by reference.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
REPORTS ON FORM 8-K
(A) 1. FINANCIAL STATEMENTS
The following Consolidated Financial Statements of Tesoro Petroleum Corporation and its subsidiaries are included in Part II, Item 8 of this Form 10-K:
PAGE
Independent Auditors' Report----------------------- 33 Statements of Consolidated Operations -- Years Ended December 31, 1993, December 31, 1992 and September 30, 1991 and Three Months Ended December 31, 1991------------ 34 Consolidated Balance Sheets -- December 31, 1993 and December 31, 1992-------- 35 Statements of Consolidated Common Stock and Other Stockholders' Equity -- Years Ended December 31, 1993, December 31, 1992 and September 30, 1991 and Three Months Ended December 31, 1991------------------------- 37 Statements of Consolidated Cash Flows -- Years Ended December 31, 1993, December 31, 1992 and September 30, 1991 and Three Months Ended December 31, 1991------------ 38 Notes to Consolidated Financial Statements--------- 39
2. FINANCIAL STATEMENT SCHEDULES
[CAPTION] PAGE Schedule II -- Amounts Receivable From Related Parties and Underwriters, Promoters and Employees Other Than Related Parties -- Years Ended December 31, 1993, December 31, 1992 and September 30, 1991 and Three Months Ended December 31, 1991-------- 75 Schedule V -- Consolidated Property, Plant and Equipment -- Years Ended December 31, 1993, December 31, 1992 and September 30, 1991 and Three Months Ended December 31, 1991-------- 76 Schedule VI -- Consolidated Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment -- Years Ended December 31, 1993, December 31, 1992 and September 30, 1991 and Three Months Ended December 31, 1991-------- 77 Schedule VIII -- Consolidated Valuation and Qualifying Accounts and Reserves -- Years Ended December 31, 1993, December 31, 1992 and September 30, 1991 and Three Months Ended December 31, 1991-------- 78 All other schedules are omitted because of the absence of the conditions under which they are required or because the required information is included in the Consolidated Financial Statements or notes thereto.
3. EXHIBITS
SCHEDULE II
SCHEDULE V
SCHEDULE VI
SCHEDULE VIII
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.
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.