UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(MARK ONE)
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 1993
OR
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period From -------------- to---------------
Commission File Number 1-3473
TESORO PETROLEUM CORPORATION
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 95-0862768
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)
8700 TESORO DRIVE, SAN ANTONIO, TEXAS 78217
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 210-828-8484
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
Common Stock, $.16 2/3 par value New York Stock Exchange
Pacific Stock Exchange
Preferred Stock Purchase Rights New York Stock Exchange
Pacific Stock Exchange
12 3/4% Subordinated Debentures New York Stock Exchange
due March 15, 2001
13% Exchange Notes New York Stock Exchange
due December 1, 2000
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: NONE
INDICATE BY CHECK MARK WHETHER THE REGISTRANT (1) HAS FILED ALL REPORTS REQUIRED
TO BE FILED BY SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 DURING
THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE REGISTRANT WAS
REQUIRED TO FILE SUCH REPORTS), AND (2) HAS BEEN SUBJECT TO SUCH FILING
REQUIREMENTS FOR THE PAST 90 DAYS. YES /X/ NO .
INDICATE BY CHECK MARK IF DISCLOSURE OF DELINQUENT FILERS PURSUANT TO ITEM 405
OF REGULATION S-K IS NOT CONTAINED HEREIN, AND WILL NOT BE CONTAINED, TO THE
BEST OF REGISTRANT'S KNOWLEDGE, IN DEFINITIVE PROXY OR INFORMATION STATEMENTS
INCORPORATED BY REFERENCE IN PART III OF THIS FORM 10-K OR ANY AMENDMENT TO THIS
FORM 10-K. /X/
AT MARCH 1, 1994, THE AGGREGATE MARKET VALUE OF THE VOTING STOCK HELD BY
NONAFFILIATES OF THE REGISTRANT WAS APPROXIMATELY $157,902,878 BASED UPON THE
CLOSING PRICE OF ITS SHARES ON THE NEW YORK STOCK EXCHANGE COMPOSITE TAPE. AT
MARCH 1, 1994, THERE WERE 22,456,055 SHARES OF THE REGISTRANT'S COMMON STOCK
OUTSTANDING.
DOCUMENTS INCORPORATED BY REFERENCE
DOCUMENT FORM 10-K PART
Proxy Statement for 1994 Annual Meeting Part III
PART I
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.
2
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
3
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.
4
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.
5
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.
6
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.
7
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.
8
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.
9
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.
10
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
11
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
12
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
13
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.
14
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.
PRESENT POSITION
NAME AGE POSITION HELD SINCE
Michael D. Burke 50 President and Chief Executive Officer July 1992
Gaylon H. Simmons 54 Executive Vice President September 1993
Bruce A. Smith 50 Executive Vice President and Chief Financial September 1993
Officer
James W. Queen 54 Senior Vice President February 1992
Don E. Beere 53 Vice President, Controller February 1992
James E. Duncan 49 Vice President, Corporate Development March 1993
James C. Reed, Jr. 49 Vice President, General Counsel and Secretary September 1993
William M. Sims 49 Vice President, Environmental Products January 1992
William T. Van Kleef 42 Vice President, Treasurer March 1993
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.
Michael D. Burke -- President and Chief Executive Officer from July 1992. Group Vice
President of Texas Eastern Corporation from 1986 to 1992. President
and Chief Executive Officer of T.E. Products Pipeline Company,
L.P., an affiliate of Texas Eastern Corporation, from 1990 to 1992.
President of Texas Eastern Products Pipeline Company from 1986 to
1990.
Gaylon H. Simmons -- Executive Vice President from September 1993. Senior Vice
President, Refining, Marketing and Crude Supply from January 1993
to September 1993. President and Chief Executive Officer of Simmons
Technology Group, Inc., from 1991 to December 1992. President and
Chief Executive Officer of the Permian Corporation from 1989 to
1991. Vice President, Supply and Marketing for MAPCO Petroleum,
Inc. from 1985 through 1989.
Bruce A. Smith -- Executive Vice President and Chief Financial Officer from September
1993. Vice President and Chief Financial Officer from September
1992 to September 1993. Vice President and Treasurer of Valero
Energy Corporation from 1986 to 1992.
Don E. Beere -- Vice President, Controller from February 1992. Vice President,
Internal Audit and Management Systems of Tesoro Petroleum
Companies, Inc. from 1990 to 1992. Director, Internal Audit and
Management Systems from 1989 to 1990. Director, Internal Audit from
1986 to 1989.
15
James E. Duncan -- Vice President, Corporate Development from March 1993. Vice Presi-
dent, Treasurer from February 1992 to 1993. Vice President,
Controller of Tesoro Petroleum Companies, Inc., from 1990 to 1992.
Director, Corporate Accounting, from 1985 to 1990.
James C. Reed, Jr. -- Vice President, General Counsel and Secretary from September 1993.
Vice President, Secretary from December 1992 to September 1993.
Vice President, Secretary of Tesoro Petroleum Companies, Inc., from
February 1992 to December 1992. Vice President, Assistant Secretary
of Tesoro Petroleum Companies, Inc., from 1990 to 1992. Assistant
General Counsel and Assistant Secretary from 1982 to 1990.
William T. Van Kleef -- Vice President, Treasurer from March 1993. Financial Consultant
from January 1992 to February 1993. Consultant to Parker & Parsley
(successor to the assets and operations of Damson Oil Corporation
and its affiliates) from February 1991 to December 1991. Vice
President and Chief Financial Officer of Damson Oil Corporation
from 1986 to 1991.
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. 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
16
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
17
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,
18
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. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
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.
19
ITEM 6. SELECTED FINANCIAL DATA
The selected consolidated financial data should be read in conjunction with
Management's Discussion and Analysis of Financial Condition and Results of
Operations in Item 7 and the Company's Consolidated Financial Statements
contained in Item 8.
THREE MONTHS
YEARS ENDED ENDED
DECEMBER 31, DECEMBER 31, YEARS ENDED SEPTEMBER 30,
1993(1) 1992 1991(2) 1991 1990 1989
(IN MILLIONS EXCEPT PER SHARE AMOUNTS)
Statements of Consolidated Operations
Data:
Gross Operating Revenues(3)------ $ 831.0 946.5 240.6 1,085.0 996.6 762.6
Interest Income------------------ 1.8 3.2 .7 4.2 5.8 9.4
Gain (Loss) on Sales of
Assets------------------------- .1 4.0 -- .1 1.7 (4.9)
Other Income--------------------- 2.0 .7 2.6 1.7 2.4 (.1)
Total Revenues--------------- 834.9 954.4 243.9 1,091.0 1,006.5 767.0
Costs of Sales and Operating
Expenses----------------------- 756.8 926.1 228.6 1,015.9 920.5 718.6
General and Administrative------- 16.7 25.9 2.8 17.0 20.2 33.9
Depreciation, Depletion and
Amortization------------------- 22.6 16.6 4.2 15.0 12.8 21.9
Interest Expense----------------- 14.5 21.1 5.0 18.8 20.8 17.7
Other---------------------------- 5.6 4.6 .7 5.3 5.9 6.1
Income Tax Provision
(Benefit)---------------------- 1.7 5.4 3.0 15.1 3.6 (.7)
Earnings (Loss) Before the
Cumulative Effect of Accounting
Changes------------------------ 17.0 (45.3) (.4) 3.9 22.7 (30.5)
Cumulative Effect of Accounting
Changes------------------------ -- (20.6) -- -- -- --
Net Earnings (Loss)---------- $ 17.0 (65.9) (.4) 3.9 22.7 (30.5)
Earnings (Loss) per Primary and Fully
Diluted* Share(1):
Earnings (loss) before the
cumulative effect of accounting
changes------------------------ $ .54 (3.87) (.19) (.37) .96 (2.83)
Cumulative effect of accounting
changes------------------------ -- (1.47) -- -- -- --
Net earnings (loss)-------------- $ .54 (5.34) (.19) (.37) .96 (2.83)
Other Selected Financial Data:
Capital Expenditures------------- $ 37.5 15.4 3.9 24.5 23.1 13.2
Total Assets--------------------- $ 434.5 446.7 494.7 496.8 504.9 445.3
Working Capital------------------ $ 124.5 122.6 106.1 95.4 117.9 105.1
Long-Term Debt and Other
Obligations, Including Current
Portion(1)--------------------- $ 185.5 201.7 189.4 184.7 168.0 163.2
Redeemable Preferred Stock(1)---- $ 78.1 71.7 57.4 57.4 57.4 57.4
Common Stock and Other
Stockholders' Equity(1)(4)----- $ 58.5 50.7 137.0 137.4 141.4 125.4
* ANTI-DILUTIVE.
(1) FOR PRO FORMA INFORMATION ON THE EFFECTS OF A RECAPITALIZATION WHICH
OCCURRED IN FEBRUARY 1994, 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.
(2) THE COMPANY'S FISCAL YEAR-END WAS CHANGED FROM SEPTEMBER 30 TO DECEMBER
31, EFFECTIVE JANUARY 1, 1992.
(3) THE COMPANY IS INVOLVED IN LITIGATION RELATED TO A NATURAL GAS SALES
CONTRACT. FOR ADDITIONAL INFORMATION CONCERNING THIS DISPUTE, SEE LEGAL
PROCEEDINGS IN ITEM 3 AND NOTES K AND P OF NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS IN ITEM 8.
(4) NO DIVIDENDS WERE PAID ON COMMON SHARES DURING THE PERIODS PRESENTED
ABOVE.
20
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.
21
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.
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.
CREDIT ARRANGEMENTS
Letters of credit are issued to obtain crude oil feedstocks for the
Company's refinery and for other operating and corporate needs. The requirements
for letters of credit have been significantly
22
reduced due to the Company's market-driven operational strategy. On October 29,
1993, the Company elected to terminate its secured Letter of 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. Concurrently, in the latter part of 1993, the Company negotiated
several interim credit arrangements collateralized by either cash or inventory.
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 March
1, 1994.
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 'State'), the Company's largest supplier of crude oil.
Under the Substitution Agreement, the Company has pledged the capital stock of
Tesoro Alaska Petroleum Company, a 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 from the State. 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 1994 and contains
various covenants and restrictions customary to inventory financing
transactions.
Effective October 29, 1993, a subsidiary of the Company, Tesoro Exploration
and Production Company ('Tesoro E&P'), entered into a $30 million reducing
revolving credit facility ('E&P Facility') which is secured by the capital stock
of Tesoro E&P and its natural gas properties in the Bob West Field. The E&P
Facility is subject to a quarterly borrowing base determination which was
initially determined to be $20 million. Since the Company does not have any
immediate requirement for additional borrowing availability, it does not expect
to request an increase in the amount of borrowing capacity under the E&P
Facility. The facility expires December 31, 1996. No borrowings were outstanding
under the E&P Facility at March 1, 1994.
The Company is currently negotiating with several financial institutions
with regard to providing a long-term corporate credit facility which would
replace the cash-secured letter of credit arrangements, the Substitution
Agreement and the E & P Facility. Based on these negotiations, the Company
believes it will be able to consummate a $115 million long-term corporate credit
facility during the first half of 1994 that will provide for the issuance of
letters of credit, cash borrowings based on domestic gas reserves and financing
of up to $15 million for a proposed vacuum unit at the Company's refinery. If
the long-term corporate credit facility is not consummated, the Company may be
required to reduce its working capital requirements or the amount of capital
expenditures proposed for 1994.
DEBT AND OTHER OBLIGATIONS
The Company's funded debt obligations as of December 31, 1993 included
approximately $108.8 million of Subordinated Debentures which bear interest at
12 3/4% and require sinking fund payments sufficient to annually retire $11.25
million principal amount of Subordinated Debentures. Upon completion of the
Recapitalization, $44.1 million of Subordinated Debentures were tendered in
exchange for a like amount of Exchange Notes, which will satisfy approximately
four years of sinking fund requirements for the Subordinated Debentures. The
indenture governing the Subordinated Debentures contains certain covenants,
including a restriction which prevents the current payment of dividends on the
Common Stock and currently limits the Company's ability to purchase or redeem
any shares of its capital stock. The Exchange Notes bear interest at 13% and
mature on December 1, 2000. The limitation on dividend payments included in the
indenture governing the Exchange Notes is less restrictive than the limitation
imposed by the Subordinated Debentures. The Subordinated Debentures and Exchange
Notes are redeemable at the option of the Company at 100% of principal amount
plus accrued interest. For further information on redemption
23
provisions and restrictions on dividends, see Note I of Notes to Consolidated
Financial Statements in Item 8.
Under an agreement reached in 1993 which settled a contractual dispute with
the State, the Company paid the State $10.3 million in January 1993 and is
obligated to make variable monthly payments to the State over the nine years
following the settlement date based on a per barrel charge that increases 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.
CAPITAL EXPENDITURES
The Company has under consideration total capital expenditures ranging from
approximately $65 million to $80 million in 1994. The proposal for 1994 includes
capital expenditures of approximately $29 million for the continued development
of the Bob West Field, which could be increased by $10 million to $15 million
based on additional development drilling proposed by the operators. In addition,
the proposal for 1994 includes capital expenditures of $32 million for the
refining and marketing operations, of which $24 million is associated with the
installation of a vacuum unit at the Kenai refinery to allow the Company to
further upgrade residual fuel oil production into higher-valued products. The
aggregate capital expenditures the Company will be able to incur in 1994 will
depend on the Company's ability to generate funds from operations, financings
and other sources. As previously indicated, the Company is negotiating a
long-term corporate credit facility which will include up to $15 million for the
financing of the proposed vacuum unit.
CASH FLOWS FROM OPERATING, INVESTING AND FINANCING ACTIVITIES
During 1993, cash and cash equivalents decreased by $10.3 million and
short-term investments decreased by $14.1 million. At December 31, 1993, the
Company's cash and short-term investments totaled $42.5 million, which included
restricted funds of $25.4 million as collateral for outstanding letters of
credit. Working capital amounted to $124.5 million at December 31, 1993. Net
cash from operating activities of $19.5 million in 1993 was primarily due to net
earnings adjusted for certain non-cash charges, partially offset by payments
totaling $12.9 million to the State under the settlement agreement entered into
in January 1993 and increased working capital requirements. Net cash used in
investing activities of $23.5 million during 1993 included capital expenditures
of $37.5 million, mainly for exploration and development activities in the Bob
West Field. During 1993, the Company completed the expansion of a gas processing
facility and pipeline and drilled 15 development gas wells in this field. In
addition, the Company participated in drilling four exploratory wells and one
development well outside of the Bob West Field in 1993. These uses of cash in
investing activities were partially offset by the net decrease of $14.1 million
in short-term investments. Net cash used in financing activities of $6.3 million
in 1993 included the repurchase of $11.25 million principal amount of
Subordinated Debentures for $9.7 million in cash, partially offset by borrowings
of $5.0 million under the E&P Facility. The Company did not pay dividends on
preferred stocks in 1993 which resulted in total dividend arrearages of $28.7
million at December 31, 1993. Dividend arrearages on preferred stocks have been
satisfied by consummation of the Recapitalization.
During 1992, cash and cash equivalents decreased by $14.2 million and
short-term investments increased by $20.0 million. Cash flows from operating
activities of $11.4 million included a net loss, offset by certain significant
non-cash charges including the cumulative effect of accounting changes,
depreciation, depletion and amortization and the settlement with the State, and
by reduced working capital requirements. Net cash used in investing activities
of $21.1 million in 1992 was mainly due to capital expenditures of $15.4
million, primarily for continued exploration and development activities
24
in the Bob West Field and capital improvements in Alaska, and to the purchase of
short-term investments of $24.0 million. 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 on the
Consolidated Balance Sheets. Partially offsetting cash used in investing
activities in 1992 were net proceeds of $12.9 million from sales of assets.
During 1992, the Company received, before expenses, $6.8 million for the sale of
the Company's Indonesian operations, $3.3 million for the sale of the corporate
aircraft and related assets and $2.1 million for the sale of certain exploration
and production properties outside of the Bob West Field. Cash flows used in
financing activities of $4.5 million in 1992 included the repayment of $6.5
million of long-term debt, primarily related to borrowings under a secured
financing agreement for development of natural gas reserves in the Bob West
Field. This financing arrangement, under which the Company borrowed $2.0 million
in 1992, was terminated by the Company in December 1992. The Company deferred
payments of dividends on preferred stocks in 1992.
During 1991, cash and cash equivalents decreased $16.1 million. Cash flows
from operating activities of $17.9 million included net earnings of $3.9
million, partially offset by a $5.2 million payment to the Department of Energy.
Net cash used in investing activities of $24.7 million in 1991 was primarily
comprised of capital expenditures for exploration and development activities in
the Bob West Field and capital improvements in Alaska. Cash flows used in
financing activities of $9.3 million in 1991 were primarily for dividend
payments on preferred stocks for three and one-half quarters which totaled $8.0
million.
RESULTS OF OPERATIONS
Effective January 1, 1992, the Company changed its fiscal year-end from
September 30 to December 31. Accordingly, the information contained herein
addresses the Company's results of operations for the year ended December 31,
1993 compared to the years ended December 31, 1992 and September 30, 1991. The
results of operations for the three-month period from October 1, 1991 to
December 31, 1991 are discussed separately.
Net earnings of $17.0 million ($.54 per share) in 1993 compare to a net loss
of $65.9 million ($5.34 per share) in 1992. Each of the Company's operating
segments, together with reduced corporate expenses, contributed to the
substantial improvement in 1993.
The comparability of 1993 and 1992, however, was impacted by certain
significant transactions. During 1993, the Company's earnings benefited from the
resolution of several state tax issues resulting in a net reduction of $3.0
million in income tax expense and $5.2 million in interest expense. In addition,
a gain of $1.4 million was recognized for the retirement of $11.25 million face
amount of Subordinated Debentures which were purchased in January 1993 for $9.7
million cash to satisfy the initial sinking fund requirement. The 1992 loss
included charges of $20.6 million for the cumulative effect of accounting
changes, $10.5 million for settlement of a contractual dispute with the State,
and $9.1 million for a cost reduction program and other employee terminations,
partially offset by a gain of $5.8 million from the sale of the Company's
Indonesian operations. Excluding these significant transactions for both years,
the improvement in 1993 as compared to 1992 was attributable to increased gross
margins on sales of refined products, increased natural gas production in South
Texas and reduced general and administrative expenses.
The net loss of $65.9 million ($5.34 per share) in 1992 compares to net
earnings of $3.9 million (a loss of $.37 per share after preferred dividend
requirements) in 1991. As described above, several significant transactions
contributed to the net loss in 1992. Excluding these transactions, the decrease
in results of operations in 1992 as compared to 1991 was primarily due to lower
operating results from the Company's refining and marketing operations and
reduced revenues from the Company's Bolivian and Indonesian operations,
partially offset by increased production and sales prices of natural gas from
the Company's South Texas field.
25
A discussion and analysis of the factors contributing to these results and
the changes in financial condition are presented below. The consolidated
financial statements and related footnotes in Item 8, together with the
following information, are intended to provide shareholders and investors with a
reasonable basis for assessing the Company's operations, but should not serve as
the sole criterion for predicting the future performance of the Company. The
Company conducts its operations in the following business segments: refining and
marketing; exploration and production; and oil field supply and distribution.
REFINING AND MARKETING
1993 1992 1991
(DOLLARS IN MILLIONS EXCEPT AS
INDICATED)
Gross Operating Revenues------------- $ 687.2 810.7 898.6
Costs of Sales----------------------- 584.6 738.9 802.8
Gross Margin--------------------- 102.6 71.8 95.8
Operating Expenses and Other--------- 77.1 76.5 67.5
Depreciation and Amortization-------- 10.3 10.2 9.0
Operating Profit (Loss)---------- $ 15.2 (14.9) 19.3
Refinery Throughput (average daily
barrels)--------------------------- 49,753 61,425 68,192
Sales of Refinery Production:
Sales ($ per barrel)------------- $ 21.91 21.30 24.40
Margin ($ per barrel)------------ $ 4.19 1.18 2.77
Volume (average daily
barrels)----------------------- 49,425 62,218 66,837
Sales of Products Purchased for
Resale:
Sales ($ per barrel)------------- $ 26.15 27.58 31.48
Margin ($ per barrel)------------ $ 1.35 1.09 .37
Volume (average daily
barrels)----------------------- 19,340 25,222 23,318
Sales Volumes (average daily
barrels):
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
Sales Price ($ per barrel):
Gasoline------------------------- $ 27.64 28.89 30.69
Jet fuel------------------------- $ 28.10 27.76 35.15
Other distillates---------------- $ 26.95 25.78 29.78
Residual fuel oil---------------- $ 11.19 11.60 15.15
1993 COMPARED TO 1992. During 1993, the Company implemented a market-driven
operational strategy which emphasizes the upgrading of refinery feedstocks and
matching production from the Company's Alaska refinery with the refined product
demand within Alaska. This strategy has resulted in a reduction in the Company's
overall refinery production, particularly lower-valued residual fuel oil. The
markets for residual fuel oil have been weak due to the global oversupply of
this product since the Persian Gulf War and current projections indicate that
such markets will continue to be weak in the future.
In implementing the Company's operational strategy, the Company reduced its
daily refinery throughput during 1993 by 19% from the 1992 level. This reduction
in throughput has enabled the Company to reduce the portion of lower quality
crude oil in the feedstock blend. By utilizing a greater percentage of higher
quality feedstocks (which results in production yields with greater margins than
26
production yields from a higher percentage of lower quality Alaska North Slope
crude oil), the Company can successfully operate the refinery at the reduced
throughput levels. Operating the refinery at lower throughput levels results in
less production of certain products, particularly residual fuel oil, for which
there is no market in Alaska and which therefore must be exported from Alaska
and sold into West Coast and Far Eastern markets. Implementation of this
strategy has resulted in an improvement in the Company's aggregate refinery
gross margin, enabling the Company to operate the refinery more profitably at
the lower throughput level.
The decrease in volumes was a significant factor in the change in revenues
in 1993 as compared to 1992. Average sales prices were essentially unchanged;
however, average margins increased in 1993, particularly with regard to sales of
refinery production. Partially offsetting the decrease in revenues from refined
products was a $33.8 million increase in sales of crude oil. Costs of sales in
1993 decreased due to lower volumes and prices and to the $10.5 million charge
in 1992 for settlement of a contractual dispute with the State for the purchase
of crude oil. The $30.1 million improvement in overall operating profit was
primarily due to the improved margins on refined product sales, part of which
was attributable to the favorable market conditions during the fourth quarter of
1993. While the price of crude oil dropped in the 1993 fourth quarter, the
Company's refined product margins held steady or improved. These market
conditions are not expected to continue during the first quarter of 1994.
1992 COMPARED TO 1991. Revenues from the sales of refined products
decreased 15% in 1992 as compared to 1991. Although volumes decreased only 3%,
average sales prices decreased almost 12%. The $34.2 million decrease in
operating results was primarily due to a further deterioration of gross margins
on refined product sales, particularly residual fuel oil. The recovery of crude
oil costs at the Company's Alaska refinery continued to be adversely impacted by
weak markets for the refinery's output of residual fuel oil, which approximated
40% of the total output of the refinery during 1992 and the prior two years.
During the latter months of 1992, the Company also incurred additional costs to
produce oxygenated gasoline. The market for oxygenated gasoline was such that
the additional costs to produce the oxygenated gasoline could not be entirely
recovered with increased sales prices. In addition to increased operating costs
for environmental issues and reductions in workforce, operating results for 1992
also included higher costs of sales resulting from the settlement of the
contractual dispute with the State for the purchase of crude oil. These
increases in operating costs were partially offset by a transportation rebate
received in 1992.
27
EXPLORATION AND PRODUCTION
1993 1992 1991
(DOLLARS IN MILLIONS EXCEPT AS
INDICATED)
United States:
Gross operating revenues--------- $ 50.5 18.8 5.2
Production costs----------------- 6.8 3.8 1.2
Depreciation, depletion and
amortization------------------- 11.1 4.9 2.9
Other---------------------------- .3 1.2 .5
Operating Profit -- United
States--------------------- 32.3 8.9 .6
Bolivia:
Gross operating revenues--------- 12.6 17.9 24.5
Production costs----------------- 1.2 .7 .6
Other---------------------------- 3.0 4.6 2.7
Operating Profit --
Bolivia-------------------- 8.4 12.6 21.2
Indonesia:
Gross operating revenues--------- -- 6.0 29.5
Production costs----------------- -- 3.7 9.5
Depreciation, depletion and
amortization------------------- -- .3 1.7
Other---------------------------- -- (5.6) 4.5
Operating Profit --
Indonesia------------------ -- 7.6 13.8
Total Operating Profit--------------- $ 40.7 29.1 35.6
Natural Gas -- United States:
Production (average daily mcf) --
Tennessee Gas contract------- 10,599 3,974 1,300
Spot market and other-------- 28,168 9,986 6,135
Total Production--------- 38,767 13,960 7,435
Average sales price per mcf --
Tennessee Gas contract------- $ 7.59 4.46 --
Spot market------------------ $ 2.03 1.83 1.88
Average---------------------- $ 3.55 3.68 1.88
Average lifting cost per mcf----- $ .48 .74 .44
Depletion per mcf---------------- $ .78 .95 1.06
Proved reserves -- end of period
(bcf)-------------------------- 120.2 73.8 33.1
Natural Gas -- Bolivia:
Production (average daily
mcf)--------------------------- 19,232 19,421 19,322
Average sales price per mcf------ $ 1.22 1.67 3.06
Average lifting cost per net
equivalent mcf----------------- $ .14 .08 .09
Proved reserves -- end of period
(bcf)-------------------------- 99.3 107.0 115.2
Crude Oil -- Indonesia (sold
effective May 1, 1992):
Production (average daily
barrels)----------------------- -- 2,714 3,315
Average sales price per
barrel------------------------- $ -- 18.20 24.39
Average lifting cost per net
equivalent mcf----------------- $ -- 1.94 1.35
Proved reserves -- end of period
(millions of barrels)---------- -- -- 4.5
1993 COMPARED TO 1992. Successful development drilling in the Bob West
Field in South Texas was the primary contributing factor to this segment's
improvement in 1993. The number of producing wells increased to 25 at the 1993
year-end compared to 10 at the end of 1992 resulting in a significant increase
in natural gas production. The increase in revenues was primarily caused by
these higher production levels, partially offset by a slight decline in average
sales prices of $3.55 per mcf in 1993 as compared to $3.68 per mcf in 1992.
Total production costs and depreciation, depletion and
28
amortization increased in 1993 due to the higher production volumes; however,
the depletion rate decreased due to the 63% increase in proved reserves. See
Legal Proceedings in Item 3 and Notes K and P of Notes to Consolidated Financial
Statements regarding litigation involving the contract for the sale of gas from
the Bob West Field.
In February 1994, the common carrier pipeline facilities transporting gas
from the Bob West Field were at capacity and the Company's production from the
field was curtailed. The curtailment affects only production subject to spot
market prices and the Company will continue to be able to produce and transport
all of its gas in the Bob West Field which is subject to the Tennessee Gas
contract. A new common carrier pipeline, which will provide transportation for
the increased gas production from the Bob West Field, is being constructed by
Coastal States Gas Transmission Company and is expected to be completed in the
second quarter of 1994. Because of the curtailment, the Company estimates that
its share of production from the Bob West Field in the first quarter of 1994
will be reduced to approximately 46 million cubic feet per day as compared to
the 1993 fourth quarter level of approximately 58 million cubic feet per day.
The Company expects that further curtailments will occur prior to June 1, 1994,
the anticipated completion date of the new pipeline.
The Bolivian operations experienced a decline in revenues primarily due to
reduced contractual sales prices for the natural gas production. Under a sales
contract with YPFB (the Bolivian state-owned oil Company), the Company's
Bolivian natural gas production is sold to YPFB, who in turn sells the natural
gas to the Republic of Argentina. The contract, including the pricing provision,
is subject to renegotiation in April 1994 for another two-year period.
The 1992 operating results from the Indonesian operations, which were sold
effective May 1, 1992, included a gain from the sale of $5.8 million.
1992 COMPARED TO 1991. The operating profit decline in this segment during
1992 as compared to 1991 was primarily due to reduced sales prices and
production levels of crude oil from the Company's former Indonesian operations,
which were sold effective May 1, 1992, and contractually reduced sales prices
for the Company's natural gas production in Bolivia, also effective May 1, 1992.
These decreases in 1992 were partially offset by the $5.8 million gain from the
sales of the Indonesian operations and increased natural gas production and
sales prices from the Company's Bob West Field.
OIL FIELD SUPPLY AND DISTRIBUTION
1993 1992 1991
(DOLLARS IN MILLIONS)
Gross Operating Revenues------------- $ 80.7 93.5 134.3
Costs of Sales----------------------- 68.4 82.4 118.7
Gross Margin--------------------- 12.3 11.1 15.6
Operating Expenses and Other--------- 15.5 15.3 15.6
Depreciation and Amortization-------- .4 .5 .5
Operating Loss------------------- $ (3.6) (4.7) (.5)
Refined Product Sales (average daily
barrels)--------------------------- 7,368 8,476 10,470
1993 COMPARED TO 1992. Revenues and costs of sales in this segment during
1993 decreased when compared to 1992 due to the discontinuance of the
operations, in the 1992 second quarter, of a wholesale distribution facility in
Oklahoma. In addition, the decrease in crude oil prices during 1993 resulted in
a correlating decrease in refined product prices. Margins, however, on both
refined product and merchandise sales improved in 1993 due to the consolidation
of certain of the Company's locations and elimination of marginally profitable
locations, including the facility in Oklahoma. Strong competition in an
oversupplied market continues to adversely impact this segment. Effective at the
1992 year-end, the Company acquired the remaining 50% interest in Tesoro-Leevac
Petroleum Company, a joint venture, which allowed the Company to consolidate
certain of its
29
marine terminals; however, this acquisition did not have a material impact on
the revenues and margins of this segment in 1993.
1992 COMPARED TO 1991. Revenues from the sales of refined products
decreased in 1992 as compared to 1991 primarily as a result of the Company's
discontinuance, in the 1992 second quarter, of the operation of the wholesale
distribution facility in Oklahoma. In addition, refined product sales prices and
margins decreased as a result of a generally weak U.S. economy, continuing
overall depressed drilling activity and an oversupply of refined products
following the Persian Gulf crisis. The operating loss of $4.7 million in 1992
was a further deterioration from the operating loss of $.5 million in 1991. This
overall decrease was mainly attributable to lower margins on refined product
sales.
GENERAL AND ADMINISTRATIVE EXPENSES
General and administrative expenses of $16.7 million in 1993 compares to
$25.9 million in 1992 and $17.0 million in 1991. The decrease in 1993 was
primarily due to expenses for a cost reduction program and other employee
terminations in 1992 totaling $9.1 million, of which $1.3 million was charged to
the operating segments, with no significant comparable charges recorded in 1993.
The remaining decrease in 1993 was attributable to the savings from this
program. The increase in 1992 as compared to 1991 was mainly due to the cost of
this program in 1992.
INTEREST AND OTHER INCOME
Interest income of $1.8 million in 1993 compares to $3.2 million in 1992 and
$4.2 million in 1991. The decreases in interest income in 1993 and 1992 were due
to lower interest rates on less cash available for investment. During 1993 and
1991, the Company had no major asset sales as compared to 1992 which included a
$5.8 million gain from the sales of the Company's Indonesian
operations partially offset by a $1.8 million loss from the sale of drilling
rigs and costs related to the disposition of the Company's remaining oil field
tool rental assets. Other income increased in 1993 as compared to 1992 due to a
$1.4 million gain from the retirement of $11.25 million principal amount of
Subordinated Debentures in January 1993.
INTEREST EXPENSE
Interest expense of $14.5 million in 1993 compares to $21.1 million in 1992
and $18.8 million in 1991. The decrease in 1993 was mainly due to a reduction of
$5.2 million for resolution of outstanding issues with several state taxing
authorities.
INCOME TAXES
Income taxes of $1.7 million in 1993 compares to $5.4 million in 1992 and
$15.1 million in 1991. The decrease in 1993 included a reduction of $3.0 million
for resolution of outstanding issues with several state taxing authorities. In
addition, foreign income taxes continued to decrease in 1993 and 1992 due to
reduced revenues from the Company's Bolivian and former Indonesian operations.
THREE MONTHS ENDED DECEMBER 31, 1991 COMPARED TO THE THREE MONTHS
ENDED DECEMBER 31, 1990
The Statement of Consolidated Operations and Statement of Consolidated Cash
Flows for the three months ended December 31, 1991 are presented in the
Consolidated Financial Statements included elsewhere herein. For discussion
purposes, results for the three months ended December 31, 1991 are compared to
the unaudited three-month period ended December 31, 1990, as set forth in Note C
of Notes to Consolidated Financial Statements included in Item 8.
The net loss of $.4 million for the three months ended December 31, 1991
(the '1991 quarter') represented a decrease of $5.3 million from the net
earnings of $4.9 million recorded during the three months ended December 31,
1990 (the '1990 quarter'). Total revenues of $243.9 million for the 1991 quarter
decreased $92.3 million, or 27%, from the 1990 quarter, largely due to lower
sales prices for refined products. The 1990 quarter had been impacted by
escalating refined product and crude oil prices during the conflict in the
Persian Gulf. During the 1991 quarter, the Company's exploration
30
and production operations in Indonesia realized lower sales prices on reduced
crude oil production as compared to the 1990 quarter. Also contributing to the
decrease in total revenues in the 1991 quarter was reduced interest income
resulting from lower interest rates on less cash available for investment.
Partially offsetting these decreases in the 1991 quarter were revenues from the
Company's convenience store operations in Alaska and other income resulting from
settlement of a matter in litigation. Costs of sales and operating expenses
decreased $83.4 million, or 27%, in the 1991 quarter as compared to the 1990
quarter, due primarily to the lower prices of crude oil and refined products,
partially offset by costs from the Company's convenience store operations.
The Refining and Marketing segment's operating profit of $1.7 million in the
1991 quarter was a decrease of $.8 million from the $2.5 million operating
profit recorded in the 1990 quarter. The decrease was primarily due to lower
sales prices for residual fuel oil, which continued to be adversely impacted by
the weak markets for this product.
The Exploration and Production segment's operating profit of $7.4 million in
the 1991 quarter decreased $8.2 million from the $15.6 million operating profit
recorded in the 1990 quarter. The decrease was mainly due to lower crude oil
sales prices on reduced production volumes from the Company's Indonesian
operations. The Company's Indonesian crude oil production decreased by 1,435
barrels per day, with an average sales price of $20.57 per barrel during the
1991 quarter as compared to $29.39 per barrel during the 1990 quarter. The
Company's operations in Bolivia also experienced lower natural gas sales prices
on reduced production volumes in the 1991 quarter. Natural gas production from
the Company's Bolivian operations decreased by 487 mcf per day with an average
sales price of $2.42 per mcf during the 1991 quarter as compared to $2.92 per
mcf in the 1990 quarter. The Company's natural gas production in the Bob West
Field increased during the 1991 quarter; however, revenues from this production
were substantially offset by increased depreciation and depletion, insurance
costs and legal fees associated with these operations.
The Oil Field Supply and Distribution segment's operating loss of $1.2
million in the 1991 quarter was a decrease of $2.8 million from the $1.6 million
operating profit recorded in the 1990 quarter. This decrease in operating
results was primarily attributable to lower margins on refined product sales
caused by the decline in drilling rig activity in the United States. The 1990
quarter included the effect of increased demand experienced during the Persian
Gulf conflict.
General and administrative expenses of $2.8 million for the 1991 quarter
decreased by $1.2 million from the 1990 quarter, primarily due to an insurance
reimbursement during the 1991 quarter for certain costs incurred in defense of
litigation in prior years. Depreciation, depletion and amortization expense of
$4.2 million in the 1991 quarter increased by $1.2 million from the 1990
quarter, due mainly to exploration and production activities in the Bob West
Field. The income tax provision of $3.0 million in the 1991 quarter decreased by
$3.8 million from the 1990 quarter, primarily due to lower foreign taxes
resulting from reduced revenues from the Company's operations in Indonesia.
LITIGATION
The Company is subject to certain commitments and contingencies, including a
contingency relating to a natural gas sales contract dispute with Tennessee Gas
Pipeline Company ('Tennessee Gas'). The Company receives payment from Tennessee
Gas for the purchase of a portion of the natural gas from the Bob West Field at
a contract price substantially greater than spot market prices. Tennessee Gas
filed suit, claiming, among other things, that the contract is not in effect
and, in the alternative, that the contract price has been incorrectly
calculated. The Company prevailed on all issues at the trial court level, and
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
31
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 those 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 upon 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. If Tennessee Gas ultimately prevails in the
litigation, the impact on the Company's future cash flows and liquidity would be
material. For further information, see Legal Proceedings in Item 3 and Notes K
and P of Notes to Consolidated Financial Statements in Item 8.
ENVIRONMENTAL
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 or install additional controls
or other modifications or changes in use for certain emission sources. The
Company is currently involved in remedial response and has incurred cleanup
expenditures associated with environmental matters at a number of sites,
including certain of its own properties. Although it is difficult to quantify
the potential impact of compliance with environmental protection laws,
management believes that the ultimate overall aggregate cost to the Company of
environmental remediation with regard to these sites will not result in a
material adverse effect on the Company's financial condition. Although the level
of future expenditures for environmental purposes, including cleanup
obligations, is impossible to determine with any degree of probability, it is
management's opinion that, based on current knowledge and the extent of such
expenditures to date, the ultimate aggregate cost of environmental remediation
will not have a material adverse effect on the Company's financial condition.
IMPACT OF CHANGING PRICES
The Company's operating results and cash flows are sensitive to the volatile
changes in energy prices. Major shifts in the cost of crude oil and the price of
refined products can result in a change in gross margin from the refining and
marketing operations as prices received for refined products may or may not keep
pace with changes in crude costs. These energy prices, together with volume
levels, also determine the carrying value of crude oil and refined product
inventory.
Likewise, major changes in natural gas prices impact revenues and the
estimated future cash flows from the Company's exploration and production
operations. The carrying value of oil and gas assets may also be subject to
non-cash write-downs based on changes in natural gas prices and other
determining factors.
32
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
33
TESORO PETROLEUM CORPORATION
STATEMENTS OF CONSOLIDATED OPERATIONS
(DOLLARS IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
THREE MONTHS
YEARS ENDED ENDED YEAR ENDED
DECEMBER 31, DECEMBER 31, SEPTEMBER 30,
1993 1992 1991 1991
Revenues:
Gross operating revenues--------- $ 831,007 946,446 240,586 1,084,954
Interest income------------------ 1,803 3,170 682 4,209
Gain on sales of assets---------- 60 4,024 9 119
Other---------------------------- 2,040 732 2,596 1,734
Total Revenues--------------- 834,910 954,372 243,873 1,091,016
Costs and Expenses:
Costs of sales and operating
expenses----------------------- 756,764 926,082 228,569 1,015,859
General and administrative------- 16,712 25,849 2,849 17,003
Depreciation, depletion and
amortization------------------- 22,591 16,552 4,225 15,005
Interest expense----------------- 14,550 21,115 4,966 18,804
Other---------------------------- 5,640 4,636 722 5,312
Total Costs and Expenses----- 816,257 994,234 241,331 1,071,983
Earnings (Loss) Before Income Taxes
and the Cumulative Effect of
Accounting Changes----------------- 18,653 (39,862) 2,542 19,033
Income Tax Provision----------------- 1,697 5,383 2,958 15,094
Earnings (Loss) Before the Cumulative
Effect of Accounting Changes------- 16,956 (45,245) (416) 3,939
Cumulative Effect of Accounting
Changes---------------------------- -- (20,630) -- --
Net Earnings (Loss)------------------ $ 16,956 (65,875) (416) 3,939
Net Earnings (Loss) Applicable to
Common Stock----------------------- $ 7,749 (75,082) (2,717) (5,268)
Earnings (Loss) Per Primary and Fully
Diluted* Share:
Earnings (Loss) Before the
Cumulative Effect of Accounting
Changes------------------------ $ .54 (3.87) (.19) (.37)
Cumulative Effect of Accounting
Changes------------------------ -- (1.47) -- --
Net Earnings (Loss)-------------- $ .54 (5.34) (.19) (.37)
* ANTI-DILUTIVE
The accompanying notes are an integral part of these consolidated financial
statements.
34
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.
35
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.
36
TESORO PETROLEUM CORPORATION
STATEMENTS OF CONSOLIDATED COMMON STOCK
AND OTHER STOCKHOLDERS' EQUITY
(DOLLARS IN THOUSANDS)
$2.16 CUMULATIVE
CONVERTIBLE ADDITIONAL RETAINED
PREFERRED STOCK COMMON STOCK PAID-IN EARNINGS DEFERRED
SHARES AMOUNT SHARES AMOUNT CAPITAL (DEFICIT) COMPENSATION
Balances at September 30, 1990------- 1,319,576 $1,320 14,059,952 $2,343 $ 86,608 $ 51,330 $ (216)
Net earnings--------------------- -- -- -- -- -- 3,939 --
Cash dividends on preferred
stocks------------------------- -- -- -- -- -- (8,028) --
Stock awards--------------------- -- -- 8,213 2 56 -- 51
Other---------------------------- -- -- -- -- -- (32) --
Balances at September 30, 1991------- 1,319,576 1,320 14,068,165 2,345 86,664 47,209 (165)
Net loss------------------------- -- -- -- -- -- (416) --
Stock awards--------------------- -- -- (1,120) (1 ) (6) -- 29
Other---------------------------- -- -- -- -- -- (8) --
Balances at December 31, 1991-------- 1,319,576 1,320 14,067,045 2,344 86,658 46,785 (136)
Net loss------------------------- -- -- -- -- -- (65,875) --
Accrued dividends on preferred
stocks, not declared or
paid--------------------------- -- -- -- -- -- (20,525) --
Conversion of preferred stock to
common stock------------------- (13) -- 22 -- -- -- --
Stock awards--------------------- -- -- 4,095 1 334 -- (209)
Other---------------------------- -- -- (122) -- -- (32) --
Balances at December 31, 1992-------- 1,319,563 1,320 14,071,040 2,345 86,992 (39,647) (345)
Net earnings--------------------- -- -- -- -- -- 16,956 --
Accrued dividends on preferred
stocks, not declared or
paid--------------------------- -- -- -- -- -- (9,175) --
Stock awards--------------------- -- -- 18,196 3 (7) -- 108
Other---------------------------- -- -- -- -- -- (32) --
Balances at December 31, 1993-------- 1,319,563 $1,320 14,089,236 $2,348 $ 86,985 $ (31,898) $ (237)
The accompanying notes are an integral part of these consolidated financial
statements.
37
TESORO PETROLEUM CORPORATION
STATEMENTS OF CONSOLIDATED CASH FLOWS
(DOLLARS IN THOUSANDS)
THREE MONTHS
YEARS ENDED ENDED YEAR ENDED
DECEMBER 31, DECEMBER 31, SEPTEMBER 30,
1993 1992 1991 1991
Cash Flows From (Used In) Operating
Activities:
Net earnings (loss)-------------- $ 16,956 (65,875) (416) 3,939
Adjustments to reconcile net
earnings (loss) to net cash
from (used in) operating
activities:
Cumulative effect of
accounting changes--------- -- 20,630 -- --
Depreciation, depletion and
amortization--------------- 22,591 16,552 4,225 15,005
Gain on sales of assets------ (60) (4,024) (9) (119)
Other------------------------ 1,901 4,231 599 2,704
Changes in assets and
liabilities:
Receivables-------------- 7,539 12,320 6,524 33,531
Inventories-------------- 325 7,986 (10,620) (20,663)
Investment in Tesoro
Bolivia Petroleum
Company---------------- (3,524) 3,908 8,756 (5,991)
Other assets------------- (2,435) 3,484 (4,748) 2,899
Accounts payable and
other current
liabilities------------ (12,800) (5,282) (3,877) (11,253)
Obligation payments to
State of Alaska-------- (12,910) -- -- --
Other liabilities and
obligations------------ 1,901 17,458 (774) (2,107)
Net cash from (used
in) operating
activities--------- 19,484 11,388 (340) 17,945
Cash Flows From (Used In) Investing
Activities:
Capital expenditures------------- (37,451) (15,446) (3,858) (24,484)
Proceeds from sales of assets,
net of expenses---------------- 194 12,905 35 2,087
Purchases of short-term
investments-------------------- (26,245) (23,976) -- --
Sales of short-term
investments-------------------- 40,314 3,955 -- --
Other---------------------------- (247) 1,478 1 (2,298)
Net cash used in
investing
activities--------- (23,435) (21,084) (3,822) (24,695)
Cash Flows From (Used In) Financing
Activities:
Repurchase of debentures--------- (9,675) -- -- --
Payments of long-term debt------- (1,643) (6,468) (512) (1,272)
Issuance of long-term debt------- 5,000 2,024 3,000 --
Dividends on preferred stocks---- -- -- -- (8,028)
Other---------------------------- (4) (20) (7) (25)
Net cash from (used
in) financing
activities--------- (6,322) (4,464) 2,481 (9,325)
Decrease in Cash and Cash
Equivalents------------------------ (10,273) (14,160) (1,681) (16,075)
Cash and Cash Equivalents at
Beginning of Period---------------- 46,869 61,029 62,710 78,785
Cash and Cash Equivalents at End of
Period----------------------------- $ 36,596 46,869 61,029 62,710
Supplemental Cash Flow Disclosures:
Interest paid-------------------- $ 19,288 17,805 234 17,839
Income taxes paid---------------- $ 5,125 6,446 3,425 13,694
The accompanying notes are an integral part of these consolidated financial
statements.
38
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.
39
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).
40
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
41
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%
42
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.
43
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
44
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
45
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
46
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
NOTE H -- INCOME TAXES
The income tax provision includes the following (in thousands):
THREE MONTHS
YEARS ENDED ENDED YEAR ENDED
DECEMBER 31, DECEMBER 31, SEPTEMBER 30,
1993 1992 1991 1991
Federal:
Current-------------------------- $ -- 418 -- 455
Deferred------------------------- -- (454) 80 (201)
Foreign------------------------------ 3,419 5,104 2,826 14,661
State-------------------------------- (1,722) 315 52 179
$ 1,697 5,383 2,958 15,094
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)
47
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):
THREE MONTHS
YEARS ENDED ENDED YEAR ENDED
DECEMBER 31, DECEMBER 31, SEPTEMBER 30,
1993 1992 1991 1991
Earnings (Loss) Before Income Taxes
and the Cumulative Effect of
Accounting Changes:
United States-------------------- $ 10,906 (60,117) (4,493) (15,581)
Foreign-------------------------- 7,747 20,255 7,035 34,614
$ 18,653 (39,862) 2,542 19,033
Income Taxes at Statutory U.S.
Corporate Tax Rate----------------- $ 6,529 (13,553) 864 6,471
Effect of:
Foreign income taxes, net of U.S.
tax
benefit------------------------ 3,419 5,104 2,826 14,661
State income taxes (benefit), net
of U.S. tax benefit------------ (1,722) 315 52 179
Accounting limitation
(recognition) of an operating
loss tax benefit--------------- (6,529) 13,553 -- --
Utilization of net operating loss
carry-forwards----------------- -- -- (864) (6,471)
Alternative minimum tax---------- -- -- -- 455
Other---------------------------- -- (36) 80 (201)
Income Tax Provision--------- $ 1,697 5,383 2,958 15,094
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.
48
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):
SINKING
AGGREGATE FUND
MATURITIES REQUIREMENTS TOTAL
1994--------------------------------- $ 4,805 -- 4,805
1995--------------------------------- $ 5,750 -- 5,750
1996--------------------------------- $ 12,279 -- 12,279
1997--------------------------------- $ 7,412 884 8,296
1998--------------------------------- $ 7,395 11,250 18,645
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.
49
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
50
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
51
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.
52
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
53
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):
YEARS ENDED DECEMBER 31,
1993 1992
HEALTH LIFE HEALTH LIFE
CARE INSURANCE CARE INSURANCE
Service Costs------------------------ $ 420 100 400 100
Interest Costs----------------------- 1,396 492 1,332 457
Net Periodic Postretirement
Expense------------------------ $ 1,816 592 1,732 557
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):
DECEMBER 31, DECEMBER 31,
1993 1992
HEALTH LIFE HEALTH LIFE
CARE INSURANCE CARE INSURANCE
Accumulated Postretirement Benefit
Obligation:
Retirees------------------------- $ 19,079 4,915 12,183 4,038
Active participants eligible to
retire------------------------- 1,566 571 625 615
Other active participants-------- 5,824 1,658 4,144 1,154
26,469 7,144 16,952 5,807
Unrecognized Net Loss---------------- (8,685) (1,044) (820) --
Accrued Postretirement Benefit
Liability---------------------- $ 17,784 6,100 16,132 5,807
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%.
54
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
55
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.
56
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
57
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.
58
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:
TOTAL STOCK OPTIONS STOCK APPRECIATION RIGHTS
RESERVED OUTSTANDING EXERCISABLE OUTSTANDING EXERCISABLE
Balances at September 30, 1990------- 1,355,257 226,296 124,430 275,863 173,449
Becoming exercisable------------- -- -- 39,684 -- 40,230
Cancelled or expired------------- (25,207) (4,491) (4,491) (31,999) (31,999)
Stock awards--------------------- (12,000) -- -- -- --
Balances at September 30, 1991------- 1,318,050 221,805 159,623 243,864 181,680
Granted at $4.837 to $4.840------ -- 600,000 -- -- --
Becoming exercisable------------- -- -- 34,243 -- 34,248
Cancelled or expired------------- -- (109,171) (90,786) (119,414) (101,030)
Stock awards--------------------- (8,400) -- -- -- --
Balances at December 31, 1992-------- 1,309,650 712,634 103,080 124,450 114,898
Granted at $2.925 to $5.250------ -- 349,680 -- -- --
Becoming exercisable------------- -- -- 127,044 -- 7,042
Cancelled or expired------------- -- (45,444) (44,278) (54,687) (53,521)
Stock awards--------------------- (20,000) -- -- -- --
Balances at December 31, 1993-------- 1,289,650 1,016,870 185,846 69,763 68,419
Price per share or right------------- $2.925 to $12.625 $8.375 to $14.000
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.
59
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.
THREE MONTHS
YEARS ENDED ENDED YEAR ENDED
DECEMBER 31, DECEMBER 31, SEPTEMBER 30,
1993 1992 1991 1991
(IN MILLIONS)
Gross Operating Revenues:
Refining and Marketing(1)-------- $ 687.2 810.7 196.8 898.6
Exploration and Production:
United States(2)------------- 50.5 18.8 2.4 5.2
Bolivia---------------------- 12.6 17.9 4.6 24.5
Indonesia-------------------- -- 6.0 5.5 29.5
Oil Field Supply and
Distribution------------------- 80.7 93.5 36.5 134.3
Intersegment Eliminations(3)----- -- (.4) (5.2) (7.1)
Total------------------------ $ 831.0 946.5 240.6 1,085.0
Operating Profit (Loss), Including
Gain on Sales of Assets(4):
Refining and Marketing----------- $ 15.2 (14.9) 1.7 19.3
Exploration and Production:
United States(2)------------- 32.3 8.9 .3 .6
Bolivia---------------------- 8.4 12.6 5.3 21.2
Indonesia-------------------- -- 7.6 1.8 13.8
Oil Field Supply and
Distribution------------------- (3.6) (4.7) (1.2) (.5)
Total Operating Profit------- 52.3 9.5 7.9 54.4
Corporate and Unallocated Costs------ (33.6) (49.4) (5.4) (35.4)
Earnings (Loss) Before Income Taxes
and the
Cumulative Effect of Accounting
Changes---------------------------- $ 18.7 (39.9) 2.5 19.0
Total Assets:
Refining and Marketing----------- $ 281.5 308.0 328.5 322.7
Exploration and Production:
United States---------------- 67.2 34.1 33.0 32.3
Bolivia---------------------- 6.5 2.9 6.8 15.6
Indonesia-------------------- -- .3 10.7 11.8
Oil Field Supply and
Distribution------------------- 21.3 23.2 27.6 32.2
Corporate------------------------ 58.0 78.2 88.1 82.2
Total Assets----------------- $ 434.5 446.7 494.7 496.8
60
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
THREE MONTHS
YEARS ENDED ENDED YEAR ENDED
DECEMBER 31, DECEMBER 31, SEPTEMBER 30,
1993 1992 1991 1991
(IN MILLIONS)
Depreciation, Depletion and
Amortization:
Refining and Marketing----------- $ 10.3 10.2 2.4 9.0
Exploration and Production:
United States---------------- 11.1 4.9 .9 2.9
Indonesia-------------------- -- .3 .6 1.7
Oil Field Supply and
Distribution------------------- .4 .5 .1 .5
Corporate------------------------ .8 .7 .2 .9
Total------------------------ $ 22.6 16.6 4.2 15.0
Capital Expenditures:
Refining and Marketing----------- $ 7.1 3.7 .8 4.4
Exploration and Production:
United States---------------- 29.3 8.9 2.9 17.8
Indonesia-------------------- -- .4 .1 1.5
Oil Field Supply and
Distribution------------------- .3 1.1 -- .4
Corporate------------------------ .8 1.3 .1 .4
Total------------------------ $ 37.5 15.4 3.9 24.5
(1) INCLUDES REVENUES OF $20.5 MILLION, $101.0 MILLION AND $165.9 MILLION IN
1993, 1992 AND 1991, RESPECTIVELY, DERIVED FROM EXPORT SALES TO CUSTOMERS
IN FAR EASTERN MARKETS.
(2) INCLUDES REVENUES AND OPERATING PROFIT OF $5.4 MILLION IN 1992 RESULTING
FROM A CHANGE IN ESTIMATE OF THE COMPANY'S REVENUES FROM NATURAL GAS
PRODUCTION IN SOUTH TEXAS (SEE NOTE K).
(3) REPRESENTS INTERSEGMENT ELIMINATIONS, PRIMARILY SALES FROM REFINING AND
MARKETING TO OIL FIELD SUPPLY AND DISTRIBUTION, AT PRICES WHICH
APPROXIMATE MARKET.
(4) OPERATING PROFIT REPRESENTS PRETAX EARNINGS (LOSS) BEFORE CERTAIN
CORPORATE EXPENSES, INTEREST INCOME AND INTEREST EXPENSE. TOTAL OPERATING
PROFIT HAS BEEN RECONCILED TO EARNINGS (LOSS) BEFORE INCOME TAXES AND THE
CUMULATIVE EFFECT OF ACCOUNTING CHANGES. AS DISCUSSED IN NOTE E, OPERATING
PROFIT FROM THE EXPLORATION AND PRODUCTION SEGMENT IN 1992 INCLUDES A $5.8
MILLION GAIN FROM THE SALES OF THE COMPANY'S INDONESIAN OPERATIONS.
61
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
NOTE O -- QUARTERLY FINANCIAL DATA (UNAUDITED)
QUARTERS
FIRST SECOND THIRD FOURTH
(IN MILLIONS EXCEPT PER SHARE AMOUNTS)
1993
Total Revenues------------------- $ 226.5 186.2 215.2 207.0
Operating Profit----------------- $ 6.0 8.9 13.1 24.3
Net Earnings (Loss)-------------- $ (2.9) 1.5 1.7 16.7
Earnings (Loss) Per Share:
Primary---------------------- $ (.37) (.06) (.04) 1.00
Fully Diluted---------------- $ (.37) (.06) (.04) .87
Market Price Per Common Share:
High------------------------- $ 5 5/8 6 5/8 7 3/4 7 1/2
Low-------------------------- $ 3 5 5 1/8 5 1/8
1992
Total Revenues------------------- $ 223.2 251.2 244.5 235.5
Operating Profit----------------- $ 2.7 5.6 7.6 (6.4)
Net Loss------------------------- $ (32.0) (5.5) (3.5) (24.9)
Loss Per Primary and Fully
Diluted Share------------------ $ (2.44) (.56) (.41) (1.93)
Market Price Per Common Share:
High------------------------- $ 6 5/8 5 3/8 5 1/2 3 5/8
Low-------------------------- $ 4 5/8 4 1/4 3 2 1/2
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.
62
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
UNITED
STATES BOLIVIA INDONESIA TOTAL
(IN THOUSANDS)
Year Ended December 31, 1993:
Property acquisition,
unproved----------------------- $ 887 -- -- 887
Exploration---------------------- 2,257 -- -- 2,257
Development---------------------- 25,496 -- -- 25,496
$ 28,640 -- -- 28,640
Year Ended December 31, 1992:
Property acquisition,
unproved----------------------- $ 9 -- -- 9
Exploration---------------------- 977 6 333 1,316
Development---------------------- 7,922 -- 109 8,031
$ 8,908 6 442 9,356
Three Months Ended December 31, 1991:
Property acquisition,
unproved----------------------- $ (7) -- -- (7)
Exploration---------------------- 1,037 15 24 1,076
Development---------------------- 1,881 -- 60 1,941
$ 2,911 15 84 3,010
Year Ended September 30, 1991:
Property acquisition,
unproved----------------------- $ 582 -- 3 585
Exploration---------------------- 9,975 45 9 10,029
Development---------------------- 7,226 -- 1,476 8,702
$ 17,783 45 1,488 19,316
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
63
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.
UNITED
STATES(1) BOLIVIA INDONESIA TOTAL
(IN THOUSANDS EXCEPT AS INDICATED)
Year Ended December 31, 1993:
Gross revenues -- sales to
nonaffiliates------------------ $ 50,228 12,594 -- 62,822
Production costs----------------- 6,763 1,152 -- 7,915
Administrative support and
other-------------------------- 939 3,046 -- 3,985
Depreciation, depletion and
amortization------------------- 11,111 -- -- 11,111
Pretax results of operations----- 31,415 8,396 -- 39,811
Income tax expense--------------- 6,647 5,160 -- 11,807
Results of operations from
producing activities(2)-------- $ 24,768 3,236 -- 28,004
Depletion rates per net
equivalent mcf----------------- $ .78 -- --
Year Ended December 31, 1992:
Gross revenues -- sales to
nonaffiliates------------------ $ 18,850 17,898 5,975 42,723
Production costs----------------- 3,796 688 3,698 8,182
Administrative support and
other-------------------------- 1,216 4,635 107 5,958
Gain (loss) on sales of
assets------------------------- (3) -- 5,750(3) 5,747
Depreciation, depletion and
amortization------------------- 4,862 -- 336 5,198
Pretax results of operations----- 8,973 12,575 7,584 29,132
Income tax expense--------------- 305 7,108 3,066 10,479
Results of operations from
producing activities(2)-------- $ 8,668 5,467 4,518 18,653
Depletion rates per net
equivalent mcf----------------- $ .95 -- .15
Three Months Ended December 31, 1991:
Gross revenues -- sales to
nonaffiliates------------------ $ 2,426 4,634 5,474 12,534
Production costs----------------- 1,071 122 2,915 4,108
Administrative support and
other-------------------------- 242 (765)(5) 107 (416)
Depreciation, depletion and
amortization------------------- 848 -- 606 1,454
Pretax results of operations----- 265 5,277 1,846 7,388
Income tax expense--------------- 9 2,744 1,413 4,166
Results of operations from
producing activities(2)-------- $ 256 2,533 433 3,222
Depletion rates per net
equivalent mcf----------------- $ .94 -- .31
Year Ended September 30, 1991:
Gross revenues -- sales to
nonaffiliates------------------ $ 5,179 24,557 29,507 59,243
Production costs----------------- 1,218 650 9,467 11,335
Administrative support and
other-------------------------- 424 2,710 4,497(4) 7,631
Depreciation, depletion and
amortization------------------- 2,920 -- 1,712 4,632
Pretax results of operations----- 617 21,197 13,831 35,645
Income tax expense--------------- 12 12,015 8,766 20,793
Results of operations from
producing activities(2)-------- $ 605 9,182 5,065 14,852
Depletion rates per net
equivalent mcf----------------- $ 1.06 -- .22
(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.
64
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.
UNITED
STATES(1) BOLIVIA INDONESIA TOTAL
(IN THOUSANDS)
As of December 31, 1993:
Future cash inflows-------------- $ 315,788 133,363 -- 449,151
Future production costs---------- (59,398) (31,092) -- (90,490)
Future development costs--------- (48,020) (2,981) -- (51,001)
Future net cash flows before
income tax expense------------- 208,370 99,290 -- 307,660
Future income tax expense-------- (76,500) (52,334) -- (128,834)
Future net cash flows------------ 131,870 46,956 -- 178,826
10% annual discount factor------- (29,118) (20,516) -- (49,634)
Standardized measure of
discounted future net cash
flows-------------------------- $ 102,752 26,440 -- 129,192
65
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
UNITED
STATES(1) BOLIVIA INDONESIA TOTAL
(IN THOUSANDS)
As of December 31, 1992:
Future cash inflows-------------- $ 215,172 146,555 -- 361,727
Future production costs---------- (33,162) (40,374) -- (73,536)
Future development costs--------- (30,294) (9,248) -- (39,542)
Future net cash flows before
income tax expense------------- 151,716 96,933 -- 248,649
Future income tax expense-------- (42,884) (56,682) -- (99,566)
Future net cash flows------------ 108,832 40,251 -- 149,083
10% annual discount factor------- (21,744) (16,628) -- (38,372)
Standardized measure of
discounted future net cash
flows-------------------------- $ 87,088 23,623 -- 110,711
As of December 31, 1991:
Future cash inflows-------------- $ 69,405 289,143 113,877 472,425
Future production costs---------- (10,167) (52,667) (87,913) (150,747)
Future development costs--------- (13,334) (11,760) (8,545) (33,639)
Future net cash flows before
income tax expense------------- 45,904 224,716 17,419 288,039
Future income tax expense-------- (4,179) (127,824) (12,178) (144,181)
Future net cash flows------------ 41,725 96,892 5,241 143,858
10% annual discount factor------- (10,853) (46,023) -- (56,876)
Standardized measure of
discounted future net cash
flows-------------------------- $ 30,872 50,869 5,241 86,982
As of September 30, 1991:
Future cash inflows-------------- $ 67,514 302,022 88,234 457,770
Future production costs---------- (11,184) (53,482) (68,400) (133,066)
Future development costs--------- (13,370) (11,760) (8,260) (33,390)
Future net cash flows before
income tax expense------------- 42,960 236,780 11,574 291,314
Future income tax expense-------- (5,457) (136,543) (6,352) (148,352)
Future net cash flows------------ 37,503 100,237 5,222 142,962
10% annual discount factor------- (7,147) (45,955) (814) (53,916)
Standardized measure of
discounted future net cash
flows-------------------------- $ 30,356 54,282 4,408 89,046
(1) SEE NOTE K REGARDING LITIGATION INVOLVING A NATURAL GAS SALES CONTRACT.
66
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)
THREE MONTHS
YEARS ENDED ENDED YEAR ENDED
DECEMBER 31, DECEMBER 31, SEPTEMBER 30,
1993 1992 1991 1991
(IN THOUSANDS)
Sales and transfers of oil and gas
produced, net of production
costs------------------------------ $ (52,766) (31,208) (8,713) (45,005)
Net changes in prices and production
costs------------------------------ (21,160) (32,397) 222 (29,828)
Extensions, discoveries and
improved recovery------------------ 73,792 104,219 1,802 19,998
Development costs incurred----------- 25,510 10,012 2,289 9,544
Revisions of estimated future
development costs------------------ (24,052) (18,666) (2,316) (12,633)
Revisions of previous quantity
estimates-------------------------- 31,031 (15,384) 4,565 (37,392)
Purchases and sales of minerals
in-place--------------------------- -- (5,884) -- 47,418
Accretion of discount---------------- 11,071 8,174 2,226 10,251
Net changes in income taxes---------- (24,945) 4,863 (2,139) 24,197
Net increase (decrease)-------------- 18,481 23,729 (2,064) (13,450)
Beginning of period------------------ 110,711 86,982 89,046 102,496
End of period------------------------ $ 129,192 110,711 86,982 89,046
67
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
68
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
UNITED
STATES BOLIVIA INDONESIA TOTAL
Proved Oil Reserves (thousands of
barrels)(1):
At September 30, 1990------------ 4 2,058 11,226 13,288
Revisions of previous
estimates---------------------- 2 59 (5,513) (5,452)
Purchase of minerals in-place---- -- 953 -- 953
Extensions, discoveries and other
additions---------------------- 3 -- -- 3
Production----------------------- (4) (242) (1,209) (1,455)
At September 30, 1991------------ 5 2,828 4,504 7,337
Revisions of previous
estimates---------------------- -- 1 1,333 1,334
Production----------------------- (1) (58) (266) (325)
At December 31, 1991------------- 4 2,771 5,571 8,346
Revisions of previous
estimates---------------------- 1 (266) -- (265)
Production----------------------- (1) (242) (328) (571)
Sales of minerals in-place------- (4) -- (5,243) (5,247)
At December 31, 1992------------- -- 2,263 -- 2,263
Revisions of previous
estimates---------------------- -- 152 -- 152
Production----------------------- -- (242) -- (242)
At December 31, 1993(3)---------- -- 2,173 -- 2,173
Proved Developed Oil Reserves
included above (thousands of
barrels):
At September 30, 1990------------ 4 1,987 11,226 13,217
At September 30, 1991------------ 5 2,738 4,504 7,247
At December 31, 1991------------- 4 2,680 5,571 8,255
At December 31, 1992------------- -- 2,098 -- 2,098
At December 31, 1993(3)---------- -- 2,173 -- 2,173
(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.
69
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
NONE.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information required under this Item will be contained in the Company's 1994
Proxy Statement which is incorporated herein by reference.
See also Executive Officers of the Registrant under Business in Item 1.
ITEM 11. EXECUTIVE COMPENSATION
Information required under this Item will be contained in the Company's 1994
Proxy Statement which is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT
Information required under this Item will be contained in the Company's 1994
Proxy Statement which is incorporated herein by reference.
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. 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
70
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
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
3 Restated Certificate of Incorporation of the Company.
3(a) By-Laws of the Company, as amended through February 9, 1994.
3(b) Amendment to Restated Certificate of Incorporation of the Company adding a new
Article IX limiting Directors' Liability.
3(c) Certificate of Designation Establishing a Series of $2.20 Cumulative Convertible
Preferred Stock, dated as of January 26, 1983.
3(d) Certificate of Designation Establishing a Series A Participating Preferred Stock,
dated as of December 16, 1985.
3(e) Certificate of Amendment, dated as of February 9, 1994, to Restated Certificate of
Incorporation of the Company amending Article IV, Article V, Article VII and
Article VIII.
4(a) 12 3/4% Subordinated Debentures due March 15, 2001, Form of Indenture, dated March
15, 1983 (incorporated by reference herein to Exhibit 4(b) to Registration
Statement No. 2-81960).
4(b) 13% Exchange Notes due December 1, 2000, Indenture dated February 8, 1994
(incorporated by reference herein to Exhibit 2 to the Company's Registration
Statement on Form 8-A filed March 2, 1994).
4(c) Rights Agreement dated December 16, 1985 between the Company and Chemical Bank,
N.A., successor to Interfirst Bank Fort Worth, N.A. (incorporated by reference
herein to Exhibit 4(i) to the Company's Annual Report on Form 10-K for the fiscal
year ended September 30, 1985, File No. 1-3473).
4(d) Amendment to Rights Agreement dated December 16, 1985 between the Company and
Chemical Bank, N.A. (incorporated by reference herein to Exhibit 4(c) to the
Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1992,
File No. 1-3473).
71
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
4(e) Copy of Forbearance Agreement dated as of March 24, 1993 between the Company and
MetLife Security Insurance Company of Louisiana (incorporated by reference herein
to Exhibit 4(n) to the Company's Annual Report on Form 10-K for the fiscal year
ended December 31, 1992, File No. 1-3473).
4(f) Copy of Amendment to the Forbearance Agreement dated as of November 12, 1993
between the Company and MetLife Security Insurance Company of Louisiana
(incorporated by reference herein to Exhibit 4(o) of the Company's Registration
Statement No. 33-68282 on Form
S-4).
4(g) Copy of Memorandum of Understanding dated as of August 31, 1993 between the Company
and MetLife Security Insurance Company of Louisiana (incorporated by reference
herein to Exhibit 10(q) of the Company's Registration Statement No. 33-68282 on
Form S-4).
4(h) Copy of Amended Memorandum of Understanding dated as of December 14, 1993 between
the Company and MetLife Security Insurance Company of Louisiana. (incorporated by
reference herein to Exhibit 4(p) of the Company's Registration Statement No.
33-68282 on Form
S-4).
4(i) Stock Purchase Agreement dated as of February 9, 1994 between the Company and
MetLife Security Insurance Company of Louisiana.
4(j) Registration Rights Agreement dated February 9, 1994 between the Company and
MetLife Security Insurance Company of Louisiana.
4(k) Call Option Agreement dated February 9, 1994 between the Company and MetLife
Security Insurance Company of Louisiana.
4(l) Copy of Tesoro Exploration and Production Company's Loan Agreement dated as of
October 29, 1993 (incorporated by reference herein to Exhibit 4(b) to the Company's
report on Form 10-Q for the quarter ended September 30, 1993, File No. 1-3473).
4(m) Copy of Agreement for Waiver and Substitution of Collateral dated as of September
30, 1993 by and between Tesoro Alaska Petroleum Company and the State of Alaska
(incorporated by reference herein to Exhibit 4(c) to the Company's report on Form
10-Q for the quarter ended September 30, 1993, File No. 1-3473).
10(a) Form of Executive Agreement providing for continuity of management between the
Company and its senior officers dated June 28, 1984 (incorporated by reference
herein to Exhibit 10(b) to the Company's Annual Report on Form 10-K for the fiscal
year ended September 30, 1984, File No. 1-3473).
10(b) Form of Amendment to Executive Agreements between the Company and its senior
officers dated September 30, 1987 (incorporated by reference herein to Exhibit
10(c) to the Company's Annual Report on Form 10-K for the fiscal year ended
September 30, 1987, File No. 1-3473).
10(c) Form of Second Amendment to Executive Agreements between the Company and its senior
officers dated February 28, 1990 (incorporated by reference herein to Exhibit 10(e)
to the Company's Annual Report on Form 10-K for the fiscal year ended September 30,
1990, File No.
1-3473).
72
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
10(d) The Company's Amended Executive Security Plan, as amended through November 13,
1989, and Funded Executive Security Plan, as amended through February 28, 1990, for
executive officers and key personnel (incorporated by reference herein to Exhibit
10(f) to the Company's Annual Report on Form 10-K for the fiscal year ended
September 30, 1990, File No. 1-3473).
10(e) Sixth Amendment to the Company's Amended Executive Security Plan and Seventh
Amendment to the Company's Funded Executive Security Plan, both dated effective
March 6, 1991 (incorporated by reference herein to Exhibit 10(g) to the Company's
Annual Report on Form 10-K for the fiscal year ended September 30, 1991, File No.
1-3473).
10(f) Employment Agreement between the Company and Michael D. Burke dated July 27, 1992
(incorporated by reference herein to Exhibit 10(j) to the Company's Annual Report
on Form 10-K for the fiscal year ended December 31, 1992, File No. 1-3473).
10(g) Employment Agreement between the Company and Bruce A. Smith dated September 14,
1992 (incorporated by reference herein to Exhibit 10(k) to the Company's Annual
Report on Form 10-K for the fiscal year ended December 31, 1992, File No. 1-3473).
10(h) Employment Agreement between the Company and Gaylon H. Simmons dated January 4,
1993 (incorporated by reference herein to Exhibit 10(l) to the Company's Annual
Report on Form 10-K for the fiscal year ended December 31, 1992, File No. 1-3473).
10(i) The Company's Amended Incentive Stock Plan of 1982, as amended through February 24,
1988 (incorporated by reference herein to Exhibit 10(t) to the Company's Annual
Report on Form 10-K for the fiscal year ended September 30, 1988, File No. 1-3473).
10(j) Resolution approved by the Company's stockholders on April 30, 1992 extending the
term of the Company's Amended Incentive Stock Plan of 1982 to February 24, 1994
(incorporated by reference herein to Exhibit 10(o) to the Company's Annual Report
on Form 10-K for the fiscal year ended December 31, 1992, File No. 1-3473).
10(k) Copy of the Company's Executive Long-Term Incentive Plan.
10(l) Agreement for the Sale and Purchase of Royalty Oil between Tesoro Alaska Petroleum
Company and the State of Alaska (for the sale of Prudhoe Bay Royalty Oil), dated
February 26, 1982 (incorporated by reference herein to Exhibit 10(p) to the
Company's Annual Report on Form 10-K for the fiscal year ended September 30, 1984,
File No.
1-3473).
10(m) Copy of Settlement Agreement dated effective January 19, 1993, between Tesoro
Petroleum Corporation, Tesoro Alaska Petroleum Company and the State of Alaska
(incorporated by reference herein to Exhibit 10(q) to the Company's Annual Report
on Form 10-K for the fiscal year ended December 31, 1992, File No. 1-3473).
10(n) Form of Indemnification Agreement between the Company and its officers and
directors (incorporated by reference herein to Exhibit B to the Company's Proxy
Statement for the Annual Meeting of Stockholders held on February 25, 1987, File
No. 1-3473).
10(o) Gas Purchase and Sales Agreement dated January 16, 1979 (incorporated by reference
herein to Exhibit 10(p) of the Company's Registration Statement No. 33-68282 on
Form S-4).
11 Statement of computation of earnings (loss) per share.
73
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
22 Subsidiaries of the Company.
24(a) Consent of Deloitte & Touche.
24(b) Consent of Netherland, Sewell & Associates, Inc.
(b) REPORTS ON FORM 8-K
No reports on Form 8-K were filed by the Company during the quarter ended
December 31, 1993.
74
SCHEDULE II
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
SCHEDULE II -- AMOUNTS RECEIVABLE FROM
RELATED PARTIES AND UNDERWRITERS, PROMOTERS
AND EMPLOYEES OTHER THAN RELATED PARTIES
(DOLLARS IN THOUSANDS)
BALANCE AT BALANCE AT
BEGINNING CLOSE
NAME OF DEBTOR OF PERIOD ADDITIONS DEDUCTIONS OF PERIOD
Tesoro-Leevac Petroleum Company(1):
Year Ended September 30, 1991-------- $ -- 5,134 -- 5,134
Three Months Ended December 31,
1991------------------------------- $ 5,134 -- 335 4,799
Year Ended December 31, 1992--------- $ 4,799 -- 4,799 --
Year Ended December 31, 1993--------- $ -- -- -- --
(1) RECEIVABLE REPRESENTED WORKING CAPITAL FINANCING PROVIDED TO TESORO-LEEVAC
PETROLEUM COMPANY, A JOINT VENTURE FORMERLY 50%-OWNED BY THE COMPANY. A
PORTION OF THIS RECEIVABLE WAS REPRESENTED BY A NOTE RECEIVABLE WITH
INTEREST PAID MONTHLY AT THE PRIME RATE. THE BALANCE REPRESENTED
SHORT-TERM FINANCING FOR PRODUCT PURCHASES PAYABLE UNDER NORMAL SALES
TERMS. EFFECTIVE DECEMBER 31, 1992, THE COMPANY ACQUIRED THE REMAINING 50%
INTEREST IN THIS JOINT VENTURE AND TRANSFERRED THESE OPERATIONS TO ITS
SUBSIDIARY, TESORO PETROLEUM DISTRIBUTING COMPANY.
75
SCHEDULE V
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
SCHEDULE V -- CONSOLIDATED PROPERTY, PLANT AND EQUIPMENT
(DOLLARS IN THOUSANDS)
BALANCE
AT BALANCE AT
BEGINNING ADDITIONS SALES OR OTHER CHANGES(2) CLOSE
OF PERIOD AT COST RETIREMENTS(1) DEBITS CREDITS OF PERIOD
Year Ended September 30, 1991:
Refining and Marketing------------- $ 257,855 4,418 536 9,626(3) -- 271,363
Exploration and Production--------- 26,573 19,316 -- -- 36 45,853
Oil Field Supply and
Distribution---------------------- 15,933 422 480 240 -- 16,115
Corporate-------------------------- 15,737 328 82 44 -- 16,027
$ 316,098 24,484 1,098 9,910 36 349,358
Three Months Ended December 31, 1991:
Refining and Marketing------------- $ 271,363 745 3 9 -- 272,114
Exploration and Production--------- 45,853 3,010 -- 1 -- 48,864
Oil Field Supply and
Distribution---------------------- 16,115 13 25 -- -- 16,103
Corporate-------------------------- 16,027 90 -- 1 -- 16,118
$ 349,358 3,858 28 11 -- 353,199
Year Ended December 31, 1992:
Refining and Marketing------------- $ 272,114 3,678 767 188 -- 275,213
Exploration and Production--------- 48,864 9,356 11,512 -- 44 46,664
Oil Field Supply and
Distribution---------------------- 16,103 1,129 370 -- 497 16,365
Corporate-------------------------- 16,118 1,283 7,199 229 -- 10,431
$ 353,199 15,446 19,848 417 541 348,673
Year Ended December 31, 1993:
Refining and Marketing------------- $ 275,213 7,103 420 390 -- 282,286
Exploration and Production--------- 46,664 29,306 -- 673 -- 76,643
Oil Field Supply and
Distribution---------------------- 16,365 250 179 -- 1,023 15,413
Corporate-------------------------- 10,431 792 102 -- -- 11,121
$ 348,673 37,451 701 1,063 1,023 385,463
(1) FOR FURTHER INFORMATION REGARDING DISPOSITION OF ASSETS, SEE NOTE E OF
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS IN
ITEM 8.
(2) RECLASSIFICATIONS AND TRANSFERS TO OR FROM OTHER BALANCE SHEET ACCOUNTS.
(3) INCLUDES THE ACQUISITION OF THE REMAINING INTEREST IN A CONVENIENCE STORE
OPERATION.
76
SCHEDULE VI
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
SCHEDULE VI -- CONSOLIDATED ACCUMULATED DEPRECIATION, DEPLETION AND
AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT
(DOLLARS IN THOUSANDS)
ADDITIONS
BALANCE AT CHARGED TO OTHER CHANGES(3) BALANCE AT
BEGINNING COSTS AND SALES OR CLOSE
OF PERIOD EXPENSES(1) RETIREMENTS(2) DEBITS CREDITS OF PERIOD
Year Ended September 30, 1991:
Refining and Marketing------------- $ 92,805 9,019 41 -- 3,192 (4) 104,975
Exploration and Production--------- 11,081 4,632 -- -- -- 15,713
Oil Field Supply and
Distribution---------------------- 10,070 507 430 2 -- 10,145
Corporate-------------------------- 10,095 847 73 -- 155 11,024
$ 124,051 15,005 544 2 3,347 141,857
Three Months Ended
December 31, 1991:
Refining and Marketing------------- $ 104,975 2,441 3 14 -- 107,399
Exploration and Production--------- 15,713 1,454 -- -- -- 17,167
Oil Field Supply and
Distribution---------------------- 10,145 120 22 -- 1 10,244
Corporate-------------------------- 11,024 210 -- -- 1 11,235
$ 141,857 4,225 25 14 2 146,045
Year Ended December 31, 1992:
Refining and Marketing------------- $ 107,399 10,191 212 94 -- 117,284
Exploration and Production--------- 17,167 5,198 7,359 -- -- 15,006
Oil Field Supply and
Distribution---------------------- 10,244 464 324 -- 8 10,392
Corporate-------------------------- 11,235 699 4,425 -- -- 7,509
$ 146,045 16,552 12,320 94 8 150,191
Year Ended December 31, 1993:
Refining and Marketing------------- $ 117,284 10,263 227 -- 494 127,814
Exploration and Production--------- 15,006 11,143 -- -- 49 26,198
Oil Field Supply and
Distribution---------------------- 10,392 392 149 579 -- 10,056
Corporate-------------------------- 7,509 793 87 -- 29 8,244
$ 150,191 22,591 463 579 572 172,312
(1) THE ANNUAL PROVISIONS FOR DEPRECIATION (GENERALLY STRAIGHT-LINE METHOD)
HAVE BEEN COMPUTED PRINCIPALLY IN ACCORDANCE WITH THE FOLLOWING RANGES OF
RATES:
REFINING AND MARKETING--------------- 3 YEARS TO 34 YEARS
EXPLORATION AND PRODUCTION----------- 3 YEARS TO 20 YEARS
OIL FIELD SUPPLY AND DISTRIBUTION---- 3 YEARS TO 45 YEARS
CORPORATE---------------------------- 3 YEARS TO 20 YEARS
THE ANNUAL PROVISION FOR DEPLETION FOR EXPLORATION AND PRODUCTION ASSETS
HAS BEEN COMPUTED ON A UNIT-OF-PRODUCTION METHOD BASED UPON PRODUCTION OF
OIL AND GAS RESERVES. LEASEHOLD IMPROVEMENTS ARE BEING AMORTIZED OVER THE
TERM OF THE LEASE OR ESTIMATED USEFUL LIFE OF THE IMPROVEMENT, WHICHEVER
PERIOD IS LESS. DEPRECIATION AND AMORTIZATION ARE PROVIDED NET OF SALVAGE
VALUE (GENERALLY 10% EXCEPT FOR THE ALASKA REFINERY WHICH IS 20%) OF THE
ASSETS.
(2) FOR FURTHER INFORMATION REGARDING THE DISPOSITION OF ASSETS, SEE NOTE E OF
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS IN ITEM 8.
(3) RECLASSIFICATIONS AND TRANSFERS TO OR FROM OTHER BALANCE SHEET ACCOUNTS.
(4) INCLUDES THE ACQUISITION OF THE REMAINING INTEREST IN A CONVENIENCE STORE
OPERATION.
77
SCHEDULE VIII
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
SCHEDULE VIII -- CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
(DOLLARS IN THOUSANDS)
ADDITIONS
BALANCE AT CHARGED TO CHARGED TO DEDUCTIONS BALANCE AT
BEGINNING COSTS AND OTHER FROM CLOSE
OF PERIOD EXPENSES ACCOUNTS(1) RESERVE(2) OF PERIOD
Allowance for Doubtful Accounts
(deducted from current receivables
in the balance sheet):
Year Ended September 30, 1991---- $ 5,957 3,508 538 3,934 6,069
Three Months Ended December 31,
1991--------------------------- $ 6,069 305 -- 2,306 4,068
Year Ended December 31, 1992----- $ 4,068 937 396 2,814 2,587
Year Ended December 31, 1993----- $ 2,587 667 71 838 2,487
(1) RECOVERIES OF ACCOUNTS RECEIVABLE PREVIOUSLY WRITTEN OFF.
(2) WRITE-OFF OF DOUBTFUL ACCOUNTS.
78
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
TESORO PETROLEUM CORPORATION
March 30, 1994 By: /s/ MICHAEL D. BURKE
Michael D. Burke
President and Chief Executive Officer
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.
Signature Title Date
/s/ CHARLES WOHLSTETTER Chairman of the Board of Directors March 30, 1994
(Charles Wohlstetter) and Director
/s/ MICHAEL D. BURKE Director, President and Chief March 30, 1994
(Michael D. Burke) Executive Officer (Principal
Executive Officer)
/s/ BRUCE A. SMITH Executive Vice President and Chief March 30, 1994
(Bruce A. Smith) Financial Officer (Principal
Financial Officer and Accounting
Officer)
/s/ RAY C. ADAM Director March 30, 1994
(Ray C. Adam)
/s/ ROBERT J. CAVERLY Director March 30, 1994
(Robert J. Caverly
Director March , 1994
(Peter M. Detwiler)
/s/ STEVEN H. GRAPSTEIN Director March 30, 1994
(Steven H. Grapstein)
/s/ CHARLES F. LUCE Director March 30, 1994
(Charles F. Luce)
/s/ RAYMOND K. MASON, SR. Director March 30, 1994
(Raymond K. Mason, Sr.)
/s/ JOHN J. McKETTA, JR. Director March 30, 1994
(John J. McKetta, Jr.)
/s/ STEWART G. NAGLER Director March 30, 1994
(Stewart G. Nagler)
/s/ JAMES Q. RIORDAN Director March 30, 1994
(James Q. Riordan)
/s/ WILLIAM S. SNEATH Director March 30, 1994
(William S. Sneath)
/s/ ARTHUR SPITZER Director March 30, 1994
(Arthur Spitzer)
Director March , 1994
(M. Richard Stewart)
/s/ MURRAY L. WEIDENBAUM Director March 30, 1994
(Murray L. Weidenbaum)
79