TESORO PETROLEUM CORP /NEW/ - 10-K Annual Report

Back to GetFilings.com

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.