TESORO PETROLEUM CORP /NEW/, S-3/A, 1994-05-31

TESORO PETROLEUM CORP /NEW/
S-3/A, 1994-05-31
PETROLEUM REFINING

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<PAGE> 1

AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON MAY 31, 1994

REGISTRATION NO. 33-53587

- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------------

AMENDMENT NO. 1

FORM S-3

REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
---------------------
TESORO PETROLEUM CORPORATION
(Exact name of issuer as specified in its charter)

<TABLE>
<S> <C>
DELAWARE 95-0862768
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
</TABLE>

8700 TESORO DRIVE
SAN ANTONIO, TEXAS 78217
(210) 828-8484
(Address, including zip code, and telephone number, including area code, of
registrant's principal offices)

MICHAEL D. BURKE
PRESIDENT AND CHIEF EXECUTIVE OFFICER
TESORO PETROLEUM CORPORATION
8700 TESORO DRIVE
SAN ANTONIO, TEXAS 78217
(210) 828-8484
(Name, address, including zip code, and telephone number,
including area code, of agent for service)

---------------------
Copies to:

<TABLE>
<S> <C>
PHILLIP M. RENFRO LOUISE A. SHEARER
FULBRIGHT & JAWORSKI L.L.P. BAKER & BOTTS, L.L.P.
SUITE 2200 ONE SHELL PLAZA
300 CONVENT STREET 910 LOUISIANA
SAN ANTONIO, TEXAS 78205 HOUSTON, TEXAS 77002
(210) 224-5575 (713) 229-1234
</TABLE>

---------------------
APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as
practicable after the effective date of this Registration Statement.

If the only securities being registered on this Form are being offered
pursuant to dividend or interest reinvestment plans, please check the following
box. / /

If any of the securities being registered on this Form are to be offered on
a delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933, other than securities offered only in connection with dividend or interest
reinvestment plans, check the following box. / /
---------------------

THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL
FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION
STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(A) OF
THE SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME
EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(A),
MAY DETERMINE.

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- --------------------------------------------------------------------------------
<PAGE> 2

***************************************************************************
* *
* Information contained herein is subject to completion or amendment. A *
* registration statement relating to these securities has been filed *
* with the Securities and Exchange Commission. These securities may not *
* be sold nor may offers to buy be accepted prior to the time the *
* registration statement becomes effective. This prospectus shall not *
* constitute an offer to sell or the solicitation of an offer to buy *
* nor shall there be any sale of these securities in any State in which *
* such offer, solicitation or sale would be unlawful prior to *
* registration or qualification under the securities laws of any such *
* State. *
* *
***************************************************************************

SUBJECT TO COMPLETION, DATED MAY 31, 1994

5,000,000 SHARES

TESORO PETROLEUM CORPORATION
COMMON STOCK
($.16 2/3 PAR VALUE)
------------------

The 5,000,000 shares (the "Shares") of Common Stock, par value $.16 2/3 per
share ("Common Stock"), of Tesoro Petroleum Corporation (the "Company" or
"Tesoro") offered hereby (the "Offering") are being offered by the
Company. The Common Stock is listed on the New York Stock
Exchange and the Pacific Stock Exchange under the symbol
"TSO." On May 26, 1994, the reported closing price of the
Common Stock on the New York Stock Exchange-Composite
Tape was $11 1/2 per share.

------------------
SEE "INVESTMENT CONSIDERATIONS" FOR A DISCUSSION OF CERTAIN FACTORS THAT SHOULD
BE CONSIDERED IN CONNECTION WITH AN INVESTMENT IN THE SHARES.
------------------
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR
HAS THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE
SECURITIES COMMISSION PASSED UPON THE ACCURACY OR AD-
EQUACY OF THIS PROSPECTUS. ANY REPRESENTATION
TO THE CONTRARY IS A CRIMINAL OFFENSE.

<TABLE>
<CAPTION>
Underwriting
Price to Discounts and Proceeds
Public Commissions to Company(1)
--------- ------------- -------------
<S> <C> <C> <C>
Per Share..................................... $ $ $
Total(2)...................................... $ $ $
</TABLE>

(1) Before deduction of expenses payable by the Company estimated at
$ .
(2) The Company has granted the Underwriters an option, exercisable for 30 days
from the date of this Prospectus, to purchase a maximum of 500,000
additional shares of Common Stock in order to cover over-allotments of the
Shares. If the option is exercised in full, the total Price to Public will
be $ , Underwriting Discounts and Commissions will be $
and Proceeds to Company will be $ .
------------------
The Shares are offered by the several Underwriters when, as and if issued
by the Company, delivered to and accepted by the Underwriters and subject to
their right to reject orders in whole or in part. It is expected that the Shares
will be ready for delivery on or about , 1994.

CS FIRST BOSTON
SMITH BARNEY SHEARSON INC.
JEFFERIES & COMPANY, INC.

The date of this Prospectus is , 1994.
<PAGE> 3

(PHOTO OF THE COMPANY'S REFINERY)

Tesoro holds the exclusive license to operate
7-Eleven convenience stores in Alaska. --

(PHOTO OF A 7-ELEVEN
CONVENIENCE STORE)

(MAP OF THE STATE OF ALASKA
INDICATING LOCATION OF THE
REFINERY)

-- The Company's refinery is
located on the Cook Inlet
near Kenai, Alaska,
facilitating shipments
of crude oil supply.

IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT
TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE COMMON STOCK AT
A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN MARKET. SUCH
TRANSACTIONS MAY BE EFFECTED ON THE NEW YORK AND PACIFIC STOCK EXCHANGES. SUCH
STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME.

2
<PAGE> 4

PROSPECTUS SUMMARY

The following summary is qualified in its entirety by, and should be read
in conjunction with, the more detailed information and financial statements
appearing elsewhere in, or incorporated by reference in, this Prospectus. Except
where otherwise indicated, the information in this Prospectus assumes that the
over-allotment option granted to the Underwriters is not exercised. All
references to the "Company" or "Tesoro" shall mean Tesoro Petroleum Corporation
and its consolidated subsidiaries, unless the context otherwise requires. All
references to the "Bob West Field" shall mean the approximately 90% of the
acreage in such field in which the Company participates.

THE COMPANY

Tesoro is an independent energy company engaged in refining and marketing,
primarily in Alaska, and in the exploration for and production of natural gas
and crude oil in South Texas and Bolivia. The Company also markets lubricants,
fuels and specialty petroleum products on a wholesale basis. In 1993, the
Company's new management team initiated a strategic plan focusing on: (i)
enhancing the profitability of the Company's Kenai, Alaska refinery (the
"Refinery") through a market-driven production strategy, (ii) expanding the
Company's exploration and production efforts in South Texas, (iii) resolving a
contractual dispute with the State of Alaska (the "State") and (iv)
strengthening the Company's capitalization to increase its financial and
operating flexibility. The successful implementation of these new strategic
efforts contributed significantly to an increase in segment operating profit
from $9.5 million in 1992 to $52.3 million in 1993 and to a return to overall
profitability with net earnings of $17.0 million in 1993.

Refining and Marketing. The Company conducts its refining operations in
Alaska, where it is one of the two largest producers of refined products.
Strategically located in Kenai, Alaska on the Cook Inlet, with access to
multiple sources of crude oil, the Refinery has a rated throughput capacity of
72,000 barrels per day ("BPD"). In 1993, Refinery production consisted of
approximately 25% jet fuel, 25% gasoline, 14% other distillates, including
diesel fuel, and 36% residual fuel oil. During 1993, all of the jet fuel was
marketed in Alaska to passenger and cargo airlines, and substantially all of the
other distillates, including diesel fuel, was marketed in Alaska for marine and
industrial purposes. During 1993, approximately 89% of the gasoline was marketed
in Alaska, with the remaining 11% being sold into West Coast markets. Tesoro
holds an exclusive license to operate all 7-Eleven convenience stores within
Alaska, and conducts its retail marketing of gasoline through 33 of the
Company's 7-Eleven stores and two other locations in Alaska. In addition, the
Company markets gasoline on a wholesale basis in Alaska through 67 branded and
24 unbranded dealers and jobbers and to two major oil companies. A majority of
the residual fuel oil produced in 1993 was sold as a feedstock to refineries on
the West Coast.

In response to consistently depressed prices in the residual fuel oil
market and Refinery production of gasoline in excess of local demand, the
Company's new management team implemented a strategy in 1993 to align Refinery
product yield more closely to the product demand of the Alaskan marketplace.
This market-driven strategy resulted in significant changes in the operation of
the Refinery, including: (i) a reduction in Refinery throughput from
approximately 61,000 BPD in 1992 to approximately 50,000 BPD in 1993 and (ii) a
reduction in the percentage of Refinery feedstocks represented by heavier
Alaskan North Slope ("ANS") crude oil, which resulted in a reduction in the
percentage of residual fuel oil produced. In addition, beginning in 1993, the
Company focused on the marketing of residual fuel oil primarily as a feedstock
for West Coast refineries. Changes in Tesoro's sales prices to such refineries
can be linked to changes in crude oil prices, unlike the more volatile Far
Eastern bunker fuel markets where the Company had primarily marketed its
residual fuel oil in the past. The implementation of these measures
significantly contributed to an improvement in the Company's refining and
marketing segment operating results from a $14.9 million loss in 1992 to a $15.2
million profit in 1993. The Company is currently installing a vacuum unit at the
Refinery, which is estimated to cost approximately $24 million and is expected
to result in further significant reductions in the production of residual fuel
oil and to improve the Refinery's overall product mix. The vacuum unit is
expected to begin operating in January 1995.

Exploration and Production. The Company explores for and produces natural
gas from two geographic areas: South Texas and Bolivia. The Company's South
Texas activities are primarily concentrated in the Bob

3
<PAGE> 5

West Field in the southern part of the Wilcox Trend in Starr and Zapata
Counties. The Bob West Field, which was discovered by the Company in 1990,
represents a major gas discovery with estimated ultimately recoverable gross
proved reserves to all participants of 334 billion cubic feet ("Bcf") of natural
gas, of which approximately 56 Bcf had been produced through March 31, 1994. The
Bob West Field encompasses approximately 4,000 acres, with 23 known productive
sands, 17 of which are now producing. Wells in the Bob West Field, the majority
of which are deviated, are typically multiple sand completions on a faulted
anticlinal structure with production from depths of 8,000 to 16,000 feet.
Estimated gross proved developed reserves per well at March 31, 1994 averaged
approximately 7.3 Bcf and gross drilling and completion costs per well drilled
in 1993 averaged approximately $2.8 million. The Company owns an average 50%
revenue interest in approximately two-thirds of the Bob West Field and an
average 28% revenue interest in the remaining one-third.

Development of the Bob West Field has been highly successful, and the
Company currently has ownership interests in 31 producing wells in this field,
15 of which were drilled in 1993 at a total cost to the Company of approximately
$21.4 million and six of which were drilled in the first quarter of 1994. An
additional 19 wells are scheduled to be drilled during the remainder of 1994.
During December 1993, the Company's net production from this field averaged 58
million cubic feet ("MMcf") of gas per day, compared to net production of 18
MMcf of gas per day during December 1992. The Company's net proved gas reserves
attributable to this field increased approximately 63% from 74 Bcf at year end
1992 to 120 Bcf at year end 1993. During 1993, approximately 73% of the
Company's production from this field was sold at spot market prices, while the
remainder was sold under a gas purchase contract (the "Tennessee Gas Contract")
to Tennessee Gas Pipeline Company ("Tennessee Gas").

The Company's other exploration and production operations are located in
southern Bolivia near the border of Argentina, where, since 1976, the Company
has discovered four significant natural gas fields. As a result, Tesoro is the
second largest holder of proved natural gas reserves in Bolivia through its
approximately 75% interest in two contract areas, Blocks XVIII and XX. To date,
only Block XVIII has been developed due to current market and transportation
constraints. In Block XVIII, a 93,000-acre area, the Company has drilled five
exploratory wells and 12 development wells within three separate fields. Wells
in this area are multiple sand completions on an anticlinal structure with
production from depths of 6,000 to 12,000 feet. During 1993, the Company's net
production averaged 19 MMcf of gas per day and 660 barrels ("Bbls") of
condensate per day, a production level that has been maintained for more than
three years. Net proved reserves in Bolivia at year end 1993 were approximately
112 billion cubic feet equivalents ("Bcfe"). Production in Bolivia is currently
sold under a contract to the Bolivian state-owned petroleum company, Yacimientos
Petroliferos Fiscales Bolivianos ("YPFB"), which, in turn, resells the gas to
the Republic of Argentina.

In 1993, operating profit of the Company's exploration and production
segment increased 40%, from $29.1 million in 1992 to $40.7 million in 1993. At
year end 1993, the present value of estimated future net revenues from proved
reserves discounted at 10% per annum was $217.8 million on a pre-tax basis. Such
estimate is based in part on the terms of the Tennessee Gas Contract, under
which the Company receives prices greatly in excess of spot market prices. This
contract is currently the subject of litigation. See "Investment Considerations"
and "Legal Proceedings -- Tennessee Gas Contract."

The Recapitalization. In February 1994, the stockholders of the Company
approved a plan of recapitalization (the "Recapitalization") for Tesoro. The
Recapitalization included (i) the reclassification of all of the Company's
outstanding $2.16 Cumulative Convertible Preferred Stock ("$2.16 Preferred
Stock"), including accrued and unpaid dividends thereon of approximately $9.5
million, into Common Stock, (ii) the satisfaction of past accrued and unpaid
dividends of approximately $21.2 million on the Company's $2.20 Cumulative
Convertible Preferred Stock ("$2.20 Preferred Stock"), and (iii) certain other
agreements relating to the terms and conditions of the $2.20 Preferred Stock. In
addition, in February 1994 MetLife Security Insurance Company of Louisiana
("MetLife Louisiana"), a wholly-owned subsidiary of Metropolitan Life Insurance
Company ("MetLife") and the sole holder of the $2.20 Preferred Stock, granted
Tesoro a three-year option (the "MetLife Louisiana Option") to purchase all of
MetLife Louisiana's holdings of $2.20 Preferred Stock and Common Stock. Until
June 30, 1994, the aggregate option price is approximately $53.0 million, after
giving effect to a reduction in the option price for the cash dividend paid on
the $2.20 Preferred Stock in May 1994. The unpaid option price will increase by
3% on the last day of each calendar

4
<PAGE> 6

quarter through December 31, 1995, and by 3.5% of the unpaid option price on the
last day of each quarter thereafter, and will be reduced by cash dividends paid
on the $2.20 Preferred Stock after February 9, 1994. Also, in February 1994,
holders of $44.1 million principal amount of the Company's 12 3/4% Subordinated
Debentures due 2001 ("Subordinated Debentures") tendered their debentures for a
like principal amount of new 13% Exchange Notes due 2000 ("Exchange Notes").
This exchange satisfied all the Company's sinking fund requirements through 1996
and over 90% of such requirements for 1997. As a result of the successful
completion of the Recapitalization, the Company's capital structure has been
significantly improved, with stockholders' equity increasing by approximately
$80 million and annual preferred dividend requirements being reduced by
approximately $2.9 million.

The Offering. The net proceeds from the Offering will be utilized to
exercise the MetLife Louisiana Option and, if such proceeds exceed the amount
required to exercise the MetLife Louisiana Option in full, for general corporate
purposes. See "Use of Proceeds." If the MetLife Louisiana Option is exercised in
full prior to June 30, 1994, the Company will acquire 2,875,000 shares of $2.20
Preferred Stock having a liquidation value of approximately $57.5 million and
4,084,160 shares of Common Stock having an aggregate market value of
approximately $47.0 million (based on a closing price of $11 1/2 per share on
May 26, 1994) in consideration for $53.0 million. The exercise in full of the
MetLife Louisiana Option will further improve the Company's financial
flexibility by eliminating dividend requirements of $6.3 million per year on the
$2.20 Preferred Stock. The Offering and the exercise in full of the MetLife
Louisiana Option will result in a net increase of only 915,840 outstanding
shares of Common Stock.

Business Strategy. The Company's ongoing business strategy is (i) to
continue to enhance its refining and marketing operations in Alaska and (ii) to
expand its exploration and production operations through development drilling in
the Bob West Field. In addition, management of the Company currently intends to
recommend to the Company's Board of Directors that the Company proceed with a
limited exploration program focused primarily on the Wilcox Trend of South Texas
if the Offering is successfully completed and the MetLife Louisiana Option is
exercised in full. In conjunction with its ongoing exploration and production
operations, the Company from time to time reviews possible acquisitions of
producing oil and gas properties. The Company believes that it will in the
future make such acquisitions to enhance its growth; however, the Company does
not currently have any specific acquisition plans.

THE OFFERING

<TABLE>
<S> <C>
Common Stock offered(1)............................... 5,000,000 shares.
Common Stock to be outstanding after the
Offering(2)......................................... 23,446,933 shares.
Use of Proceeds(3).................................... To exercise the MetLife Louisiana
Option. See "Use of Proceeds."
Trading Markets....................................... New York Stock Exchange and Pacific
Stock Exchange.
Trading Price......................................... Closing price of $11 1/2 on the New
York Stock Exchange-Composite Tape on
May 26, 1994.
Symbol................................................ "TSO."
</TABLE>

- ---------------
(1) Does not include 500,000 shares of Common Stock subject to the Underwriters'
over-allotment option.

(2) The shares outstanding after the Offering do not include 341,441 shares
subject to currently exercisable options and stock awards granted under
employee benefit plans and assume the issuance of 5,000,000 shares pursuant
to the Offering and the repurchase and retirement of 4,084,160 shares upon
the exercise in full of the MetLife Louisiana Option.

(3) The net proceeds of the Offering will be used to exercise the MetLife
Louisiana Option in whole or in part depending on the aggregate proceeds to
the Company. Any net proceeds in excess of the amount required to exercise
the MetLife Louisiana Option will be used for general corporate purposes.
See "Use of Proceeds."

INVESTMENT CONSIDERATIONS

Prospective purchasers of Common Stock should consider carefully the
information set forth under "Investment Considerations" as well as the other
information contained in, or incorporated by reference in, this Prospectus.

5
<PAGE> 7

SUMMARY HISTORICAL CONSOLIDATED FINANCIAL AND OPERATING DATA
(DOLLARS IN MILLIONS, EXCEPT PER SHARE AMOUNTS)

The following summary historical consolidated financial and operating data
should be read in conjunction with "Selected Financial Data," "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
the Consolidated Financial Statements, including the notes thereto.

Segment operating profit (loss)(2):
Refining and marketing........................ 19.3 (14.9) 15.2 1.2 6.4
Exploration and production(1)................. 35.6 29.1 40.7 5.6 13.1
Other......................................... (.5) (4.7) (3.6) (.8) (1.2)
--------- ---------- ---------- ---------- ----------
Total segment operating profit........ 54.4 9.5 52.3 6.0 18.3
--------- ---------- ---------- ---------- ----------
--------- ---------- ---------- ---------- ----------
General and administrative expenses............. 17.0 25.9 16.7 3.4 3.6
Interest expense(3)............................. 18.8 21.1 14.5 5.0 4.9
Earnings (loss) before the cumulative effect of
accounting changes and extraordinary loss..... 3.9 (45.3) 17.0 (2.9) 7.2
Net earnings (loss)(4).......................... 3.9 (65.9) 17.0 (2.9) 2.4
Net earnings (loss) applicable to Common
Stock(4)...................................... (5.3) (75.1) 7.7 (5.2) .5
Earnings (loss) per primary and fully
diluted* share(4)............................. (.37) (5.34) .54 (.37) .03
OTHER FINANCIAL DATA:
Depreciation, depletion and amortization........ $ 15.0 $ 16.6 $ 22.6 $ 4.8 $ 6.6
Capital expenditures............................ 24.5 15.4 37.5 5.1 18.5
</TABLE>

<TABLE>
<CAPTION>
AS OF AS OF DECEMBER 31, AS OF MARCH 31,
SEPTEMBER 30, ------------------ ------------------
1991 1992 1993 1993 1994
------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Cash and short-term investments.................. $ 62.7 $ 66.9 $ 42.5 $ 66.2 $ 49.4
Long-term debt and other obligations, including
current portion................................ 184.7 201.7 185.5 180.4 184.9
Redeemable preferred stock....................... 57.4 71.7 78.1 73.3 --
Common Stock and other stockholders' equity...... 137.4 50.7 58.5 45.5 144.1
</TABLE>

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* Anti-dilutive
(Table continued on following page)

6
<PAGE> 8

SUMMARY HISTORICAL CONSOLIDATED FINANCIAL AND OPERATING DATA
(DOLLARS IN MILLIONS, EXCEPT PER UNIT AMOUNTS)

<TABLE>
<CAPTION>
YEAR ENDED THREE MONTHS
YEAR ENDED DECEMBER 31, ENDED MARCH 31,
SEPTEMBER 30, ------------------------------ ------------------------------
1991 1992 1993 1993 1994
------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
REFINING AND MARKETING OPERATIONS:
Refinery throughput (average BPD)(5)... 68,192 61,425 49,753 52,911 45,320
Product sales, excluding residual fuel
oil sales (average BPD)............. 61,426 63,509 51,820 59,109 49,372
Residual fuel oil sales (average
BPD)(6)............................. 28,729 23,931 16,945 20,866 16,446
Margin per Bbl of Refinery
production.......................... $ 2.77 $ 1.18 $ 4.19 $ 2.94 $ 4.24
EXPLORATION AND PRODUCTION OPERATIONS:
NATURAL GAS -- UNITED STATES:
Net production (average daily
Mcf).............................. 7,435 13,960 38,767 27,009 48,998
Average sales prices (per Mcf)(1)... $ 1.88 $ 3.68 $ 3.55 $ 3.07 $ 3.92
Average lifting cost (per Mcf)...... $ .44 $ .74 $ .48 $ .49 $ .53
Average finding cost (per Mcf)(7)... $ .72 $ .20 $ .47 * *
Proved reserves at end of period
(Bcf)............................. 33.1 73.8 120.2 ** 121.5
Present value of estimated future
net
revenues from proved reserves
before deduction of income
taxes(1)(8)....................... $ 32.1 $ 120.2 $ 162.6 ** $ 171.0
NATURAL GAS -- BOLIVIA:
Net production (average daily
Mcf).............................. 19,322 19,421 19,232 17,747 19,137
Average sales prices (per Mcf)...... $ 3.06 $ 1.67 $ 1.22 $ 1.19 $ 1.23
Average lifting cost (per net
equivalent Mcf)................... $ .09 $ .08 $ .14 $ .23 $ .11
Proved reserves at end of period
(Bcfe)............................ 131.6 120.1 111.9 ** **
Present value of estimated future
net revenues from proved reserves
before deduction of income
taxes(8).......................... $ 123.5 $ 54.1 $ 55.2 ** **
</TABLE>

- ---------------

* Data not available.

** The Company did not obtain independent reserve reports at March 31, 1993 for
any of its oil and gas properties or at March 31, 1994 for its Bolivian
properties.

(See footnotes on following page)

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<PAGE> 9

NOTES TO SUMMARY HISTORICAL
CONSOLIDATED FINANCIAL AND OPERATING DATA

(1) The Company is involved in litigation with Tennessee Gas relating to a
natural gas sales contract. For additional information concerning this
dispute, see "Investment Considerations," "Legal Proceedings -- Tennessee
Gas Contract" and Notes K and P of Notes to Consolidated Financial
Statements.

(2) Segment operating profit represents pretax earnings (loss) before certain
corporate expenses, interest income and interest expense.

(3) Interest expense in 1993 is net of a $5.2 million credit for settlement of
several state tax issues (see Note H of Notes to Consolidated Financial
Statements). Excluding this credit, interest expense for 1993 would have
been $19.7 million.

(4) The net loss for the year ended December 31, 1992 included a charge of $20.6
million for the cumulative effect of the adoption of Statement of Financial
Accounting Standards ("SFAS") No. 106, "Employers' Accounting for
Postretirement Benefit Other than Pensions" and SFAS No. 109, "Accounting
for Income Taxes." The net earnings for the three months ended March 31,
1994 include a $4.8 million extraordinary loss related to an early
extinguishment of debt in connection with the Recapitalization, which was
completed in February 1994.

(5) The Refinery has a rated throughput capacity of 72,000 BPD.

(6) All sales of residual fuel oil represent sales of residual fuel oil produced
at the Refinery.

(7) Average finding cost per Mcf represents costs incurred in oil and gas
property acquisition, exploration and development activities for each
indicated period divided by the changes in proved reserves resulting from
extensions, discoveries and other additions and revisions of previous
reserve quantity estimates during such period. See Note P of Notes to
Consolidated Financial Statements.

(8) The present value of estimated future net revenues from proved reserves
represents the computation of estimated future net revenues, before
deduction of income taxes, relating to proved reserves at the end of each
period presented, discounted at a rate of 10% per annum and assuming no
escalation in prices. The present value of such estimated future net
revenues is not intended to be representative of the fair market value of
the Company's proved reserves. The calculations of revenues and costs used
to determine the present value of estimated future net revenues from proved
reserves, before deduction of income taxes, do not necessarily represent
the amounts to be received or expended by the Company.

8
<PAGE> 10

SELECTED SUMMARY PRO FORMA FINANCIAL DATA
(DOLLARS IN MILLIONS, EXCEPT PER SHARE AMOUNTS)

The following sets forth certain financial data on an historical basis and
as adjusted to give effect to the Recapitalization and the Offering, assuming
net proceeds of $54.0 million, after deduction of $3.5 million of underwriting
discounts and estimated expenses, from the issuance of 5,000,000 shares of the
Company's Common Stock (before the Underwriters' over-allotment option) at an
offering price of $11 1/2 per share pursuant to the Offering. The unaudited
summary pro forma financial data have been prepared assuming the
Recapitalization and the Offering occurred as of January 1, 1993 for statements
of operations and other financial data presentation purposes and on March 31,
1994 for balance sheet data presentation purposes. The pro forma financial data
assume that the proceeds from the Offering are used to exercise the MetLife
Louisiana Option in full at a price of $53.0 million and take into account the
payment of a cash dividend on the $2.20 Preferred Stock in May 1994 from the
Company's available cash. See "Use of Proceeds." The pro forma financial data
are not necessarily indicative of the Company's results of operations or
financial position in the future or of what the Company's results of operations
or financial position would have been had the transactions been consummated
during the periods, or as of the dates, for which pro forma financial
information is presented. The pro forma financial statements are based upon, and
should be read in conjunction with, "Pro Forma Condensed Consolidated Financial
Data," including the notes thereto, and the Consolidated Financial Statements,
including the notes thereto.

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1993
----------------------------------------------------
PRO FORMA
PRO FORMA RECAPITALIZATION
HISTORICAL RECAPITALIZATION AND OFFERING(1)
---------- ---------------- ----------------
<S> <C> <C> <C>
STATEMENT OF CONSOLIDATED OPERATIONS DATA:
Total revenues(2).................................. $834.9 $834.9 $834.9
Segment operating profit(3)........................ 52.3 52.3 52.3
General and administrative expenses................ 16.7 16.7 16.7
Interest expense(4)................................ 14.5 14.5 14.5
Earnings before income taxes and extraordinary
loss............................................ 18.7 18.6 18.6
Net earnings....................................... 17.0 12.1 12.1
Net earnings applicable to Common Stock............ 7.7 5.7 12.1
Earnings (loss) per primary and fully diluted*
share:
Earnings before extraordinary loss.............. $ .54 $ .46 $ .71
Extraordinary loss.............................. -- (.21) (.20)
---------- ------- -------
Net earnings.................................... $ .54 $ .25 $ .51
---------- ------- -------
---------- ------- -------
OTHER FINANCIAL DATA:
Depreciation, depletion and amortization............. $ 22.6 $ 22.6 $ 22.6
Capital expenditures................................. 37.5 37.5 37.5
</TABLE>

<TABLE>
<CAPTION>
THREE MONTHS ENDED MARCH 31, 1994
----------------------------------------------------
PRO FORMA
PRO FORMA RECAPITALIZATION
HISTORICAL RECAPITALIZATION AND OFFERING(1)
---------- ---------------- ----------------
<S> <C> <C> <C>
STATEMENT OF CONSOLIDATED OPERATIONS DATA:
Total revenues(2).................................. $192.7 $192.7 $192.7
Segment operating profit(3)........................ 18.3 18.3 18.3
General and administrative expenses................ 3.6 3.6 3.6
Interest expense................................... 4.9 4.9 4.9
Earnings before income taxes and extraordinary
loss............................................ 8.8 8.8 8.8
Net earnings....................................... 2.4 7.2 7.2
Net earnings applicable to Common Stock............ 0.5 5.6 7.2
Earnings (loss) per primary and fully diluted*
share:
Earnings before extraordinary loss.............. $ .27 $ .24 $ .30
Extraordinary loss.............................. (.24) -- --
---------- ------- -------
Net earnings.................................... $ .03 $ .24 $ .30
---------- ------- -------
---------- ------- -------
</TABLE>

- ---------------

* Anti-dilutive
(Table continued on following page)

9
<PAGE> 11

<TABLE>
<CAPTION>
AS OF MARCH 31, 1994
-----------------------------
PRO FORMA
HISTORICAL(5) OFFERING(1)
------------- -----------
<S> <C> <C>
BALANCE SHEET DATA:
Cash and short-term investments.................................... $ 49.4 $ 48.9
Long-term debt and other obligations, including current portion.... 184.9 184.9
Common Stock and other stockholders' equity........................ 144.1 143.6
Book value per common share........................................ 3.86 6.14
</TABLE>

- ---------------

(1) The Company is currently prohibited under the terms of the indenture
governing the Subordinated Debentures from repurchasing its capital stock,
including the shares of $2.20 Preferred Stock and Common Stock subject to
the MetLife Louisiana Option, except from the proceeds of a substantially
concurrent sale of other shares of capital stock. If the proceeds to the
Company from the Offering are not sufficient to exercise the MetLife
Louisiana Option in full, the Company would be able to exercise the MetLife
Louisiana Option only to the extent of the net proceeds of the Offering.

(2) The Company is involved in litigation with Tennessee Gas relating to a
natural gas sales contract. For additional information concerning this
dispute, see "Investment Considerations," "Legal Proceedings -- Tennessee
Gas Contract" and Notes K and P of Notes to Consolidated Financial
Statements.

(3) Segment operating profit represents pretax earnings before certain corporate
expenses, interest income and interest expense.

(4) Interest expense in 1993 is net of a $5.2 million credit for settlement of
several state tax issues (see Note H of Notes to Consolidated Financial
Statements). Excluding this credit, interest expense for 1993 would have
been $19.7 million.

(5) Includes the Recapitalization, which was consummated in February 1994.

10
<PAGE> 12

INVESTMENT CONSIDERATIONS

Prospective purchasers of shares of Common Stock offered hereby should
consider carefully, in addition to the other information contained in, or
incorporated by reference in, this Prospectus, the following matters:

Possible Adverse Impact of Pending Litigation. The Company is involved in
certain litigation regarding a gas purchase contract with Tennessee Gas. Two
producing acreage units within the Bob West Field are subject to the Tennessee
Gas Contract, pursuant to which Tennessee Gas pays prices greatly in excess of
spot market prices ($7.84 per Mcf during March 1994, compared to average spot
market prices for natural gas of $2.09 per Mcf during March 1994). During 1993,
the Tennessee Gas Contract price was paid with respect to approximately 27% of
the Company's net production from the Bob West Field. As of March 31, 1994, the
cumulative difference between the amount that Tennessee Gas has paid for gas
purchases under the Tennessee Gas Contract and the price that would have been
paid based on spot market prices totaled approximately $38.9 million, which the
Company anticipates will continue to increase. If Tennessee Gas ultimately
prevails in this litigation, the Company could be required to return to
Tennessee Gas this difference, plus interest, if awarded by the court. In
addition, the present value of estimated future net revenues on a pre-tax basis
from the Company's proved domestic reserves has been calculated based in part on
the price being paid by Tennessee Gas at the date of determination. At March 31,
1994, such present value was $171.0 million. If calculated using March 31, 1994
spot market prices instead of the contract price, such present value would have
been $92.0 million. The trial court judgment in the case in favor of the Company
was affirmed in part and reversed and remanded to the trial court in part by the
Court of Appeals. Both parties are seeking review of the appellate court ruling
in the Supreme Court of Texas. An adverse judgment in this case could have a
material adverse effect on the Company. See "Legal Proceedings -- Tennessee Gas
Contract" and Notes K and P of Notes to Consolidated Financial Statements.

Certain Provisions of Tennessee Gas Contract. Tennessee Gas has elected not
to take gas under the Tennessee Gas Contract on June 1, 1994. The Company does
not know if Tennessee Gas will elect to take gas under the Tennessee Gas
Contract thereafter. Tennessee Gas has the right to elect not to take gas during
any contract year subject to an obligation to pay for gas not taken at the end
of such contract year. The failure to take gas could adversely affect the
Company's income and cash flows from operating activities within a contract
year, but the Company should recover lost revenues shortly after the end of the
contract year under the take-or-pay provisions of the Tennessee Gas Contract.
The contract year ends on January 31 of each year.

Concentration of Operations. The Company's exploration and production
segment contributed 78% of total operating profit in 1993. Oil and gas
production is subject to interruption as a result of a variety of conditions and
events, including natural disasters, reservoir damage, mechanical difficulties,
unavailability of equipment and supplies, transportation problems, title and
contractual controversies, governmental regulation and others. Because the
Company's domestic oil and gas production is confined to South Texas, primarily
to the Bob West Field, and its international oil and gas operations are confined
to two blocks in Bolivia, the effect of any of such conditions or events on the
Company could be more adverse than if the Company were more geographically
diverse. Any interruption of oil and gas production in any one or more of the
Company's areas of operation could have a material adverse effect on the
Company.

All refinery operations are conducted at the Company's facility in Kenai,
Alaska. As a result, the operations of the Company would be subject to
significant interruption if the Refinery or the dock facilities used by the
Company were to experience a major accident or were damaged by severe weather or
other natural disaster. The Company maintains business interruption insurance
with respect to its Refinery operations in amounts that management of the
Company believes to be adequate.

Potential Interruption of Feedstock Availability. The Refinery currently
utilizes crude oil that is transported through the Trans Alaska Pipeline System
("TAPS") to Valdez, Alaska and from there to the Refinery by the Company's
time-chartered American flag vessel. In connection with an ongoing overhaul of
the electrical systems of the TAPS, numerous electrical code violations have
recently been discovered. While representatives of the TAPS have indicated that
they believe the overhaul of the electrical system and any action required to
remedy such violations will not cause any significant interruptions in the
transportation of crude oil through the TAPS, there is a possibility that such
interruptions could occur as a result of electrical

11
<PAGE> 13

failure, regulatory action or other matters related to the overhaul or the
violations. In 1993, approximately 72% (35,600 BPD) of the Refinery's feedstock
was ANS crude oil, of which approximately 24,300 BPD was purchased under a
royalty crude oil purchase contract with the State, which is scheduled to expire
at the end of 1994. The Company and the State have agreed in principle to extend
the contract through 1995. During 1994, this contract requires the Company to
purchase approximately 27,500 BPD of ANS crude oil, which equals approximately
55% of the Company's total feedstock requirements during 1993. The agreement in
principle between the Company and the State would require the Company to
purchase approximately 40,000 BPD of ANS crude oil during 1995, which equals
approximately 80% of the Company's total 1993 feedstock requirements. The
Company's remaining feedstock requirements are generally met through short-term
contracts and spot market purchases. In the event of any significant
interruption in this supply or transportation system, the Company has access to
other sources of feedstocks. However, the Company cannot predict the price or
terms on which such alternative feedstock supplies could be secured, and any
such interruption could have a material adverse effect on the Company's
operations.

Volatility of Prices, Earnings and Cash Flows. The markets for crude oil
and natural gas and the refined products produced at the Refinery historically
have been volatile and are likely to continue to be volatile in the future. An
increase in crude oil prices could adversely affect the Company's operating
margins. The Company's operating margins are subject to wide fluctuation in
response to relatively minor changes in the supply of and demand for crude oil
and natural gas and refined petroleum products, market uncertainty and a variety
of additional factors that are beyond the control of the Company. These factors
include the level of consumer product demand, weather conditions, domestic and
foreign government regulations, political conditions in other producing
countries, the actions of the Organization of Petroleum Exporting Countries, the
supply of foreign crude oil and natural gas, the proximity of the Company's gas
reserves to pipelines, the capacities of such pipelines, fluctuations in
seasonal demand, governmental regulations, the price of foreign imports, the
price and availability of alternative fuels and overall economic conditions. The
Company cannot predict the future markets and prices for the Company's natural
gas or refined products. Additionally, depressed worldwide residual fuel oil
markets have had a significantly negative effect on the Company's results of
operations. The Company cannot predict whether the market for residual fuel oil
will improve in the foreseeable future, although current projections indicate
that such markets will continue to be weak.

Decreases in the prices of natural gas have had, and could have in the
future, an adverse effect on the carrying value of the Company's proved reserves
and the Company's revenues, profitability and cash flow. Currently, spot natural
gas prices (Henry Hub) are favorable; however, such prices have been extremely
volatile over the last 30 months, ranging from a low of $1.03 per million
British thermal units ("MMBtu") in January 1992 to a high of $3.24 per MMBtu in
February 1994. The average Henry Hub price for 1993 was $2.21 per MMBtu versus
$1.80 per MMBtu for 1992.

Proposed Pipeline Rate Increase. The Company transports its crude oil and a
substantial portion of its refined products utilizing Kenai Pipe Line Company's
("KPL") pipeline and marine terminal facilities in Kenai, Alaska. In March 1994,
KPL filed a revised tariff with the Federal Energy Regulatory Commission
("FERC") for dock loading services, which 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. Following the FERC's
rejection of KPL's tariff and the commencement of negotiations for the purchase
by the Company of the dock facilities, KPL filed a temporary tariff that would
increase the Company's cost on an annual basis by approximately $1.5 million.
The negotiations between the Company and KPL are continuing. The Company
believes that the ultimate resolution of this matter will not have a material
adverse effect upon the financial condition or results of operations of the
Company.

Environmental Regulations and Liabilities. The Company is subject to
extensive federal, state and local laws and regulations governing releases into
the environment and the storage, transportation, disposal and cleanup of
hazardous waste materials. Future environmental regulations could result in
increased capital expenditures and operating costs that may adversely affect the
Company's results of operations and financial condition. At present, the Company
has been identified by the U.S. Environmental Protection Agency (the "EPA") as a
potentially responsible party ("PRP") pursuant to the Comprehensive
Environmental Response, Compensation, and Liability Act ("CERCLA") for two
Superfund sites. See "Management's Discussion and

12
<PAGE> 14

Analysis of Financial Condition and Results of Operations -- Environmental,"
"Business -- Government Regulation and Legislation" and "Legal
Proceedings -- Mud and Gulf Coast Superfund Sites." While the Company has from
time to time been, and presently is, the subject of litigation and
investigations relating to environmental and related matters, management of the
Company believes that such proceedings will not have a material adverse effect
on the results of operations or competitive position of the Company. However,
there can be no assurance that the Company will not become involved in further
litigation or other proceedings, or that if the Company were to be held
responsible for damage in any litigation or proceedings (including existing
ones), such costs would not be material. See "Business -- Government Regulation
and Legislation" and "Legal Proceedings."

The Company currently operates service stations in Alaska, and has in the
past operated service stations in other jurisdictions, that have underground
fuel storage tanks. All such storage tanks are subject to governmental
regulation and legislation. See "Business -- Government Regulation and
Legislation." The operation of underground storage tanks poses certain risks
apart from costs associated with regulatory requirements. These risks are
predominately damages associated with underground leaks of petroleum products.
The Company currently has leak detection and tank testing programs in effect in
Alaska to mitigate the threat of such risks. In addition, the majority of the
Company's operating service stations are in nonresidential locations, further
reducing the risks associated with contamination of residential areas. However,
there can be no assurance that the Company will not become liable for damages
from its underground storage tanks at some future date.

Uncertainty in Estimating Oil and Gas Reserves. There are numerous
uncertainties inherent in estimating quantities of proved reserves of oil and
gas and in projecting future rates of production and timing of development
expenditures, including many factors beyond the control of the Company. The
reserve data set forth in this Prospectus represent only estimates. In addition,
the present value of estimated future net revenues from proved reserves of the
Company is based upon certain assumptions about future production levels, prices
and costs that may not prove correct over time. For information concerning the
risk of litigation which, if adversely determined, could affect such estimates,
see " -- Possible Adverse Impact of Pending Litigation" and "Legal
Proceedings -- Tennessee Gas Contract."

The Company periodically reviews the carrying value of its oil and gas
properties under the full-cost accounting rules of the Securities and Exchange
Commission (the "SEC" or the "Commission"). Under the full-cost accounting
rules, capitalized costs of oil and gas properties may not exceed the present
value of estimated future net cash flows from proved reserves on an after-tax
basis, discounted at 10% per annum, plus the lower of cost or fair market value
of unproved properties. Application of this rule generally requires pricing
future revenues at the unescalated prices in effect as of the end of each fiscal
quarter and requires a write-down if the "ceiling" is exceeded, even if prices
declined for only a short period of time. The risk that the Company will be
required to write down the carrying value of its crude oil and natural gas
properties increases when crude oil and natural gas prices are depressed or
unusually volatile.

Depletion of Reserves; Risk of Oil and Gas Operations. The Bob West Field
has a relatively short reserve life of approximately 5.8 years based on December
1993 production levels. The Company expects to increase future production rates,
which may result in more rapid depletion of this field. Without the acquisition
of producing properties or successful drilling of new wells, the Company's
production and reserves will decline. To the extent the Company engages in
drilling activities, such activities carry the risk that no commercially viable
oil and gas production will be obtained. The cost of drilling, completing and
operating wells is often uncertain. Moreover, drilling may be curtailed, delayed
or canceled as a result of many factors, including title problems, regulatory
delays, weather conditions and shortages or delays in delivery of equipment, as
well as the financial instability of well operators, major working interest
owners and well servicing companies.

Possible Limitation on Use of Tax Benefits. Under Sections 382 and 383 of
the Internal Revenue Code of 1986, if the Company has an "ownership change," as
defined therein, the Company's use of its net operating loss carryforwards and
general business credits after the ownership change will be subject to an annual
limit (the "382 Limit"). The Company intends to take the position that an
ownership change under existing law has not occurred as a result of the
Recapitalization and will not occur as a result of the Offering and the

13
<PAGE> 15

exercise in full of the MetLife Louisiana Option. Because there are substantial
interpretive questions concerning the application of Sections 382 and 383 and
because changes in ownership of the Company occurring within three years after
the Offering and the exercise of the MetLife Louisiana Option are taken into
account in determining whether an ownership change has occurred, there can be no
assurance that an ownership change will not occur as a result of the Offering
and the exercise of the MetLife Louisiana Option or as a result of future
events. If an ownership change occurs as a result of the Offering and the
exercise of the MetLife Louisiana Option, the 382 Limit, based on the market
value of the Common Stock on May 26, 1994, could be as low as approximately
$12.3 million per year. The Company's net operating loss carryforwards and
general business credits at December 31, 1993 were approximately $71.1 million
and $8.2 million, respectively.

Foreign Operations. A portion of the Company's operations are conducted in
foreign countries, where the Company is subject to risks of a political nature
and other risks inherent in foreign operations. The Company's operations outside
the United States 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.

Operating Hazards. The Company's oil and gas and refining operations are
hazardous due to the combination of individuals and machines operating in
restricted work areas and the highly flammable nature of crude oil, natural gas
and refined products. As a result, the Company has experienced personal injury
and property damage incidents in the past and expects such incidents to occur in
the future. The frequency and severity of such incidents affect the Company's
operating costs, insurability and relationships with customers, employees and
regulators. Any significant increase in the frequency or severity of such
incidents, or the general level of compensation awards with respect thereto,
could affect the ability of the Company to obtain insurance and could have a
material adverse effect on the Company.

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. The industry also competes
with other industries that supply the energy and fuel requirements of
industrial, commercial, individual and other consumers. The Company competes
with a substantial number of major integrated oil companies and other companies
having materially greater financial and other resources. These competitors have
a greater ability to bear the economic risks inherent in all phases of the
industry. In addition, unlike the Company, many competitors also produce large
volumes of crude oil, which may be used in connection with their refining
operations. The North American Free Trade Agreement has further streamlined and
simplified procedures for the importation and exportation of gas among Mexico,
the United States and Canada. These changes are likely to enhance the ability of
Canadian and Mexican producers to export natural gas to the United States,
thereby further increasing competition in the domestic natural gas market.

THE COMPANY

USE OF PROCEEDS

The net proceeds from the Offering are estimated to be approximately $54.0
million ($59.5 million if the over-allotment option is exercised), after
deduction of underwriting discounts and estimated expenses. The Company will use
such proceeds to exercise the MetLife Louisiana Option. Any net proceeds in
excess of the amount required to exercise the MetLife Louisiana Option in full
will be used for general corporate purposes. The aggregate amount required to
exercise the MetLife Louisiana Option in full prior to June 30, 1994, is

14
<PAGE> 16

approximately $53.0 million, after giving effect to a reduction in the option
price for the cash dividend paid on the $2.20 Preferred Stock in May 1994. If
the MetLife Louisiana Option is exercised in full prior to June 30, 1994, the
Company will acquire 2,875,000 shares of $2.20 Preferred Stock having a
liquidation value of approximately $57.5 million and 4,084,160 shares of Common
Stock having an aggregate market value of $47.0 million (based on a closing
price of $11 1/2 per share on May 26, 1994) in consideration for approximately
$53.0 million. Upon the exercise in full of the MetLife Louisiana Option,
dividend requirements of $6.3 million per year on the $2.20 Preferred Stock
would be eliminated. The Offering and the exercise in full of the MetLife
Louisiana Option will result in a net increase of only 915,840 outstanding
shares of Common Stock.

If the net proceeds from the Offering are less than the full exercise
price, the MetLife Louisiana Option will be exercised in part to the extent of
the net proceeds. The MetLife Louisiana Option provides that any partial
exercise will result in the purchase of a pro rata portion of each of the shares
of Common Stock and the shares of $2.20 Preferred Stock held by MetLife
Louisiana. The Company is currently prohibited under the terms of the indenture
governing the Subordinated Debentures from repurchasing its capital stock,
including the shares of $2.20 Preferred Stock and Common Stock subject to the
MetLife Louisiana Option, except from the proceeds of a substantially concurrent
sale of other shares of capital stock. Accordingly, if the proceeds to the
Company from the Offering are not sufficient to exercise the MetLife Louisiana
Option in full, the Company would be able to exercise the MetLife Louisiana
Option only to the extent of the net proceeds of the Offering.

PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY

The Common Stock is listed on the New York Stock Exchange and Pacific Stock
Exchange under the symbol "TSO." The following table sets forth, on a per share
basis, the high and low sales prices of the Common Stock on the New York Stock
Exchange - Composite Tape, as reported by the Dow Jones News/Retrieval Service,
for each of the quarterly periods indicated. As of May 26, 1994, there were
4,111 holders of record of Common Stock.

<TABLE>
<CAPTION>
HIGH LOW
----- -----
<S> <C> <C>
1992:
First.............................................................. $6 5/8 $4 5/8
Second............................................................. 5 3/8 4 1/4
Third.............................................................. 5 1/2 3
Fourth............................................................. 3 5/8 2 1/2
1993:
First.............................................................. 5 5/8 3
Second............................................................. 6 5/8 5
Third.............................................................. 7 3/4 5 1/8
Fourth............................................................. 7 1/2 5 1/8
1994:
First.............................................................. 12 3/8 5 1/4
Second (through May 26, 1994)...................................... 12 1/8 9 7/8
</TABLE>

On May 26, 1994, the closing price of the Common Stock on the New York
Stock Exchange - Composite Tape, as reported by the Dow Jones News/Retrieval
Service, was $11 1/2 per share.

Certain provisions of the Company's Revolving Credit Facility (as
hereinafter defined) and the indenture governing the Subordinated Debentures
effectively prohibit the Company from currently paying cash dividends on Common
Stock. The Company has not paid cash dividends on the Common Stock since 1986,
and does not anticipate paying cash dividends on Common Stock in the foreseeable
future.

15
<PAGE> 17

CAPITALIZATION

The following table sets forth the unaudited consolidated capitalization of
the Company as of March 31, 1994 and as adjusted to give effect to the Offering
and the application of the estimated net proceeds of the Offering as set forth
under "Use of Proceeds." The information presented below should be read in
conjunction with "Selected Financial Data," "Pro Forma Condensed Consolidated
Financial Data," including the notes thereto, and the Consolidated Financial
Statements, including the notes thereto.

<TABLE>
<CAPTION>
AS OF MARCH 31, 1994
------------------------------------
HISTORICAL(1) PRO FORMA OFFERING
------------- ------------------
(DOLLARS IN MILLIONS)
<S> <C> <C>
Long-term debt and other obligations, including current
portion:
Subordinated Debentures...................................... $ 58.6 $ 58.6
Exchange Notes............................................... 44.1 44.1
Liability to State of Alaska................................. 61.7 61.7
Liability to Department of Energy............................ 13.2 13.2
Other........................................................ 7.3 7.3
------- -------
Total long-term debt and other obligations, including
current
portion................................................. 184.9 184.9
------- -------
Common Stock and other stockholders' equity:
$2.20 Preferred Stock........................................ 57.5 -- (2)
Common Stock................................................. 3.7 3.9 (2)(3)
Additional paid-in capital................................... 114.4 171.2 (2)
Accumulated deficit.......................................... (31.3) (31.3)
Deferred compensation........................................ (.2) (.2)
------- -------
Total Common Stock and other stockholders' equity......... 144.1 143.6
------- -------
Total capitalization........................................... $ 329.0 $328.5
------- -------
------- -------
Shares of Common Stock issued and outstanding (in thousands)... 22,457 23,373 (3)
</TABLE>

- ---------------

(1) Includes the Recapitalization, which was consummated in February 1994.

(2) Reflects the sale of 5,000,000 shares of Common Stock in the Offering at an
assumed price of $11 1/2 per share. See "Use of Proceeds."

(3) Represents a net increase of 915,840 shares of Common Stock associated with
the Offering, resulting from the issuance of 5,000,000 shares of Common
Stock in the Offering and the application of the net proceeds to reacquire
and retire 4,084,160 shares of Common Stock in connection with the exercise
in full of the MetLife Louisiana Option.

16
<PAGE> 18

SELECTED FINANCIAL DATA
(DOLLARS IN MILLIONS, EXCEPT PER SHARE AMOUNTS)

The selected financial data for the three years ended September 30, 1991,
the three months ended December 31, 1991, and the years ended December 31, 1992
and 1993 are taken from the selected financial data contained in the Company's
Annual Report on Form 10-K for the year ended December 31, 1993. The selected
financial data for the three months ended March 31, 1993 and March 31, 1994 are
unaudited and are taken from the Company's Condensed Consolidated Financial
Statements contained in the Company's Quarterly Reports on Form 10-Q for the
quarters ended March 31, 1993 and March 31, 1994, respectively. The historical
financial data below should be read in conjunction with "Management's Discussion
and Analysis of Financial Condition and Results of Operations" and the
Consolidated Financial Statements, including the notes thereto.

<TABLE>
<CAPTION>
THREE MONTHS
YEAR ENDED THREE MONTHS YEAR ENDED ENDED
SEPTEMBER 30, ENDED DECEMBER 31, MARCH 31,
---------------------------- DECEMBER 31, ----------------- ---------------
1989 1990 1991 1991 1992(1) 1993(2) 1993 1994
------ -------- -------- ------------ ------- ------- ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF CONSOLIDATED
OPERATIONS DATA:
Gross operating
revenues(3)................ $762.6 $ 996.6 $1,085.0 $240.6 $ 946.5 $ 831.0 $224.5 $189.1
Interest income.............. 9.4 5.8 4.2 .7 3.2 1.8 .5 .5
Gain (loss) on sales of
assets..................... (4.9) 1.7 .1 -- 4.0 .1 -- 2.7
Other income................. (.1) 2.4 1.7 2.6 .7 2.0 1.5 .4
------ -------- -------- ------------ ------- ------- ------ ------
Total revenues........... 767.0 1,006.5 1,091.0 243.9 954.4 834.9 226.5 192.7
Costs of sales and operating
expenses................... 718.6 920.5 1,015.9 228.6 926.1 756.8 213.8 167.6
General and administrative... 33.9 20.2 17.0 2.8 25.9 16.7 3.4 3.6
Depreciation, depletion and
amortization............... 21.9 12.8 15.0 4.2 16.6 22.6 4.8 6.6
Interest expense(4).......... 17.7 20.8 18.8 5.0 21.1 14.5 5.0 4.9
Other........................ 6.1 5.9 5.3 .7 4.6 5.6 1.7 1.2
Income tax provision
(benefit).................. (.7) 3.6 15.1 3.0 5.4 1.7 .7 1.6
------ -------- -------- ------------ ------- ------- ------ ------
Earnings (loss) before the
cumulative effect of
accounting changes and
extraordinary loss......... (30.5) 22.7 3.9 (.4) (45.3) 17.0 (2.9) 7.2
Cumulative effect of
accounting changes......... -- -- -- -- (20.6) -- -- --
Extraordinary loss on
extinguishment of debt..... -- -- -- -- -- -- -- (4.8)
------ -------- -------- ------------ ------- ------- ------ ------
Net earnings (loss)(5)....... $(30.5) $ 22.7 $ 3.9 $ (.4) $ (65.9) $ 17.0 $ (2.9) $ 2.4
------ -------- -------- ------------ ------- ------- ------ ------
------ -------- -------- ------------ ------- ------- ------ ------
Net earnings (loss)
applicable to Common
Stock(5)................... $(39.7) $ 13.5 $ (5.3) $ (2.7) $ (75.1) $ 7.7 $ (5.2) $ .5
------ -------- -------- ------------ ------- ------- ------ ------
------ -------- -------- ------------ ------- ------- ------ ------
Earnings (loss) per primary
and fully diluted*
share(2)(5):
Earnings (loss) before
the cumulative effect
of accounting changes
and extraordinary loss
on extinguishment of
debt.................. $(2.83) $ .96 $ (.37) $ (.19) $ (3.87) $ .54 $ (.37) $ .27
Cumulative effect of
accounting changes.... -- -- -- -- (1.47) -- -- --
Extraordinary loss on
extinguishment of
debt.................. -- -- -- -- -- -- -- (.24)
------ -------- -------- ------------ ------- ------- ------ ------
Net earnings (loss)(5)... $(2.83) $ .96 $ (.37) $ (.19) $ (5.34) $ .54 $ (.37) $ .03
------ -------- -------- ------------ ------- ------- ------ ------
------ -------- -------- ------------ ------- ------- ------ ------
</TABLE>

(Table continued on following page)

17
<PAGE> 19

<TABLE>
<CAPTION>
AS OF
AS OF SEPTEMBER 30, AS OF DECEMBER 31, MARCH 31,
---------------------------- ------------------------ ---------------
1989 1990 1991 1991 1992 1993 1993 1994
------ -------- -------- ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
BALANCE SHEET AND OTHER DATA:
Cash and short-term
investments............. $ 71.9 $ 78.8 $ 62.7 $ 61.0 $ 66.9 $ 42.5 $ 66.2 $ 49.4
Capital expenditures....... 13.2 23.1 24.5 3.9 15.4 37.5 5.1 18.5
Total assets............... 445.3 504.9 496.8 494.7 446.7 434.5 427.7 442.1
Working capital............ 105.1 117.9 95.4 106.1 122.6 124.5 109.7 110.3
Long-term debt and other
obligations, including
current portion(2)...... 163.2 168.0 184.7 189.4 201.7 185.5 180.4 184.9
Redeemable preferred
stock(2)................ 57.4 57.4 57.4 57.4 71.7 78.1 73.3 --
Common Stock and
other stockholders'
equity(2)(6)............ 125.4 141.4 137.4 137.0 50.7 58.5 45.5 144.1
</TABLE>

- ---------------

* Anti-dilutive.

(1) The Company's fiscal year end was changed from September 30 to December 31,
effective January 1, 1992.

(2) For pro forma information on the effects of the Recapitalization, which
occurred in February 1994, see "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and Note B of Notes to
Consolidated Financial Statements.

(3) The Company is involved in litigation with Tennessee Gas relating to a
natural gas sales contract. For additional information concerning this
dispute, see "Investment Considerations," "Legal Proceedings -- Tennessee
Gas Contract" and Notes K and P of Notes to Consolidated Financial
Statements.

(5) The net loss for the year ended December 31, 1992 included a charge of $20.6
million for the cumulative effect of the adoption of SFAS No. 106,
"Employer's Accounting for Postretirement Benefit Other than Pensions" and
SFAS No. 109, "Accounting for Income Taxes." The net earnings for the three
months ended March 31, 1994 include a $4.8 million extraordinary loss
related to an early extinguishment of debt in connection with the
Recapitalization, which was completed in February 1994.

(6) No dividends were paid on Common Stock during the periods presented above.

18
<PAGE> 20

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS

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. Also included herein are the
Company's results of operations for the three months ended March 31, 1994
compared to the three months ended March 31, 1993.

Net earnings of $2.4 million, or $.03 per share, for the three months ended
March 31, 1994 ("1994 quarter") compare to a net loss of $2.9 million, or $.37
per share, for the three months ended March 31, 1993 ("1993 quarter"). The
comparability between these two periods was impacted by certain transactions.
The 1994 quarter included a non-cash extraordinary loss of $4.8 million on the
extinguishment of debt in connection with the Recapitalization. Earnings before
the extraordinary loss were $7.2 million, or $.27 per share, for the 1994
quarter. Also included in the 1994 quarter was a $2.8 million gain on the sale
of the Company's Valdez, Alaska terminal. The 1993 quarter included a gain of
$1.4 million on the repurchase and retirement of $11.25 million principal amount
of Subordinated Debentures at market value. Excluding these transactions from
both periods, the improvement in the 1994 quarter as compared to the 1993
quarter was primarily attributable to higher natural gas prices on increased
natural gas production from the Bob West Field and improved gross margins in the
refining and marketing operations.

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 in 1993 for the retirement of $11.25
million principal 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 from the Bob West Field 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 Bob West Field.

19
<PAGE> 21

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, together with the following
information, are intended to provide 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

<TABLE>
<CAPTION>
YEAR ENDED YEAR ENDED THREE MONTHS
SEPTEMBER 30, DECEMBER 31, ENDED MARCH 31,
------------- ----------------- -----------------
1991 1992 1993 1993 1994
-------- ------- ------- ------- -------
(DOLLARS IN MILLIONS, EXCEPT PER UNIT PRICES)
<S> <C> <C> <C> <C> <C>
Gross operating revenues...................... $ 898.6 $ 810.7 $ 687.2 $ 194.6 $ 150.3
Costs of sales................................ 802.8 738.9 584.6 173.1 124.2
------- ------- ------- ------- -------
Gross margin................................ 95.8 71.8 102.6 21.5 26.1
Operating expenses and other, including gain
on sales of assets.......................... 67.5 76.5 77.1 17.8 17.1
Depreciation and amortization................. 9.0 10.2 10.3 2.5 2.6
------- ------- ------- ------- -------
Operating profit (loss)..................... $ 19.3 $ (14.9) $ 15.2 $ 1.2 $ 6.4
------- ------- ------- ------- -------
------- ------- ------- ------- -------
Refinery throughput (average BPD)............. 68,192 61,425 49,753 52,911 45,320
Sales of Refinery production:
Sales (per Bbl)............................. $ 24.40 $ 21.30 $ 21.91 $ 20.98 $ 18.46
Margin (per Bbl)............................ $ 2.77 $ 1.18 $ 4.19 $ 2.94 $ 4.24
Volume (average BPD)........................ 66,837 62,218 49,425 57,332 46,236
Sales of products purchased for resale:
Sales (per Bbl)............................. $ 31.48 $ 27.58 $ 27.50 $ 26.43 $ 24.12
Margin (per Bbl)............................ $ .37 $ 1.09 $ 1.35 $ .88 $ 2.62
Volume (average BPD)........................ 23,318 25,222 19,340 22,643 19,582
Sales volumes (average BPD):
Gasoline.................................... 25,883 25,196 22,466 25,907 22,570
Jet fuel.................................... 15,055 19,060 11,305 12,618 10,678
Diesel fuel and other distillates........... 20,488 19,253 18,049 20,584 16,124
Residual fuel oil........................... 28,729 23,931 16,945 20,866 16,446
------- ------- ------- ------- -------
Total............................... 90,155 87,440 68,765 79,975 65,818
------- ------- ------- ------- -------
------- ------- ------- ------- -------
Sales price (per Bbl):
Gasoline.................................... $ 30.69 $ 28.89 $ 27.64 $ 25.51 $ 23.92
Jet fuel.................................... 35.15 27.76 28.10 28.70 25.43
Diesel fuel and other distillates........... 29.78 25.78 26.95 26.19 23.53
Residual fuel oil........................... 15.15 11.60 11.19 11.46 8.22
</TABLE>

Three Months Ended March 31, 1994 Compared to Three Months Ended March 31,
1993. Revenues decreased in the 1994 quarter as compared to the 1993 quarter,
primarily due to an 18% reduction in sales volumes of refined products. The
reduction in volumes resulted from the Company's market-driven operating
strategy implemented in 1993, which more closely aligns Refinery production with
market demand in Alaska while minimizing the output of lower value residual fuel
oil. Costs of sales were lower in the 1994 first quarter, due to the reduced
throughput level together with a decrease in crude oil prices. Included in
operating expenses and other above for the 1994 quarter was the $2.8 million
gain from the sale of the Company's Valdez, Alaska terminal. The overall
improvement in gross margin and the gain on sales of assets were partially
offset by a $2.1 million increase in operating expenses which included higher
environmental and transportation costs.

20
<PAGE> 22

Damage to West Coast pipelines caused by an earthquake in 1994 has resulted
in temporary increased demand for ANS crude oil for use as a feedstock in West
Coast refineries and a resulting increase in the cost of ANS crude oil to the
Refinery. Sales prices of refined products produced at the Refinery have not
increased proportionately and, as a result, refined product margins during the
second quarter of 1994 have been depressed. The Company anticipates that such
conditions will adversely affect results for the second quarter of 1994 and
thereafter for so long as such conditions exist.

1993 Compared to 1992. During 1993, the Company implemented a market-driven
operational strategy, which emphasizes the upgrading of Refinery feedstocks and
more closely matching production of the 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 new refining and marketing operational
strategy, the Company reduced its average 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 ANS crude oil in the feedstock blend. By
utilizing a greater percentage of higher quality feedstocks (which results in
production yields with greater margins than production yields from a higher
percentage of lower quality 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 significant 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 relating to 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.

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 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 in response to certain environmental requirements. 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. Such
environmental requirements were suspended in December 1992. See "Business --
Government Regulation and Legislation." 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. These increases in operating costs were
partially offset by a transportation rebate received in 1992.

21
<PAGE> 23

Exploration and Production

<TABLE>
<CAPTION>
THREE MONTHS
YEAR ENDED ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
SEPTEMBER 30, ----------------- -----------------
1991 1992 1993 1993 1994
------------- ------- ------- ------- -------
(DOLLARS IN MILLIONS, EXCEPT PER UNIT AMOUNTS)
<S> <C> <C> <C> <C> <C>
United States:
Gross operating revenues.................... $ 5.2 $ 18.8 $ 50.5 $ 7.7 $ 17.4
Lifting cost................................ 1.2 3.8 6.8 1.2 2.1
Depreciation, depletion and amortization.... 2.9 4.9 11.1 2.0 3.8
Other....................................... .5 1.2 .3 .3 .3
------- ------- ------- ------- -------
Operating profit -- United States........ .6 8.9 32.3 4.2 11.2
------- ------- ------- ------- -------
Bolivia:
Gross operating revenues.................... 24.5 17.9 12.6 2.8 2.8
Lifting cost................................ .6 .7 1.2 .4 .2
Other....................................... 2.7 4.6 3.0 1.0 .7
------- ------- ------- ------- -------
Operating profit -- Bolivia.............. 21.2 12.6 8.4 1.4 1.9
------- ------- ------- ------- -------
Indonesia (sold effective May 1, 1992):
Gross operating revenues.................... 29.5 6.0 -- -- --
Lifting cost................................ 9.5 3.7 -- -- --
Depreciation, depletion and amortization.... 1.7 .3 -- -- --
Other....................................... 4.5 (5.6) -- -- --
------- ------- ------- ------- -------
Operating profit -- Indonesia............ 13.8 7.6 -- -- --
------- ------- ------- ------- -------
Total operating profit........................ $ 35.6 $ 29.1 $ 40.7 $ 5.6 $ 13.1
------- ------- ------- ------- -------
------- ------- ------- ------- -------
Natural Gas -- United States:
Production (average daily Mcf)
Tennessee Gas Contract................... 1,300 3,974 10,599 6,356 16,181
Spot market and other.................... 6,135 9,986 28,168 20,653 32,817
------- ------- ------- ------- -------
Total production.................... 7,435 13,960 38,767 27,009 48,998
------- ------- ------- ------- -------
------- ------- ------- ------- -------
Proved reserves -- end of period (Bcf)...... 33.1 73.8 120.2 * 121.5
Average sales price (per Mcf):
Tennessee Gas Contract................... $ -- $ 4.46 $ 7.59 $ 7.36 $ 7.80
Spot market.............................. 1.88 1.83 2.03 1.75 2.01
Average.................................. 1.88 3.68 3.55 3.07 3.92
Average lifting cost (per Mcf).............. .44 .74 .48 .49 .53
Depletion (per Mcf)......................... 1.06 .95 .78 .82 .85
Natural Gas -- Bolivia:
Production (average daily Mcf).............. 19,322 19,421 19,232 17,747 19,137
Proved reserves -- end of period (Bcfe)..... 131.6 120.1 111.9 * *
Average sales price (per Mcf)............... $ 3.06 $ 1.67 $ 1.22 $ 1.19 $ 1.23
Average lifting cost (per net equivalent
Mcf)..................................... $ .09 $ .08 $ .14 $ .23 $ .11
Crude Oil -- Indonesia (sold effective May 1,
1992):
Production (average BPD).................... 3,315 2,714 -- -- --
Average sales price (per Bbl)............... $ 24.39 $ 18.20 -- -- --
Average lifting cost (per net equivalent
Mcf)..................................... $ 1.35 $ 1.94 -- -- --
</TABLE>

- ---------------

* The Company did not obtain independent reserve reports at March 31, 1993 for
any of its oil and gas properties or at March 31, 1994 for its Bolivian
properties.

22
<PAGE> 24

Three Months Ended March 31, 1994 Compared to Three Months Ended March 31,
1993. The number of producing wells in South Texas in which the Company has an
interest increased to 33 at the end of the 1994 quarter compared to 11 at the
end of the 1993 quarter. The resulting increase in the Company's production
levels in South Texas, together with higher average sales prices, contributed to
the higher revenues. Total lifting costs and depreciation, depletion and
amortization also increased in the 1994 quarter due to the higher production
levels.

The 1994 quarter production level, which was higher than the 1993
quarter's, was lower than the 58 MMcf per day produced during the three months
ended December 31, 1993. Beginning 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 affected only
production subject to spot market prices, and the Company continued to produce
and transport all of its gas in the Bob West Field subject to the Tennessee Gas
Contract. Accordingly, the average realized selling price for the Company's
domestic natural gas was $3.92 per Mcf during the 1994 quarter, which compares
to $3.07 per Mcf in the 1993 quarter. A new common carrier pipeline began
transporting the increased gas production from the Bob West Field in May 1994.
The Company believes that there should now be adequate transportation for all of
its gas production from the Bob West Field. See "Investment Considerations,"
"Legal Proceedings -- Tennessee Gas Contract" and Notes K and P of Notes to
Consolidated Financial Statements regarding litigation involving the Tennessee
Gas Contract.

Tennessee Gas has elected not to take gas under the Tennessee Gas Contract
on June 1, 1994. The Company does not know if Tennessee Gas will elect to take
gas under the Tennessee Gas Contract thereafter. Tennessee Gas has the right to
elect not to take gas during any contract year subject to an obligation to pay
for gas not taken at the end of such contract year. The failure to take gas
could adversely affect the Company's income and cash flows from operating
activities within a contract year, but the Company should recover lost revenues
shortly after the end of the contract year under the take-or-pay provisions of
the Tennessee Gas Contract. The contract year ends on January 31 of each year.

Results from the Company's Bolivian operations improved by $.5 million when
comparing the 1994 quarter to the 1993 quarter. Under a sales contract with
YPFB, the Company's Bolivian natural gas production is sold to YPFB, which in
turn sells the natural gas to the Republic of Argentina. The contract between
YPFB and the Republic of Argentina has recently been extended for an additional
three-year period ending March 31, 1997. The contract extension will maintain
approximately the same volumes, but with a small decrease in price. The
Company's contract with YPFB, including the pricing provision, is subject to
renegotiation in May 1994 for up to a three-year period. As a result of the
terms of the contract extension between YPFB and the Republic of Argentina, the
Company expects the renegotiation to result in a corresponding small decrease in
the contract price. The renegotiation could also result in a reduction of
volumes purchased from the Company due to new supply sources anticipated to
commence producing near the end of 1994.

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 end of
1993 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 to $3.55 per Mcf in 1993, as compared to $3.68 per Mcf in 1992. Total
lifting costs and depreciation, depletion and amortization increased in 1993 due
to the higher production volumes; however, the depletion rate decreased due to
the 63% increase in proved reserves.

The Company's Bolivian operations experienced a decline in revenues
primarily due to reduced contractual sales prices for the natural gas
production.

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.

23
<PAGE> 25

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 Bob West Field.

Oil Field Supply and Distribution

YEAR ENDED THREE MONTHS ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
SEPTEMBER 30, -------------------- --------------------
1991 1992 1993 1993 1994
------------- ------- ------- ------- -------
(DOLLARS IN MILLIONS)
<S> <C> <C> <C> <C> <C>
Gross operating revenues....................... $ 134.3 $ 93.5 $ 80.7 $ 19.4 $ 18.6
Costs of sales................................. 118.7 82.4 68.4 16.6 15.9
------- ------ ------ ------ ------
Gross margin................................. 15.6 11.1 12.3 2.8 2.7
Operating expenses and other................... 15.6 15.3 15.5 3.5 3.8
Depreciation and amortization.................. .5 .5 .4 .1 .1
------- ------ ------ ------ ------
Operating loss............................... $ (.5) $ (4.7) $ (3.6) $ (.8) $ (1.2)
------- ------ ------ ------ ------
------- ------ ------ ------ ------
Refined product sales (average BPD)............ 10,470 8,476 7,368 6,897 7,424
</TABLE>

Three Months Ended March 31, 1994 Compared to Three Months Ended March 31,
1993. Operating expenses and other for the 1994 quarter included a charge of
approximately $.9 million for winding up the Company's environmental products
marketing operations. The Company is continuing its wholesale marketing of fuels
and lubricants.

1993 Compared to 1992. Revenues and costs of sales in this segment during
1993 decreased when compared to 1992 due to the discontinuance, in the 1992
second quarter, of the operation of a wholesale distribution facility in
Oklahoma. In addition, the decrease in crude oil prices during 1993 resulted in
a correlative decrease in refined product prices. Notwithstanding such
decreases, margins 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 marine terminals;
however, this acquisition did not have a material impact on the revenues or
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 War. 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

There was no significant change in general and administrative expenses in
the 1994 quarter compared to the 1993 quarter. General and administrative
expenses of $16.7 million in 1993 compare to $25.9 million in 1992 and $17.0
million in 1991. The decrease in 1993 was primarily due to the inclusion in 1992
of 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. There were no significant comparable charges recorded in 1993. The
remaining decrease in 1993 was attributable to the effects of the cost reduction
program. The increase in 1992 as compared to 1991 was mainly due to expenses for
the cost reduction program in 1992.

24
<PAGE> 26

Interest and Other Income

Other income in the 1993 quarter included a $1.4 million gain from the
purchase and retirement of $11.25 million principal amount of Subordinated
Debentures in January 1993. Since this retirement satisfied the sinking fund
requirement due in March 1993, the gain was not reported as an extraordinary
item. 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; 1992 included a $5.8 million
gain from the sale 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 the $1.4 million gain from
the purchase and retirement of Subordinated Debentures in January 1993.

Interest Expense

There was no significant change in interest expense in the 1994 quarter
compared to the 1993 quarter. 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

The increase of $.8 million in the income tax provision during the 1994
quarter as compared to the 1993 quarter was due to federal and state income
taxes on the Company's increased taxable earnings. Income taxes of $1.7 million
in 1993 compare to $5.4 million in 1992 and $15.1 million in 1991. The decrease
in 1993 included a reduction of $3.0 million for resolution of outstanding
issues with several state taxing authorities. In addition, foreign income taxes
continued to decrease in 1993 and 1992 due to reduced revenues from the
Company's Bolivian and former Indonesian operations.

Three Months Ended December 31, 1991 Compared to the Three Months Ended
December 31, 1990

The Statements of Consolidated Operations and Statements of Consolidated
Cash Flows for the three months ended December 31, 1991 are presented in the
Consolidated Financial Statements. For discussion purposes, results for the
three months ended December 31, 1991 are compared to the unaudited three-month
period ended December 31, 1990, as set forth in Note C of Notes to Consolidated
Financial Statements.

The net loss of $.4 million for the three months ended December 31, 1991
(the "1991 quarter") represented a decrease of $5.3 million from the net
earnings of $4.9 million recorded during the three months ended December 31,
1990 (the "1990 quarter"). Total revenues of $243.9 million for the 1991 quarter
decreased $92.3 million from the 1990 quarter, largely due to lower sales prices
for refined products. The 1990 quarter had been impacted by escalating refined
product and crude oil prices during the conflict in the Persian Gulf. During the
1991 quarter, the Company's exploration and production operations in Indonesia
realized lower sales prices on reduced crude oil production as compared to the
1990 quarter. Also contributing to the decrease in total revenues in the 1991
quarter was reduced interest income resulting from lower interest rates on less
cash available for investment. Partially offsetting these decreases in the 1991
quarter were revenues from the Company's convenience store operations in Alaska
and other income resulting from settlement of a matter in litigation. Costs of
sales and operating expenses decreased $83.4 million in the 1991 quarter as
compared to the 1990 quarter, due primarily to the lower prices of crude oil and
refined products, partially offset by costs from the Company's convenience store
operations.

The refining and marketing segment's operating profit of $1.7 million in
the 1991 quarter was a decrease of $.8 million from the $2.5 million operating
profit recorded in the 1990 quarter. The decrease was primarily

25
<PAGE> 27

due to lower sales prices for residual fuel oil, which continued to be adversely
impacted by the weak markets for this product.

The exploration and production segment's operating profit of $7.4 million
in the 1991 quarter decreased $8.2 million from the $15.6 million operating
profit recorded in the 1990 quarter. The decrease was mainly due to lower crude
oil sales prices on reduced production volumes from the Company's Indonesian
operations. The Company's Indonesian crude oil production decreased by 1,435
BPD, with an average sales price of $20.57 per Bbl during the 1991 quarter as
compared to $29.39 per Bbl during the 1990 quarter. The Company's operations in
Bolivia also experienced lower natural gas sales prices on reduced production
volumes in the 1991 quarter. Natural gas production from the Company's Bolivian
operations decreased by 487 Mcf per day, with an average sales price of $2.42
per Mcf during the 1991 quarter, as compared to $2.92 per Mcf in the 1990
quarter. The Company's natural gas production in the Bob West Field increased
during the 1991 quarter; however, revenues from this production were
substantially offset by increased depreciation and depletion, insurance costs
and legal fees associated with these operations.

The oil field supply and distribution segment's operating loss of $1.2
million in the 1991 quarter was a decrease of $2.8 million from the $1.6 million
operating profit recorded in the 1990 quarter. This decrease in operating
results was primarily attributable to lower margins on refined product sales
caused by the decline in drilling rig activity in the United States. The 1990
quarter included the effect of increased demand experienced during the Persian
Gulf conflict.

General and administrative expenses of $2.8 million for the 1991 quarter
decreased by $1.2 million from the 1990 quarter, primarily due to an insurance
reimbursement during the 1991 quarter for certain costs incurred in defense of
litigation in prior years. Depreciation, depletion and amortization expense of
$4.2 million in the 1991 quarter increased by $1.2 million from the 1990
quarter, due mainly to exploration and production activities in the Bob West
Field. The income tax provision of $3.0 million in the 1991 quarter decreased by
$3.8 million from the 1990 quarter, primarily due to lower foreign taxes
resulting from reduced revenues from the Company's operations in Indonesia.

CAPITAL RESOURCES AND LIQUIDITY

During the first quarter of 1994, the Company continued to achieve
significant improvement in profitability, resulting primarily from (i) strong
gross margins on the sales of refined products, (ii) the Company's recently
implemented market-driven operating strategy to better align Refinery production
with refined product demand in the Alaskan market and minimize the output of
lower value residual fuel oil and (iii) higher natural gas production resulting
from continuing success in developing the Bob West Field. The Company's
liquidity and capital resources have been significantly enhanced as a result of
the Company's improvement in profitability, together with the completion of the
Recapitalization in February 1994 and the finalization of the Company's
Revolving Credit Facility during April 1994.

Significant components of the Recapitalization were as follows:

- Subordinated Debentures in the principal amount of $44.1 million were
tendered in exchange for a like principal amount of new Exchange Notes,
which satisfied the 1994 sinking fund requirements and, except for $.9
million, will satisfy sinking fund requirements for the Subordinated
Debentures through 1997. The Exchange Notes bear interest at 13% per
annum, are scheduled to mature on December 1, 2000 and have no sinking
fund requirements.

- The 1,319,563 outstanding shares of $2.16 Preferred Stock, together with
accrued and unpaid dividends of $9.5 million at February 9, 1994, were
reclassified into 6,465,859 shares of Common Stock. The Company also
agreed to issue up to 131,956 shares of Common Stock on behalf of the
holders of $2.16 Preferred Stock and to pay $500,000 for certain of their
legal fees and expenses in connection with the settlement of litigation
related to the reclassification. The court awarded $500,000 and 73,913
shares of Common Stock for such legal fees and expenses, with the
remainder of the 131,956 shares to be issued to the former holders of
$2.16 Preferred Stock upon the court's orders becoming final and
nonappealable. A portion of the shares to be issued to the former holders
of $2.16 Preferred Stock may be awarded to counsel retained by a party
objecting to the settlement. See "Legal Proceedings -- Recapitalization
Matters."

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- The Company and MetLife Louisiana, the holder of all the Company's
outstanding $2.20 Preferred Stock, entered into an agreement (the
"Amended MetLife Memorandum") with regard to such preferred shares
pursuant to which MetLife Louisiana agreed to waive all existing
mandatory redemption requirements, to consider all accrued and unpaid
dividends thereon through February 9, 1994 (aggregating approximately
$21.2 million) 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 certain other rights of the $2.20 Preferred Stock and to grant
to the Company the MetLife Louisiana Option (pursuant to which the
Company has the option to purchase, until February 9, 1997, all shares of
the $2.20 Preferred Stock and Common Stock held by MetLife Louisiana),
all in consideration for, among other things, the issuance by the Company
to MetLife Louisiana of 1,900,075 shares of Common Stock. Such additional
shares are also subject to the MetLife Louisiana Option. Until June 30,
1994, the option price is approximately $53.0 million, after giving
effect to a reduction in the option price for the cash dividend paid on
the $2.20 Preferred Stock in May 1994. The unexercised option price will
be increased by 3% on the last day of each calendar quarter until
December 31, 1995, and by 3 1/2% on the last day of each quarter
thereafter, and will be reduced by cash dividends paid on the $2.20
Preferred Stock after February 9, 1994. The Company will be required to
pay dividends (in either cash or Common Stock) when due on the $2.20
Preferred Stock in order for the MetLife Louisiana Option to remain
outstanding. In addition, the MetLife Louisiana Option is subject to
certain minimum exercise requirements to remain outstanding beyond one
year and two years; however, even if the net proceeds of the Offering are
not sufficient to exercise the MetLife Louisiana Option in full, such net
proceeds will be sufficient to satisfy all of the minimum exercise
requirements.

For further information regarding the pro forma effects of the
Recapitalization, see "Capitalization," "Pro Forma Condensed Consolidated
Financial Data" and Note B of Notes to Consolidated Financial Statements.

Proposed Pipeline Rate Increase

The Company transports its crude oil and a substantial portion of its
refined products utilizing KPL's pipeline and marine terminal facilities in
Kenai, Alaska. In March 1994, KPL filed a revised tariff with the FERC for dock
loading services, which 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. Following the FERC's rejection
of KPL's tariff and the commencement of negotiations for the purchase by the
Company of the dock facilities, KPL filed a temporary tariff that would increase
the Company's annual cost by approximately $1.5 million. The negotiations
between the Company and KPL are continuing. The Company believes that the
ultimate resolution of this matter will not have a material adverse effect upon
the financial condition or results of operations of the Company.

Credit Arrangements

During April 1994, the Company entered into a new three-year $125 million
corporate revolving credit facility ("Revolving Credit Facility") with a
consortium of ten banks. The Revolving Credit Facility, which is subject to a
borrowing base, provides for (i) the issuance of letters of credit up to the
full amount of the borrowing base as calculated, but not to exceed $125 million
and (ii) cash borrowings up to the amount of the borrowing base attributable to
domestic oil and gas reserves. Outstanding obligations under the Revolving
Credit Facility are secured by liens on substantially all of the Company's trade
accounts receivable and product inventory and mortgages on the Refinery and the
Company's South Texas natural gas reserves.

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Revolving Credit Facility will reduce the availability of letters of credit on a
dollar-for-dollar basis; however, letter of credit issuances will not reduce
cash borrowing availability unless the aggregate dollar amount of outstanding
letters of credit exceeds the sum of the accounts receivable and inventory
components of the borrowing base. The terms of the Revolving Credit Facility
include standard and customary restrictions and covenants. For information
concerning such restrictions and covenants, see Note I of Notes to Consolidated
Financial Statements.

The Revolving Credit Facility replaced certain interim financing
arrangements that the Company had been using since the termination of its prior
letter of credit facility in October 1993. The interim financing arrangements
that were cancelled in conjunction with the completion of the new Revolving
Credit Facility included a $30 million reducing revolving credit facility and a
waiver and substitution of collateral agreement with the State. In addition, the
completion of the Revolving Credit Facility provides the Company significant
flexibility in the investment of excess cash balances, as the Company is no
longer required to maintain minimum cash balances or to cash secure letters of
credit.

During May 1994, the National Bank of Alaska and the Alaska Industrial
Development & Export Authority agreed to provide a loan to the Company of up to
$15 million of the $24 million cost of the vacuum unit for the Refinery (the
"Vacuum Unit Loan"). The Vacuum Unit Loan will mature on January 1, 2002, will
require 28 equal quarterly payments beginning April 1, 1995 and will bear
interest at the unsecured 90-day commercial paper rate, adjusted quarterly,
plus 2.6% per annum for two-thirds of the amount borrowed and at the National
Bank of Alaska floating prime rate plus 1/4 of 1% per annum for the remainder.
The Vacuum Unit Loan is secured by a first lien on the Refinery.

Debt and Other Obligations

The Company's funded debt obligations as of December 31, 1993 included
approximately $108.8 million principal amount of Subordinated Debentures, which
bear interest at 12 3/4% per annum and require sinking fund payments sufficient
to annually retire $11.25 million principal amount of Subordinated Debentures.
As part of the Recapitalization, $44.1 million principal amount of Subordinated
Debentures was tendered in exchange for a like principal amount of Exchange
Notes. Such exchange satisfied the 1994 sinking fund requirement and, except for
$.9 million, will satisfy sinking fund requirements for the Subordinated
Debentures through 1997. The indenture governing the Subordinated Debentures
contains certain covenants, including a restriction which prevents the current
payment of cash dividends on 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% per annum, mature on December 1, 2000 and have no
sinking fund requirements. The limitation on dividend payments included in the
indenture governing the Exchange Notes is less restrictive than the limitation
imposed by the Subordinated Debentures. For further information on restrictions
on dividends, see Note I of Notes to Consolidated Financial Statements. The
Subordinated Debentures and Exchange Notes are redeemable at the option of the
Company at 100% of principal amount, plus accrued interest. The Company is
monitoring the feasibility of a debt offering that would reduce fixed charges by
refinancing all or a substantial portion of such indebtedness at lower interest
rates. The Company is not undertaking such a debt offering at this time because
it considers the current interest rate environment unattractive; however, if
interest rate levels decline, the Company may decide to proceed with such an
offering. There can be no assurance whether or when such an offering would
occur.

If the Subordinated Debentures and the Exchange Notes are redeemed prior to
their respective maturities, the Company will be required to recognize a noncash
extraordinary charge to earnings equal to the portion of the original issue
discount on the Subordinated Debentures and the debt issuance costs of both the
Subordinated Debentures and the Exchange Notes that remains unamortized at the
date of redemption (aggregating approximately $8.5 million at March 31, 1994).

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 through December 2001
based on a per barrel charge on the volume of feedstock processed at the
Refinery that is currently 16 cents and increases to 33 cents. In 1993, the
Company's variable payments to the State

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totaled $2.6 million. In January 2002, the Company is obligated to pay the State
$60 million; provided, however, that such payment may be deferred indefinitely
by continuing the variable monthly payments to the State beginning at 34 cents
per barrel for 2002 and increasing one cent per barrel annually thereafter.

Capital Expenditures

The Company has under consideration total capital expenditures ranging from
approximately $65 million to $80 million in 1994. Proposed capital expenditures
for 1994 include 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
proposed capital expenditures for 1994 include $32 million for the refining and
marketing operations, of which $24 million is associated with the installation
of a vacuum unit at the Refinery to allow the Company to further upgrade
residual fuel oil production into higher-valued products. The Revolving Credit
Facility and the Vacuum Unit Loan, along with other available funds, are
expected to provide sufficient capital to meet the Company's capital expenditure
requirements during 1994.

Cash Flows From Operating, Investing and Financing Activities

During the three months ended March 31, 1994, cash and cash equivalents
increased by $12.8 million and short-term investments decreased by $6.0 million.
At March 31, 1994, the Company's cash totaled $49.4 million, which included
$26.6 million as collateral for outstanding letters of credit. Subsequent to
March 31, 1994, these interim cash-backed letter of credit arrangements were
replaced by the Revolving Credit Facility (see Note I of Notes to Consolidated
Financial Statements). Working capital amounted to $110.3 million at March 31,
1994. Net cash from operating activities of $30.3 million during the three
months ended March 31, 1994, compared to $14.4 million for the 1993 quarter, was
primarily due to net earnings adjusted for certain noncash charges and reduced
working capital requirements. The 1993 quarter included a payment of $10.8
million to the State in connection with the settlement of a contractual dispute.
Net cash used in investing activities of $10.2 million during the three months
ended March 31, 1994 included capital expenditures of $18.5 million, partially
offset by cash proceeds of $2.0 million from the sale of the Company's Valdez,
Alaska terminal and the sale of $6.0 million in short-term investments. Capital
expenditures for the three months ended March 31, 1994 included $11.7 million
for exploration and production activities in the Bob West Field, where an
additional six natural gas development wells were completed during this period.
The refining and marketing segment's capital expenditures totaled $6.1 million
for the three months ended March 31, 1994, primarily for initial installation
costs for the vacuum unit and completion of the deisobutanizer unit. Net cash
used in financing activities of $7.3 million during the three months ended March
31, 1994 included the repayment of net borrowings of $5.0 million under the
reducing revolving credit facility, which was replaced by the Revolving Credit
Facility (see Note I of Notes to Consolidated Financial Statements).

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 noncash 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 reducing revolving credit facility, which has since
been replaced. The Company did not pay dividends on preferred stocks in 1993,

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which resulted in cumulative dividend arrearages of $28.7 million at December
31, 1993. Such dividend arrearages have since been satisfied by consummation of
the Recapitalization. As a result of the Recapitalization, annual preferred
stock dividend requirements have been reduced to $6.3 million; such dividend
requirements will be eliminated if the MetLife Louisiana Option is exercised in
full.

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
noncash 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 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.

For further information concerning actions recently taken by Tennessee Gas
under the Tennessee Gas Contract and the potential effect thereof on the
Company's income and cash flows from operating activities, see "-- Results of
Operations -- Exploration and Production -- Three Months Ended March 31, 1994
Compared to Three Months Ended March 31, 1993."

LITIGATION

The Company is subject to certain commitments and contingencies, including
a contingency relating to a natural gas sales contract dispute with Tennessee
Gas. The Company is selling a portion of the gas from its Bob West Field to
Tennessee Gas under a Gas Purchase and Sales Agreement which provides that the
price of gas shall be the maximum price as calculated in accordance with Section
102(b)(2) (the "Contract Price") of the Natural Gas Policy Act of 1978 (the
"NGPA").

Tennessee Gas filed suit against the Company alleging that the gas contract
is not applicable to the Company's properties and that the gas sales price
should be the price calculated under the provisions of Section 101 of the NGPA
rather than the Contract Price. During March 1994, the Contract Price was $7.84
per Mcf, the Section 101 price was $4.58 per Mcf and the average spot market
price was $2.09 per Mcf. Tennessee Gas also claimed that the contract should be
considered an "output contract" under Section 2.306 of the Texas Business and
Commerce Code and that the increases in volumes tendered under the contract
exceeded those allowable for an output contract. The Company continues to
receive payment from Tennessee Gas based on the Contract Price for all volumes
that are subject to the contract under the Company's interpretation.

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Appeals remanded the case to the trial court based on its determination (i) that
the Tennessee Gas Contract was an output contract and (ii) that a fact issue
existed as to whether the increases in the volumes of gas tendered to Tennessee
Gas under the contract were made in bad faith or were unreasonably
disproportionate to prior tenders. The Company is seeking review of the
appellate court ruling on the output contract issue in the Supreme Court of
Texas. Tennessee Gas is seeking review of the appellate court ruling denying the
remaining Tennessee Gas claims in the Supreme Court of Texas.

Although the outcome of any litigation is uncertain, management, based upon
advice from outside legal counsel, is confident that the decision of the trial
and appellate courts will ultimately be upheld as to the validity of the
Tennessee Gas Contract and the Contract Price. Therefore, if the Supreme Court
of Texas does not grant the Company's petition for writ of error and affirms the
appellate court ruling, the Company believes that the only issue for trial
should be whether the increases in the volumes of gas tendered to Tennessee Gas
from the Company's properties were made in bad faith or were unreasonably
disproportionate. The appellate court decision was the first reported decision
in Texas holding that a take-or-pay contract was an output contract. As a
result, it is not clear what standard the trial court would be required to apply
in determining whether the increases were in bad faith or unreasonably
disproportionate. The appellate court acknowledged in its opinion that the
standards used in evaluating other kinds of output contracts would not be
appropriate in this context. The Company believes that the appropriate standard
would be whether the development of the field was undertaken in a manner that a
prudent operator would have undertaken in the absence of an above-market sales
price. Under that standard, 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 March 31, 1994, under the
Tennessee Gas Contract based on the Contract Price, which net revenues
aggregated $21.1 million more than the Section 101 prices and $38.9 million in
excess of the spot market prices. If Tennessee Gas ultimately prevails in this
litigation, the Company could be required to return to Tennessee Gas the
difference between the spot market price for gas and the Contract Price, plus
interest, if awarded by the court. In addition, the present value of estimated
future net revenues on a pre-tax basis from the Company's proved domestic
reserves has been calculated based in part on the price being paid by Tennessee
Gas at the date of determination. At March 31, 1994, such present value was
$171.0 million. If calculated using March 31, 1994 spot market prices instead of
the Contract Price, such present value would have been $92.0 million. An adverse
judgment in this case could have a material adverse effect on the Company.

The Company received a letter dated May 12, 1994, from Tennessee Gas
requesting that the Company agree to allow Tennessee Gas to escrow with itself
the difference between the Contract Price and the spot market price for all of
the Company's gas taken from time to time by Tennessee Gas from wells covered by
the Tennessee Gas Contract. In addition, to the extent the Company believed that
Tennessee Gas was not meeting its take-or-pay obligations, Tennessee Gas would
also deposit the alleged take-or-pay liability into escrow. The letter from
Tennessee Gas states that if the Company does not agree to the escrow, Tennessee
Gas will consider all its remedies available under statutory and common law. The
Company has rejected the proposed escrow and believes that Tennessee Gas has no
legal basis to withhold payment and that if the payments are withheld, the
courts will ultimately require Tennessee Gas to make payments to the Company.

In a separate letter to the Company, Tennessee Gas asserted that the gas
delivered under the Tennessee Gas Contract did not meet contractual
specifications and indicated that it intended to refuse future deliveries of gas
unless the deficiency was corrected within 30 days. The Company believes that
its future deliveries of gas will meet contractual specifications. See "Legal
Proceedings -- Tennessee Gas Contract" and Notes K and P of Notes to
Consolidated Financial Statements.

ENVIRONMENTAL

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chemical substances at various sites or install additional controls or other
modifications or changes in use for certain emission sources. The Company is
currently involved in remedial responses and has incurred cleanup expenditures
associated with environmental matters at a number of sites, including certain of
its own properties. Although the level of future expenditures for environmental
purposes, including cleanup obligations, is impossible to determine with any
degree of probability, it is management's opinion that, based on current
knowledge and the extent of such expenditures to date, the ultimate aggregate
cost of environmental remediation will not have a material adverse effect on the
Company's financial condition. At March 31, 1994, the Company's accrual for
environmental liabilities was $6.0 million. See "Legal Proceedings."

IMPACT OF CHANGING PRICES

The Company's operating results and cash flows are sensitive to the
volatile changes in energy prices. Major shifts in the cost of crude oil and the
price of refined products can result in a change in gross margin from the
refining and marketing operations, as prices received for refined products may
or may not keep pace with changes in crude costs. These energy prices, together
with volume levels, also determine the carrying value of crude oil and refined
product inventory.

Likewise, major changes in natural gas prices impact revenues and the
present value of estimated future net revenues from the Company's exploration
and production operations. The carrying value of oil and gas assets may also be
subject to noncash write-downs based on changes in natural gas prices and other
determining factors. See "Investment Considerations -- Uncertainty in Estimating
Oil and Gas Reserves."

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BUSINESS

GENERAL

The Company is an independent energy company engaged in refining and
marketing, primarily in Alaska, and in the exploration for and production of
natural gas and crude oil in South Texas and Bolivia. The Company also markets
lubricants, fuels and specialty petroleum products on a wholesale basis. For
financial information relating to industry segments, see "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
Note N of Notes to Consolidated Financial Statements.

REFINING AND MARKETING

Refining and Marketing Activities

Industry Overview/Competition. The refining and marketing businesses are
highly competitive, with price being the principal factor in competition. In the
refining market, the Company competes primarily with three other refineries in
Alaska and, to a lesser extent, refineries on the West Coast. Given the
Refinery's proximity to the Alaskan market, the Company believes it enjoys a
cost advantage in that market versus refineries on the West Coast. However,
there is no assurance that the Company's cost advantage can be maintained. The
Company's refining competition in Alaska consists of a refinery situated near
Fairbanks owned by MAPCO, Inc. and two refineries situated near Valdez and
Fairbanks, respectively, owned by Petro Star Inc. The Company estimates that
such other refineries have a combined capacity to process approximately 156,000
BPD of crude oil. ANS crude oil is the only feedstock used in these competing
refineries. After processing the crude oil and removing the lighter-end
products, which represent approximately 30% of each barrel processed, these
refiners are permitted, because of their direct connection to the TAPS, to
return the remainder of the residual products back into the pipeline system as
"return oil" in consideration for a fee, thereby eliminating their need to
market residual products. The Refinery is not directly connected to the TAPS,
and the Company, therefore, cannot return its residual products to the TAPS. In
general, the competing refineries in Alaska do not have the same downstream
capabilities that the Company currently possesses. Management of the Company
estimates that the Company has the capacity to produce approximately twice the
volume of light products per barrel of ANS crude oil that any of the competing
refineries is currently able to produce.

The Company's marketing business in Alaska is segmented by product line.
The Company believes it is the largest producer and distributor of gasoline in
Alaska, with the largest network of branded and unbranded dealers and jobbers.
The Company is the principal supplier for two major oil companies through
product exchange agreements, whereby gasoline in Alaska is provided in exchange
for gasoline delivered to the Company on the West Coast. Jet fuel sales are
concentrated in Anchorage, where the Company is one of two principal suppliers
to, and the only supplier with a direct pipeline into, the Anchorage
International Airport, which is a major hub for air cargo traffic to the Far
East. Diesel fuel is sold primarily on a wholesale basis.

The Company's West Coast marketing business is primarily a distribution
business selling to independent dealers and jobbers outside major urban areas.
The Company competes against independent marketing companies and, to a lesser
extent, integrated oil companies when engaging in these marketing operations.

The Kenai Refinery. The Company's Refinery is strategically located in
Kenai, Alaska, approximately 90 miles southwest of Anchorage, Alaska, where it
has access to multiple sources of crude oil. The original crude oil distillation
unit was built by Tesoro in 1969 with a capacity of 17,500 BPD. The crude unit
was originally designed to process Cook Inlet crude oil, as the Alaskan North
Slope had not yet been developed. During the 1970s and 1980s, the crude unit was
updated and expanded to its current capacity of 72,000 BPD. These expansions
enabled the Company to process 100% ANS crude oil. In addition, the Company has,
over time, added numerous downstream processing units, including a hydrocracker,
a deisobutanizer ("DIB") unit, a reformer, a Partial Recycle Isomerization
Process ("PRIP") unit, and during 1994 will add automated process controls. The
Company has received permits and has begun construction on a new vacuum unit,
which is expected to begin operating in January 1995.

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Crude Oil Supply. The Refinery is designed to process crude oil with up to
1.0% sulphur content. As such, the Refinery can process Cook Inlet, ANS and
certain foreign crude oils.

ANS Crude Oil. ANS crude oil is a heavy crude oil which contains an
average of 1.0% sulphur. In 1993, approximately 72% (35,600 BPD) of the
Refinery's feedstock was ANS crude oil, of which approximately 24,300 BPD
was purchased under a royalty crude oil purchase contract with the State,
which is scheduled to expire at the end of 1994. The Company and the State
have agreed in principle to extend the contract through 1995. During 1994,
this contract requires the Company to purchase approximately 27,500 BPD of
ANS crude oil. The agreement in principle between the Company and the State
would require the Company to purchase approximately 40,000 BPD during 1995.
The Company does not currently anticipate increasing the percentage of ANS
crude oil utilized as feedstock at the Refinery. Under its agreement in
principle with the State, the Company has the right to sell or to exchange
up to 20% of the ANS crude oil to be purchased from the State during 1995.
The Company's additional ANS crude feedstock supply is currently purchased
pursuant to a short-term contract.

Cook Inlet Crude Oil. Cook Inlet crude oil, a lighter crude oil that
contains an average of .1% sulphur, accounted for approximately 22% of the
Refinery's feedstock supply in 1993. The Company obtains Cook Inlet crude
from several producers on the Kenai Peninsula under short-term contracts.

Other Supply. In 1993, the Refinery obtained approximately 6% of its
feedstock supply from other sources. This feedstock supply was primarily
heavy atmospheric gas oil ("HAGO") and was purchased from a local
competitor's refineries and from a West Coast refinery under short-term
contracts. HAGO is a refinery byproduct which generates various light
refined products with no residual fuel oil.

Transportation of Crude Oil Supply. The ANS crude oil is transported by the
TAPS from the North Slope to Valdez, Alaska. From Valdez, the Company charters
an American flag vessel, the Overseas Washington, under an agreement expiring in
October 1994, to transport ANS crude oil from the TAPS terminal at Valdez,
Alaska to the Refinery. The Company is currently negotiating for a replacement
vessel and does not anticipate any interruptions in its crude oil supply as a
result of the expiration of the charter. A central gathering system collects
Cook Inlet crude oil for pipeline transport to the Refinery.

Alaskan Refinery Products and Marketing. The Company is a major supplier of
petroleum products within Alaska, the primary marketplace for the Company's
refined products. In 1993, Refinery production was approximately 25% jet fuel,
25% gasoline, 14% other distillates, including diesel fuel, and 36% residual
fuel oil. The Company has implemented a market-driven strategy which has
resulted in significant changes in the operation of the Refinery, including: (i)
a reduction in Refinery throughput from approximately 61,000 BPD in 1992 to
approximately 50,000 BPD in 1993 to better align Refinery production with
refined product demand in the Alaskan market and (ii) a reduction in the
percentage of Refinery feedstocks represented by heavier ANS crude oil, which
resulted in the reduction in the percentage of residual fuel oil produced. In
addition, the Company focused on the marketing of residual fuel oil primarily as
a feedstock for West Coast refineries. Changes in the Company's sales prices to
such refineries can be linked to changes in crude oil prices, unlike the more
volatile Far Eastern bunker fuel markets where the Company had primarily
marketed its residual fuel oil in the past.

34
<PAGE> 36

The following table sets forth the Refinery throughput, the sales volume of
the Company's various products and the composition and pricing of
Company-produced versus purchased product for the fiscal years ended September
30, 1991, December 31, 1992 and December 31, 1993 and the three-month periods
ended March 31, 1993 and March 31, 1994.

YEAR YEAR ENDED THREE MONTHS
ENDED DECEMBER 31, ENDED MARCH 31,
SEPTEMBER 30, ------------------- -------------------
1991 1992 1993 1993 1994
------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
Refinery throughput (BPD)................ 68,192 61,425 49,753 52,911 45,320
Sales of Refinery production:
Sales (per Bbl)........................ $ 24.40 $ 21.30 $ 21.91 $ 20.98 $ 18.46
Margin (per Bbl)....................... $ 2.77 $ 1.18 $ 4.19 $ 2.94 $ 4.24
Volume (average BPD)................... 66,837 62,218 49,425 57,332 46,236
Sales of products purchased for resale:
Sales (per Bbl)........................ $ 31.48 $ 27.58 $ 27.50 $ 26.43 $ 24.12
Margin (per Bbl)....................... $ .37 $ 1.09 $ 1.35 $ .88 $ 2.62
Volume (average BPD)................... 23,318 25,222 19,340 22,643 19,582
Sales volumes (average BPD):
Gasoline............................... 25,883 25,196 22,466 25,907 22,570
Jet fuel............................... 15,055 19,060 11,305 12,618 10,678
Diesel fuel and other distillates...... 20,488 19,253 18,049 20,584 16,124
Residual fuel oil...................... 28,729 23,931 16,945 20,866 16,446
------- ------- ------- ------- -------
Total.......................... 90,155 87,440 68,765 79,975 65,818
------- ------- ------- ------- -------
------- ------- ------- ------- -------
Sales price (per Bbl):
Gasoline............................... $ 30.69 $ 28.89 $ 27.64 $ 25.51 $ 23.92
Jet fuel............................... 35.15 27.76 28.10 28.70 25.43
Diesel fuel and other distillates...... 29.78 25.78 26.95 26.19 23.53
Residual fuel oil...................... 15.15 11.60 11.19 11.46 8.22
</TABLE>

Gasoline. In 1993, the Company distributed approximately 89% of the
gasoline produced at the Refinery to end users in Alaska, by retail sales
through 33 of its 7-Eleven convenience stores and two other locations, by
wholesale sales through 68 branded and 25 unbranded dealers and jobbers and by
deliveries to two major oil companies for their retail operations in Alaska in
exchange for gasoline delivered to the Company in the West Coast market. During
1993, the production of gasoline by all refineries in Alaska, including the
Company's, exceeded the market demand. As a result, the remaining approximately
11% of the Refinery's 1993 gasoline production was transported to West Coast
markets. These export sales are generally made during the winter months when the
demand for gasoline in Alaska is lowest.

Jet Fuel. The Company is a major supplier of commercial jet fuel into the
Alaskan marketplace, with all of its production being marketed in Alaska to
passenger and cargo airlines. The demand for jet fuel in Alaska currently
exceeds the production of the refiners in Alaska, and several marketers,
including the Company, import jet fuel into Alaska to meet excess demand.

Diesel Fuel and Other Distillates. Substantially all of the Company's
diesel fuel and other distillate production is sold on a wholesale basis in
Alaska and resold primarily for marine and industrial purposes. Approximately 5%
of the Company's diesel fuel production in 1993 was sold for on-highway use.
Generally, the production of diesel fuel in Alaska is in balance with demand;
however, because of the high variability of the demand, there are occasions when
diesel fuel is imported into or exported from Alaska.

Residual Fuel Oil. Due to the Refinery's configuration, a product of the
Company's refining process is residual fuel oil. Since there is no significant
demand for residual fuel oil in Alaska, substantially all of the Company's
residual fuel oil production is exported from Alaska. During 1993, pursuant to
its new marketing strategy, the Company commenced selling and transporting a
substantial volume of its residual fuel oil to the

35
<PAGE> 37

West Coast, where it is generally used as a refinery feedstock. Prior to 1993,
the Company's primary market for the residual fuel oil was the Far Eastern
bunker fuel markets. Marketing the residual fuel oil as a feedstock has, to a
significant degree, reduced the Company's exposure to the pricing volatility
that exists in the Far Eastern bunker fuel markets. In addition, the Refinery's
reduced throughput and reduction of ANS crude oil as a percentage of total
feedstock has caused residual fuel oil output to decrease from approximately
23,400 BPD in 1992 to approximately 17,600 BPD during 1993. The installation of
the vacuum unit is expected to further reduce the production of residual fuel
oil significantly and improve the Company's overall product mix.

West Coast Marketing. In support of the Refinery, the Company conducts
domestic wholesale marketing operations, primarily in California, Oregon and
Washington. During 1993, these operations sold approximately 27,800 BPD of
refined products, of which approximately 30% was received from major oil
companies in exchange for products from the Refinery, approximately 5% was
received directly from the 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.

Refined Product Transportation. The Company operates a ten-inch diameter
common carrier petroleum pipeline from the Refinery to its terminal in
Anchorage. The pipeline allows the Company to transport light products to the
terminal throughout the year, regardless of weather conditions. During 1993, the
pipeline transported an average of approximately 22,300 BPD of petroleum
products, all of which were transported for the Company. The pipeline has a
capacity of 40,000 BPD. From the Company's Anchorage terminal, light petroleum
products are distributed by contracted jobbers to 33 of the Company's 7-Eleven
stores and two other locations, 68 branded and 25 unbranded dealers and two
major oil companies. The Company also has a charter for an American flag vessel,
the Baltimore Trader, under an 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
Refinery. With the installation of the vacuum unit at the Refinery and the
resultant further decrease in residual fuel oil production, the Company
anticipates that the vessel replacing the Overseas Washington will also be able
to meet the Company's residual fuel oil transportation needs after the Baltimore
Trader charter expires. See "--Transportation of Crude Oil Supply." 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.

For further information on transportation in Alaska, see "Government
Regulation and Legislation -- Environmental Controls."

Capital Expenditure Program. The Company has under consideration total
capital expenditures for the refining and marketing operations of $32 million in
1994, of which $24 million is associated with the installation of a vacuum unit
at the Refinery. Under the Vacuum Unit Loan, the Company may borrow up to $15
million of the $24 million cost of the vacuum unit. See "Management's Discussion
and Analysis -- Capital Resources and Liquidity." Approximately $5 million is
planned to be expended in 1994 on 7-Eleven store upgrades, the opening of new
7-Eleven stores and continued upgrading of underground storage tanks in the
Alaskan retail operations. The remainder of the refining and marketing capital
expenditures is primarily related to normal Refinery maintenance.

Refinery Units. The following is a flow chart of the Refinery's major
process units and a summary description of the Refinery's process units and
their respective functions.

36
<PAGE> 38

[SCHEMATIC HERE]

(DESCRIPTION OF SCHEMATIC)

The schematic appearing on this page is a flow chart illustrating the
refining process at the Company's Refinery.

37
<PAGE> 39

Crude Unit. The crude unit was built in 1969 and has been modified twice,
most recently during 1983-1985. After expansion and modification, the Refinery
has a rated capacity of 72,000 BPD. The hydrocarbon compounds that make up crude
oil separate or "fractionate" when subjected to high temperatures. The crude
unit fractionates crude oil into finished products (jet fuel and diesel fuel)
and feedstock for further processing (liquefied petroleum gas ("LPG") and off
gas, light straight run, heavy naphtha, atmospheric gas oil and atmospheric
residuum). The LPG and off gas are further processed in the amine and LPG units.
The light straight run is pumped to the PRIP unit for further processing. The
heavy naphtha is feedstock for the reformer. The atmospheric gas oil is further
processed in the hydrocracker. The remaining atmospheric residuum is currently
sold as feedstock to complex refineries on the West Coast.

Vacuum Unit. A 16,500 BPD vacuum unit is currently being installed and is
scheduled to commence operations in January 1995. Residual fuel oil is used for
feedstock for the vacuum unit. In the vacuum unit, the residual fuel oil is
fractionated into three different products: (i) Light Vacuum Gas Oil ("LVGO"),
(ii) Heavy Vacuum Gas Oil ("HVGO") and (iii) Vacuum Tower Bottom ("VTB").

The LVGO is further processed in the hydrocracker and converted into
gasoline and jet fuel. HVGO is sold to refineries on the West Coast for
catalytic hydrocracker feedstock. VTB's are blended with light cycle oil to
produce bunker fuel, which is sold primarily on the West Coast.

Deisobutanizer Unit. A 5,000 BPD DIB unit came on stream in December 1993.
With the addition of the DIB unit, the Refinery is able to produce high purity
(95%) normal butane for gasoline blending and to also increase the production of
propane (150 BPD). Tesoro previously blended a mixture of isobutane and normal
butane into gasoline. The isobutane/normal butane mixture has a higher vapor
pressure than normal butane. With the production of normal butane from the DIB
unit, Tesoro is able to increase the amount of normal butane used in gasoline
blending, which results in increased gasoline production of approximately 600
BPD.

Hydrocracker Unit. The 9,000 BPD hydrocracker unit was installed in 1981
and upgraded during the Refinery's modification in 1983-1985. The hydrocracker
unit processes atmospheric gas oil from the crude unit, combined with hydrogen
from the reformer and the hydrogen plant, into jet fuel and feedstock (heavy
hydrocrackate, light hydrocrackate and LPG and off gas).

Reformer. The reformer, which has a 12,000 BPD capacity, was constructed in
1975 and upgraded in 1980. The unit is fed naphtha from the crude unit and heavy
hydrocrackate from the hydrocracker unit. These are converted into high octane
reformate for gasoline blending. Other products from the reformer are hydrogen,
which is used in the hydrocracker unit, LPG, which is feedstock for the LPG
unit, and off gas, which is used as fuel for the process heaters at the
Refinery.

Partial Recycle Isomerization Process Unit. The light straight run gasoline
from the crude unit and the light hydrocrackate from the hydrocracker unit are
the feedstocks for this unit. The PRIP unit produces a stream of isomerate which
is used to increase the octane of gasoline. The PRIP unit allows Tesoro to make
100% unleaded and super unleaded gasoline and at the same time reduce the
percentage of aromatic hydrocarbons in the finished gasoline product. This unit
was installed in 1986 and has a capacity of 4,000 BPD.

Amine Unit. The Company's amine unit was constructed in 1981 and reworked
in 1985. It has a capacity of 2,500 BPD. The amine unit removes hydrogen sulfide
from LPGs and off gases produced in other units. The off gases are used as fuel
for the process heaters and the LPG is feedstock for the LPG unit.

Sulphur Plant. The sulphur plant processes the hydrogen sulfide from the
amine unit into sulphur.

LPG Unit. The 2,400 BPD LPG unit was built in 1975. The unit produces
finished product (commercial grade propane) and feedstock (a butane-plus product
that is used for gasoline blending and as refinery fuel).

Operations. Each unit in the Refinery requires regular maintenance and
repair (referred to as "turnarounds") during which it is not in operation.
Turnaround cycles vary for different units and, in general, the Refinery
managers plan product inventories and unit maintenance to permit some operations
to continue even when certain units are inactive. Maintenance turnarounds
involve a number of independent contractors and engineers, as well as the
Refinery's own personnel. Turnarounds are effected on a continuous 24-hour basis
in order to minimize the unproductive time of the units involved. Tesoro
expenses current maintenance charges

38
<PAGE> 40

as incurred and estimated amounts related to the future expenses of periodic
process unit turnarounds. At the time such periodic unit turnarounds are
performed, the actual costs incurred are charged against the previously
established liabilities. To the extent actual costs exceed previously
established liabilities, a turnaround may result in reduced income. The Company
completed a turnaround of the crude unit in May 1992 and anticipates another
turnaround in September 1994. The Company is planning a turnaround of the
hydrocracker in 1996, a turnaround of the reformer in 1994 and a turnaround of
the PRIP unit in 1995.

EXPLORATION AND PRODUCTION

South Texas

Since 1989, Tesoro's exploration staff has generated numerous exploration
prospects in the Wilcox Trend of South Texas. The Wilcox Trend extends from
Northern Mexico through South Texas into Western Louisiana. Multiple pay sands
exist within the Wilcox Trend, where extensive faulting has trapped hydrocarbons
in numerous producing zones. The Company's South Texas exploration program has
been very successful as a result of the discovery of the Bob West Field, with
the Company having achieved an average finding cost of $.43 per Mcf of gas
during the period beginning October 1, 1990 and ending December 31, 1993. In
April 1992, Tesoro sold its interest in all producing and undeveloped properties
in South Texas outside the Bob West Field in order to concentrate its resources
on the Bob West Field.

The Bob West Field is located in the southern part of the Wilcox Trend in
Starr and Zapata Counties. The field represents a major gas discovery with
estimated ultimately recoverable gross proved reserves of 334 Bcf of natural
gas, of which approximately 56 Bcf had been produced through March 31, 1994.
Tesoro owns an average 50% revenue interest in approximately two-thirds of the
Bob West Field and an average 28% revenue interest in the remaining one-third.
There are 23 known productive sands in the Bob West Field, 17 of which are now
producing. The producing sands are found at depths of approximately 8,000 to
16,000 feet. The Bob West Field encompasses approximately 4,000 acres, and the
thickness of individual productive zones ranges from 20 feet to as much as 220
feet. Continued successful development of the Bob West Field has resulted in an
increase in Tesoro's net proved domestic natural gas reserves from 74 Bcf at
year end 1992 to 120 Bcf at year end 1993, which represents an increase of
approximately 63%. During December 1993, the Company's net production from the
Bob West Field averaged 58 MMcf of gas per day, representing a 222% increase
over the December 1992 production level of 18 MMcf of gas per day. Fifteen
development wells were drilled and completed in the Bob West Field during 1993,
at a cost to the Company of approximately $21.4 million. Through year end 1993,
the Company has successfully completed a total of 25 wells within the Bob West
Field, with no dry holes encountered in the process. The Company's development
program for 1994 and 1995 provides for the drilling of ten and five wells,
respectively, on the two producing acreage units within the Bob West Field that
are subject to the Tennessee Gas Contract and 17 and 10 wells, respectively, on
other acreage within the Bob West Field. In the first quarter of 1994, six wells
were drilled. The net costs associated with the Company's 1994 drilling program
(including the wells drilled during the first quarter) are expected to be
approximately $41.4 million.

The Company has entered into an agreement (the "Co-Operator Agreement")
pursuant to which the Company acts as the geological operator of approximately
two-thirds of the Bob West Field (the "Co-Operator Portion"), while Coastal Oil
& Gas Corporation acts as the production operator. As geological operator,
Tesoro's responsibilities include: (i) proposing and conducting seismic
operations, (ii) soliciting, evaluating and awarding bids for electric and mud
logging and (iii) assimilating subsurface information from each drill site and
applying such information for purposes of continuing development of the
Co-Operator Portion. In addition, the Company has proposed the drilling of all
new wells and the surface and subsurface location of such wells in the
Co-Operator Portion. The Company continues to propose the drilling of all new
wells in the Co-Operator Portion, but as of December 1, 1993 no longer has the
exclusive right to do so. The production operator is responsible for all other
operations associated with the Co-Operator Portion, including the drilling,
completion and production of all wells.

Upon the expiration of the Co-Operator Agreement on December 3, 1994, the
Company has the option of assuming responsibility for the production operator's
duties in the Co-Operator Portion. This option is

39
<PAGE> 41

contingent upon the Company's demonstrating to the production operator that the
Company has an in-house engineering staff and field operations staff capable of
and experienced in producing and reworking high pressure gas wells. The Company
believes that it will satisfy this requirement when the Co-Operator Agreement
expires, and currently intends to exercise the option to assume the production
operator's responsibilities for the Co-Operator Portion.

During 1993, in addition to the continued development of the Bob West
Field, the Company participated in the drilling of four exploratory wells at a
net cost of approximately $1.7 million in other areas of the Wilcox Trend. One
exploratory well was completed as a gas well and is currently producing, one has
been completed and is awaiting a pipeline connection and two were dry holes. In
1994, a delineation well to the first exploratory discovery was drilled at a net
cost of approximately $.2 million and was evaluated as a dry hole. Another
exploratory well drilled during 1994 has been completed but has not been tested.
Management of the Company currently intends to recommend to the Company's Board
of Directors that the Company proceed with a limited exploration program focused
primarily on the Wilcox Trend of South Texas if the Offering is successfully
completed and the MetLife Louisiana Option is exercised in full.

Tennessee Gas Contract. The Company has interests in two 352-acre producing
units in the Bob West Field that are subject to a gas purchase contract with
Tennessee Gas expiring on January 31, 1999. The Tennessee Gas Contract requires
Tennessee Gas to purchase gas from the two producing units at escalating prices
that are substantially above current spot market prices for natural gas. During
1993, for example, Tennessee Gas purchased approximately 27% of the Company's
net gas production from the Bob West Field under the Tennessee Gas Contract at
an average price of $7.59 per Mcf of gas, which was substantially above the 1993
average spot market rate of $2.03 per Mcf. The Tennessee Gas Contract is
presently the subject of litigation with Tennessee Gas. See "Investment
Considerations," "Legal Proceedings -- Tennessee Gas Contract" and Notes K and P
of Notes to Consolidated Financial Statements.

Gas Processing, Gathering and Transportation. The Company owns a 70%
interest in the central gas processing facility for the Bob West Field, which is
currently capable of processing 120 MMcf per day. The Company also owns a 70%
interest in the Starr County Gathering System's two 10-inch diameter pipelines.
The pipelines transport the Company's gas production eight miles to a 16-inch
diameter pipeline from the Bob West Field. In February 1994, the pipeline
facilities were at capacity and production subject to spot market prices was
being curtailed. However, the Company has continued to produce and transport all
of its gas in the Bob West Field subject to the Tennessee Gas Contract. New
common carrier pipeline facilities have been constructed by Coastal States Gas
Transmission Company. The Company believes the new facilities should provide
adequate transportation for all of the Company's gas production from the Bob
West Field. Tesoro has exercised its option to acquire a 50% interest in the new
pipeline facilities in consideration for payment of 50% of the capitalized costs
attributable to the facilities, plus interest on such costs at the rate of 8%
per annum. In addition, the central gas processing facility and sales line are
currently being expanded to enable processing in excess of 150 MMcf per day.

The Company does not operate the central gas processing facility for the
Bob West Field or the Starr County Gathering System's two 10-inch diameter
pipelines. If the Company is appointed as or becomes the production operator or
sole operator of the Co-Operator Portion under the Co-Operator Agreement, the
Company will be appointed as the operator of the central gas processing facility
for the Bob West Field. See " -- South Texas."

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<PAGE> 42

Bolivia

The Company's Bolivian exploration and production operations are located in
southern Bolivia near the border of Argentina, where, since 1976, the Company
has discovered four significant natural gas fields. As of December 31, 1993,
Tesoro was the second largest holder of proved natural gas reserves in Bolivia,
with estimated net proved reserves totaling 112 Bcfe. The Company is the
operator of a joint venture that 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 has drilled five exploratory wells and 12
development wells within three separate fields in Block XVIII. During 1993, the
Company's net production averaged 19 MMcf of gas per day and 660 Bbls of
condensate per day, a production level that has been maintained for more than
three years. 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 (which are payable in kind), with YPFB receiving
the remainder. Under the sales contract with YPFB covering hydrocarbons produced
from the La Vertiente, Escondido and Taiguati Fields in Block XVIII, the Company
and its joint venture participant have contracted to sell approximately 18 MMcf,
after Bolivian taxes, of natural gas per day to YPFB, which in turn resells the
gas to the Republic of Argentina. At December 31, 1993, the Company was
receiving $1.25 per Mcf for gas sold under this contract. The contract between
YPFB and the Republic of Argentina has recently been extended for an additional
three-year period ending March 31, 1997. The contract extension will maintain
approximately the same volumes, but with a small decrease in price. The
Company's contract with YPFB, including the pricing provision, is subject to
renegotiation in May 1994 for up to a three-year period. As a result of the
terms of the contract extension between YPFB and the Republic of Argentina, the
Company expects the renegotiation to result in a corresponding small decrease in
the contract price. The renegotiation could also result in a reduction of
volumes purchased from the Company due to new supply sources anticipated to
commence producing near the end of 1994.

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 Block XX and is shut in
pending the approval of a commercialization agreement by the Government of
Bolivia. 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 MMcf 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
of development 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 commenced 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 second and third exploratory wells, the Company has
submitted bank guarantees to YPFB in the aggregate amount of $4.0 million.

In January 1994, three major energy companies announced a project to build
a $2 billion natural gas pipeline from Bolivia to Brazil. The Company
understands that the project is in the early planning stages, and that the
companies are seeking financing. There can be no assurance that these companies
will proceed with the project or, if so, whether or when the pipeline will
ultimately be completed. In any event, however, the Company does not believe
that the pipeline could be completed before 1997.

For further information regarding Tesoro's Bolivian operations, see Note F
of Notes to Consolidated Financial Statements.

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<PAGE> 43

Operating Statistics

The following table summarizes the Company's exploration and production
activities for the fiscal years ended September 30, 1991, December 31, 1992 and
December 31, 1993 and the three-month periods ended March 31, 1993 and 1994.
Effective May 1, 1992, the Company sold its Indonesian operations.

<TABLE>
<CAPTION>
YEAR YEAR ENDED THREE MONTHS
ENDED DECEMBER 31, ENDED MARCH 31,
SEPTEMBER 30, ------------------- ------------------
1991 1992 1993 1993 1994
-------- ------- ------- ------ -------
<S> <C> <C> <C> <C> <C>
Net natural gas production
(average daily Mcf):
United States.......................... 7,435 13,960 38,767 27,009 48,998
Bolivia(1)............................. 19,322 19,421 19,232 17,747 19,137
-------- ------- ------- ------ -------
Total.......................... 26,757 33,381 57,999 44,756 68,135
-------- ------- ------- ------ -------
-------- ------- ------- ------ -------
Net crude oil production
(average BPD):
Bolivia (condensate)................... 663 660 663 620 662
Indonesia.............................. 3,315 2,714 -- -- --
-------- ------- ------- ------ -------
Total.......................... 3,978 3,374 663 620 662
-------- ------- ------- ------ -------
-------- ------- ------- ------ -------
Average realized sales prices --
Natural gas (per Mcf):
United States(3)....................... $ 1.88 $ 3.68 $ 3.55 $ 3.07 $ 3.92
Bolivia................................ 3.06 1.67 1.22 1.19 1.23
</TABLE>

<TABLE>
<S> <C> <C> <C> <C> <C>
Average realized sales prices --
Crude oil (per Bbl):
Bolivia (condensate)................... $ 21.11 $ 17.65 $ 14.26 $15.37 $ 11.48
Indonesia.............................. 24.39 18.20 -- -- --
Average lifting cost (per net
equivalent Mcf):
United States.......................... $ .44 $ .74 $ .48 $ .49 $ .53
Bolivia................................ .09 .08 .14 .23 .11
Indonesia.............................. 1.35 1.94 -- -- --
Average finding cost for natural gas --
United States(2) (per Mcf)............. $ .72 $ .20 $ .47 * *
Proved natural gas reserves at end of
period:
United States (Bcf).................... 33.1 73.8 120.2 ** 121.5
Bolivia (Bcfe)......................... 131.6 120.1 111.9 ** **
Present value of estimated future net
revenues from proved reserves before
deduction of income taxes (end of
period):
(dollars in millions)(3)
United States(4)....................... $ 32.1 $ 120.2 $ 162.6 ** $ 171.0
Bolivia................................ 123.5 54.1 55.2 ** **
</TABLE>

- ---------------

* Data not available.

** The Company did not obtain independent reserve reports at March 31, 1993 for
any of its oil and gas properties or at March 31, 1994 for its Bolivian
properties.
(Table continued on following page)

42
<PAGE> 44

YEAR YEAR ENDED DECEMBER THREE MONTHS
ENDED 31, ENDED MARCH 31,
SEPTEMBER 30, -------------------- -------------------
1991 1992 1993 1993 1994
-------- ------- ------- ------ -------
<S> <C> <C> <C> <C> <C>
Depletion rates ($ per net
equivalent Mcf):
United States.................. $ 1.06 $ .95 $ .78 $ .82 $ .85
Indonesia...................... .22 .15 -- -- --
Net exploratory wells drilled:
United States --
Net productive wells........ 1.46 1.00 .38 -- .13
Net dry holes............... -- .50 .50 -- .13
Net development wells drilled:
Net productive wells --
United States............... 1.43 3.85 7.87 .66 3.25
Indonesia................... 3.00 -- -- -- --
-------- ------- ------- ------ -------
Total.................. 4.43 3.85 7.87 .66 3.25
-------- ------- ------- ------ -------
-------- ------- ------- ------ -------
Net dry holes --
United States............... 1.00 -- -- -- .38
Indonesia................... 2.00 -- -- -- --
-------- ------- ------- ------ -------
Total.................. 3.00 -- -- -- .38
-------- ------- ------- ------ -------
-------- ------- ------- ------ -------
</TABLE>

- ---------------

(1) The Company's natural gas production from Bolivia as presented above
represents the Company's net production before Bolivian taxes.

(2) Average finding cost per Mcf represents costs incurred in oil and gas
property acquisition, exploration and development activities for each
indicated period divided by the changes in proved reserves resulting from
extensions, discoveries and other additions and revisions of previous
reserve quantity estimates during such period. See Note P of Notes to
Consolidated Financial Statements.

(3) The present value of estimated future net revenues from proved crude oil
and natural gas reserves at the end of each period presented has been
calculated in accordance with the rules and regulations of the Commission.
The calculation was made on a pre-tax basis, assuming no escalation in
prices and using a 10% discount rate. This present value is not intended to
be representative of the fair market value of the Company's proved
reserves. The calculations of revenues and costs used to determine the
present value of estimated future net revenues do not necessarily represent
the amounts to be received or expended by the Company. For further
information, see the discussion below and Note P of Notes to Consolidated
Financial Statements.

(4) See "Investment Considerations," "Legal Proceedings -- Tennessee Gas
Contract" and Notes K and P of Notes to Consolidated Financial Statements
regarding litigation concerning the Tennessee Gas Contract.

Proved developed reserves are proved reserves that are expected to be
recovered from existing wells with existing equipment and operating methods.
Proved undeveloped reserves are proved reserves that are expected to be
recovered from new wells drilled to known reservoirs on undrilled acreage for
which the existence and recoverability of such reserves can be estimated with
reasonable certainty, or from existing wells where a relatively major
expenditure is required to establish production.

The present values shown should not be construed as the current market
value of the reserves. The 10% discount factor used to calculate present value,
which is specified by the Commission, is not necessarily the most appropriate
discount rate, and present value, no matter what discount rate is used, is
materially affected by assumptions as to timing of future production, which may
prove to be inaccurate. In addition, the

43
<PAGE> 45

calculation of estimated future net revenues does not take into account the
effect of various cash outlays, including, among other things, general and
administrative costs and interest expense.

Future prices received for production and future production costs may vary,
perhaps significantly, from the prices and costs assumed for purposes of these
estimates. There can be no assurance that the proved reserves will be developed
within the periods indicated or that prices and costs will remain constant.
There can be no assurance that actual production will equal the estimated
amounts used in the preparation of reserve projections. The reserve estimates
and present values of estimated future net revenues in the preceding table are
based on spot and contract prices in effect at the end of the indicated period,
without escalation. The prices used for the December 31, 1993 estimates were
$1.75 per Mcf for spot market gas in the Bob West Field, $7.73 per Mcf for gas
sold under the Tennessee Gas Contract and $1.13 per Mcf for Bolivian gas. Price
reductions decrease such present values by lowering the future net revenues
attributable to the reserves and will reduce the quantities of reserves that are
economically recoverable. Price increases have the opposite effect. Any
significant decline in prices of oil or gas, or an adverse outcome in the
Tennessee Gas litigation, could have a material adverse effect on the Company's
financial condition and results of operations.

There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures. The data in the above tables represent estimates only.
Oil and gas reserve engineering must be recognized as a subjective process of
estimating underground accumulations of oil and gas that cannot be measured in
an exact way, and estimates of other engineers might differ materially from
those shown above. The accuracy of any reserve estimate is a function of the
quality of available data and engineering and geological interpretation and
judgment. Results of drilling, testing and production after the date of the
estimate may justify revisions. Accordingly, reserve estimates are often
materially different from the quantities of oil and gas that are ultimately
recovered.

Netherland, Sewell & Associates, Inc., independent petroleum consultants,
prepared the foregoing estimates of the Company's proved reserves and the
present values of estimated future net revenues therefrom (except for estimates
of future income tax expense related thereto). No estimates of the Company's
reserves comparable to those included herein have been included in reports to
any federal agency other than the Commission.

ACREAGE AND WELLS

The following table sets forth the Company's gross and net acreage and
productive wells at December 31, 1993:

<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
ACREAGE ACREAGE
------------- --------------
ACREAGE (IN THOUSANDS) GROSS NET GROSS NET
-------------------------------------------------------- ----- --- ------ ----
<S> <C> <C> <C> <C>
United States........................................... 3 2 11 4
Bolivia................................................. 38 29 1,210 880
----- --- ------ ----
Total................................................. 41 31 1,221 884
----- --- ------ ----
----- --- ------ ----
</TABLE>

<TABLE>
<CAPTION>
GAS
--------------
PRODUCTIVE GAS WELLS GROSS NET
-------------------------------------------------------------- ----- ----
<S> <C> <C>
United States................................................. 26 14.8
Bolivia....................................................... 14 10.5
----- ----
Total(1).................................................... 40 25.3
----- ----
----- ----
</TABLE>

- ---------------

(1) 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.

44
<PAGE> 46

OIL FIELD SUPPLY AND DISTRIBUTION

The Company sells lubricants, fuels and specialty petroleum products
primarily to onshore and offshore drilling contractors. The Company's products
are sold through five 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.

Effective March 31, 1994, the Company discontinued its environmental
remediation products and services operations and recorded a charge of $.9
million in connection with such discontinuance.

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 NGPA,
the Natural Gas Act (the "NGA"), and the regulations and orders issued by 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, the FERC has endeavored to make natural gas transportation more accessible
to gas buyers and sellers on an open and nondiscriminatory 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 sales efforts. In addition,
numerous petitions seeking judicial review of Orders Nos. 636, 636A and 636B and
seeking review of the 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.

45
<PAGE> 47

The Company does not believe that 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, the FERC initiated a proceeding seeking industry-wide
comments about its role in regulating natural gas gathering performed by
interstate pipelines or their affiliates. Numerous written and oral comments
have been received by the FERC concerning whether and how it should regulate
gathering activities, but the Company cannot predict what, if any, action the
FERC may take or whether such action will affect access to markets of its gas or
its own gas gathering facilities and activities.

The oil and gas exploration and production operations of the Company are
subject to various types of regulation at the state and local levels. Such
regulation includes requiring drilling permits and the maintenance of bonds in
order to drill or operate wells; the regulation of the location of wells; the
method of drilling and casing of wells and the surface use and restoration of
properties upon which wells are drilled; and the plugging and abandoning of
wells. The operations of the Company are also subject to various conservation
regulations, including regulation of the size of drilling and spacing units or
proration units, the density of wells that may be drilled in a given area and
the unitization or pooling of oil and gas properties. In this regard, some
states allow the forced pooling or integration of lands and leases. In addition,
state conservation laws establish maximum rates of production from oil and gas
wells, generally prohibit the venting or flaring of gas and impose certain
requirements regarding the ratability of production. The effect of these
regulations is to limit the amounts of crude oil, condensate and natural gas the
Company can produce from its wells and the number of wells or the locations at
which the Company can drill.

The North American Free Trade Agreement has further streamlined and
simplified procedures for the importation and exportation of gas 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 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 Alaska one additional year of exemption from requiring the use of
oxygenated gasoline. However, state and local officials may still require the
use of these fuels at their option. In addition, the EPA has been directed to
conduct additional studies of potential health effects of oxygenated fuel in
Alaska. Additional federal regulations promulgated on August 21, 1990, and
scheduled to go into effect on October 1, 1993, set limits on the quantity of
sulphur in on-highway diesel fuels which the Company produces. The State

46
<PAGE> 48

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 approximately 1% of its refined product sales
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 Alaska, the majority
of which are located in nonresidential 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 remove or upgrade underground storage tanks at
several of its current and former service station locations; however, the
Company does not expect to make any material capital expenditures for such
purposes. See "Legal Proceedings."

The Company currently charters a vessel to transport crude oil from the
Valdez, Alaska pipeline terminal through Prince William Sound and Cook Inlet to
the 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 the 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 (50,000 Bbls). With respect to
the charter vessels employed by the Company to transport crude oil through
Prince William Sound and Cook Inlet to the 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. To meet the federal and
State standards, the Company has entered into a contract with Alyeska Pipeline
Service Company ("Alyeska") to provide the initial spill response services in
Prince William Sound, with the Company to assume those responsibilities after
mutual agreement with Alyeska and the State and Federal On-Scene Spill Response
Coordinators. The Alaska legislature passed legislation in 1992, providing
limited immunity for spill response contractors, which has facilitated access to
contract extensions that will not be dependent on further legislative action.
The Company has also entered into an agreement with Cook Inlet Spill Prevention
& Response Inc. for oil spill response services in Cook Inlet. The Company
believes these contracts provide the additional services necessary to meet the
spill response requirements established by Alaska and federal law.

For further information regarding environmental matters, see "Legal
Proceedings."

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 currently imposed by Bolivian laws,
regulations and practices will have a material adverse effect upon its Bolivian
operations.

47
<PAGE> 49

TAXES

United States

The Revenue Reconciliation Act of 1993 imposed a 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
have had or will have a material adverse effect on the Company's 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 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 that 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 adverse effect on the
Company's Bolivian operations.

48
<PAGE> 50

MANAGEMENT

The following table sets forth certain information as of May 26, 1994 with
respect to the executive officers and directors of the Company.

DIRECTORS

<TABLE>
<CAPTION>
NAME AGE POSITION WITH COMPANY OCCUPATION
---- --- ------------------------ ------------------------------
<S> <C> <C> <C>
Ray C. Adam.................... 74 Director Former Chairman and Chief
Executive Officer of NL
Industries, Inc.
Michael D. Burke............... 50 Director, President and President and Chief
Chief Executive Executive Officer of Tesoro
Officer
Robert J. Caverly.............. 75 Director Consultant and Investor
Peter M. Detwiler.............. 65 Director Chairman of the Board of
Detwiler & Company, Inc.
</TABLE>

<TABLE>
<S> <C> <C> <C>
Steven H. Grapstein............ 36 Director Vice President of Kuo
Investment Company
Charles F. Luce................ 76 Director Special Counsel to MetLife
Raymond K. Mason, Sr........... 67 Director Chairman of the Board of
American Banks of Florida,
Inc.
John J. McKetta, Jr............ 78 Director Professor Emeritus Chemical
Engineering at The University
of Texas at Austin
Stewart G. Nagler.............. 51 Director Senior Executive Vice-
President and Chief Financial
Officer of MetLife
William S. Sneath.............. 68 Director Former Chairman and Chief
Executive Officer of
Union Carbide
Arthur Spitzer................. 81 Director Owner of Spitzer Investments
Murray L. Weidenbaum........... 67 Director Mallinckrodt Distinguished
University Professorship at
Washington University,
St. Louis, Missouri
Charles Wohlstetter............ 84 Director and Chairman Vice Chairman of the
of the Board of Board of GTE Corporation
Directors
</TABLE>

49
<PAGE> 51

EXECUTIVE OFFICERS

<TABLE>
<CAPTION>
PRESENT
POSITION
NAME AGE POSITION HELD SINCE
---- --- ------------------------------- ---------------
<S> <C> <C> <C>
Michael D. Burke................... 50 President and Chief Executive July 1992
Officer
Gaylon H. Simmons.................. 54 Executive Vice President September 1993
Bruce A. Smith..................... 50 Executive Vice President and September 1993
Chief Financial Officer
James W. Queen..................... 54 Senior Vice President February 1994
Don E. Beere....................... 53 Vice President, Controller February 1992
James E. Duncan.................... 49 Vice President, Corporate March 1993
Development
James C. Reed, Jr.................. 49 Vice President, General September 1993
Counsel and Secretary
William T. Van Kleef............... 42 Vice President, Treasurer March 1993
</TABLE>

Business Experience -- Executive Officers

<TABLE>
<S> <C>
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 responsible for Refining, Marketing and
Crude Supply Operations 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 responsible for Exploration and
Production Operations 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.
James W. Queen.......... Senior Vice President from February 1994. Senior Vice President,
Oil Field Products Distribution from February 1992 to February
1994. Senior Vice President, Control and Accounting from 1985 to
1992.
Don E. Beere............ Vice President, Controller from February 1992. Vice President,
Internal Audit and Management Systems of Tesoro Petroleum
Companies, Inc. from February 1990 to 1992. Director, Internal
Audit and Management Systems from December 1989 to 1990.
Director, Internal Audit from February 1986 to 1989.
James E. Duncan......... Vice President, Corporate Development from March 1993. Vice
President, Treasurer from February 1992 to 1993. Vice President,
Controller of Tesoro Petroleum Companies, Inc. from February
1990 to 1992. Director, Corporate Accounting from April 1985 to
1990.
</TABLE>

50
<PAGE> 52

<TABLE>
<S> <C>
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 February 1990
to 1992. Assistant General Counsel and Assistant Secretary from
August 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 February 1991.
</TABLE>

POSSIBLE CHANGE IN BOARD OF DIRECTORS

Under the terms of the Amended MetLife Memorandum, MetLife Louisiana has
agreed to request that Messrs. Ray C. Adam, Charles F. Luce, Stewart G. Nagler
and William S. Sneath resign in the event the MetLife Louisiana Option is
exercised in full. The Company believes that if the MetLife Louisiana Option is
exercised in full, those directors will resign. The Nominating Committee of the
Board of Directors and the Board of Directors have not determined whether the
vacancies that would be created by such resignations will be filled or, if so,
who would be nominated. The members of the Board of Directors have reached an
understanding that, if the MetLife Louisiana Option has not been exercised in
full by June 30, 1994, on such date the Board of Directors will appoint one
additional director to be selected from a list, to be proposed by MetLife
Louisiana and Oakville N.V. (another major stockholder of the Company), of
persons associated with or recommended by major stockholders.

LEGAL PROCEEDINGS

Tennessee Gas Contract. The Company is selling a portion of the gas from
its Bob West Field to Tennessee Gas under a Gas Purchase and Sales Agreement
which provides that the price of gas shall be the maximum price as calculated in
accordance with Section 102(b)(2) of the NGPA (the "Contract Price").

The District Court trial judge returned a verdict in favor of the Company
on all issues. On appeal by Tennessee Gas, the Court of Appeals affirmed the
validity of the Tennessee 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 remanded the case to the trial court based on its determination
(i) that the Tennessee Gas Contract was an output contract and (ii) that a fact
issue existed as to whether the increases in the volumes of gas tendered to
Tennessee Gas under the contract were made in bad faith or were unreasonably
disproportionate to prior tenders. The Company is seeking review of the
appellate court ruling on the output contract issue in the Supreme Court of
Texas. Tennessee Gas is seeking review of the appellate court ruling denying the
remaining Tennessee Gas claims in the Supreme Court of Texas.

51
<PAGE> 53

not grant the Company's petition for writ of error and affirms the appellate
court ruling, the Company believes that the only issue for trial should be
whether the increases in the volumes of gas tendered to Tennessee Gas from the
Company's properties were made in bad faith or were unreasonably
disproportionate. The appellate court decision was the first reported decision
in Texas holding that a take-or-pay contract was an output contract. As a
result, it is not clear what standard the trial court would be required to apply
in determining whether the increases were in bad faith or unreasonably
disproportionate. The appellate court acknowledged in its opinion that the
standards used in evaluating other kinds of output contracts would not be
appropriate in this context. The Company believes that the appropriate standard
would be whether the development of the field was undertaken in a manner that a
prudent operator would have undertaken in the absence of an above-market sales
price. Under that standard, 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 March 31, 1994, under the
Tennessee Gas Contract based on the Contract Price, which net revenues
aggregated $21.1 million more than the Section 101 prices and $38.9 million in
excess of the spot market prices. If Tennessee Gas ultimately prevails in this
litigation, the Company could be required to return to Tennessee Gas the
difference between the spot market price for gas and the Contract Price, plus
interest, if awarded by the court. In addition, the present value of estimated
future net revenues on a pre-tax basis from the Company's proved domestic
reserves has been calculated based in part on the price being paid by Tennessee
Gas at the date of determination. At March 31, 1994, such present value was
$171.0 million. If calculated using March 31, 1994 spot market prices instead of
the Contract Price, such present value would have been $92.0 million.

In a separate letter to the Company, Tennessee Gas asserted that the gas
delivered under the Tennessee Gas Contract did not meet contractual
specifications and indicated that it intended to refuse future deliveries of gas
unless the deficiency was corrected within 30 days. The Company believes that
its future deliveries of gas will meet contractual specifications. An adverse
judgment in this case could have a material adverse effect on the Company. See
Notes K and P of Notes to Consolidated Financial Statements.

Refund Claim. In May 1994, a former customer threatened to file suit
against the Company for a refund in the amount of approximately $1.2 million,
plus interest of approximately $4.4 million and attorney's fees, related to two
gasoline purchases from the Company in 1979. The customer also alleges
entitlement to treble damages and punitive damages in the aggregate amount of
$16.8 million. The refund claim is based on allegations that the Company
renegotiated the acquisition price of gasoline sold to the customer and failed
to pass on the benefit of the renegotiated price to the customer in violation of
Department of Energy price and allocation controls then in effect. The Company
believes the claim is without merit and anticipates that the ultimate resolution
of this matter will not have a material adverse effect on the Company.

ADEC Consent Order. In March 1991, the Company entered into a Consent Order
with the Alaska Department of Environmental Conservation ("ADEC") substantially
similar to 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 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

52
<PAGE> 54

and to remove the hydrocarbons. The Company estimates that annual expenditures
of approximately $1.5 million will be required in the future to operate such
subsurface monitoring and interception systems. The majority of such expenses
will be covered by insurance through 1995.

Clean Air Act Matters. In March 1992, the Company received a notice from
the EPA alleging possible violations by the Company of the New Source
Performance Standards under the Clean Air Act at the Refinery. 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 to date assessed a
penalty against the Company for its alleged violations. Although the Company is
continuing in its efforts to resolve these issues with the EPA, 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.

Mud and Gulf Coast Superfund Sites. The Company, along with over 100 other
parties, has been identified by the EPA as a PRP pursuant to CERCLA for the Mud
and Gulf Coast Superfund sites in Abbeville, Louisiana. The Company arranged for
the disposal of a minimal amount of materials at these locations, but CERCLA
imposes joint and several liability on each PRP. The EPA is seeking
reimbursement for its response costs incurred to date at each site, as well as a
commitment from the PRPs either to conduct future remedial activities or to
finance such activities.

The Company has entered into a de minimis settlement with the EPA at the
Gulf Coast site for $2,500. At this time, the Company is unable to determine the
extent of the Company's liability related to the Mud site; however, based on the
Gulf Coast settlement, the Company believes that the aggregate amount of such
liability, if any, would not have a material adverse effect on the Company.

Recapitalization Matters. 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 in
formulating the originally proposed terms of the Recapitalization, 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. On April 13,
1994, the court entered an order that approved a settlement agreement which
provided for (i) the exchange of each share of $2.16 Preferred Stock into 4.9
shares of Common Stock and (ii) the issuance of up to 131,956 shares of Common
Stock and the payment of $500,000 by the Company for plaintiff's attorneys' fees
and expenses awarded by the Delaware Chancery Court. By order dated April 20,
1994, the court awarded plaintiff's counsel $500,000 and 73,913 shares of Common
Stock out of the 131,956 shares of Common Stock applied for by such counsel for
legal fees and expenses, with the remaining shares to be issued to the former
holders of $2.16 Preferred Stock as of the close of business on February 9, 1994
upon the court's orders becoming final and nonappealable. Subsequently, counsel
retained by a party objecting to the settlement has applied for legal fees and
expenses totalling approximately $11,500 to be paid in the form of Common Stock
out of the 58,043 shares of Common Stock to be issued to the former holders of
$2.16 Preferred Stock.

DESCRIPTION OF CAPITAL STOCK

GENERAL

The authorized capital stock of the Company consists of 50,000,000 shares
of Common Stock and 5,000,000 shares of preferred stock, no par value, of which
2,875,000 shares have been designated as $2.20 Preferred Stock and 250,000
shares have been designated as Series A Participating Preferred Stock. At May
26, 1994, there were outstanding 22,531,093 shares of Common Stock and 2,875,000
shares of $2.20 Preferred Stock. Each share of $2.20 Preferred Stock has a
liquidation value of $20 (plus accrued and unpaid dividends). Chemical Bank,
N.A. is the transfer agent and registrar for the Common Stock and the $2.20
Preferred Stock.

Each outstanding share of the Company's capital stock is fully paid and
nonassessable.

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<PAGE> 55

The following descriptions summarize the material terms and provisions of
the Company's capital stock, but do not purport to be complete, and are
qualified in their entirety by reference to the Company's Certificate of
Incorporation, as amended, and the Amended MetLife Memorandum, which are filed
as exhibits to the Registration Statement of which this Prospectus is a part.

COMMON STOCK

Dividends

Holders of Common Stock are entitled to dividends, when and if declared by
the Board of Directors, but only out of funds legally available therefor,
subject to (i) the rights of the holders of shares ranking prior to Common Stock
as to dividends and distributions, including the $2.20 Preferred Stock, and (ii)
limitations on the payment of dividends on Common Stock contained in certain of
the Company's outstanding debt instruments. Holders of preferred stock,
including the $2.20 Preferred Stock, are entitled to the payment of dividends
for the current and all prior quarterly periods before any dividend may be
declared upon Common Stock or before any other payment on account of, or the
setting aside of money for, the purchase, redemption or other retirement of
Common Stock may be made. The Company is presently effectively prohibited from
paying cash dividends on its Common Stock. See "Price Range of Common Stock and
Dividend Policy" and Note I of Notes to Consolidated Financial Statements.

Liquidation Rights

Upon the liquidation, dissolution or winding up of the affairs of the
Company, whether voluntary or involuntary, each share of each class of preferred
stock, including the $2.20 Preferred Stock, is entitled, before any distribution
is made to holders of Common Stock, to receive the amount of the liquidation
value of such class of preferred stock, together with all accrued and unpaid
dividends to the date fixed for distribution. After the stated amounts payable
upon liquidation on the preferred stock have been paid in full or provision for
the payment has been made, the remaining net assets of the Company will be
distributed pro rata to the holders of Common Stock.

Voting Rights

Each share of Common Stock is entitled to one vote for all purposes, except
as otherwise provided by law or as expressly provided in the Certificate of
Incorporation.

$2.20 PREFERRED STOCK

Pursuant to the Amended MetLife Memorandum, MetLife Louisiana, the sole
holder of the $2.20 Preferred Stock, contractually agreed to substantial
modifications in the terms of the $2.20 Preferred Stock. MetLife Louisiana also
agreed not to sell any shares of the $2.20 Preferred Stock unless the buyer
agrees that such shares will remain subject to MetLife Louisiana's agreements
and waivers relating to the $2.20 Preferred Stock. The following description
incorporates the effect of such contractual modifications.

Dividends

Holders of $2.20 Preferred Stock are entitled to receive, when and as
declared by the Board of Directors, but only out of funds legally available
therefor, cumulative cash dividends presently payable at, but not exceeding, the
rate of $2.20 per share per annum. Dividends are payable quarterly, in cash, on
February 15, May 15, August 15 and November 15, and are cumulative. The Company
is prohibited from declaring and paying dividends on any junior stock and from
redeeming, repurchasing or making a sinking fund payment on any junior stock or
stock on a parity with the $2.20 Preferred Stock in the payment of dividends
unless all prior dividends accumulated on the $2.20 Preferred Stock, including
the current quarterly period, have been paid or declared and set aside for
payment. See " -- Ranking."

Pursuant to the Amended MetLife Memorandum, MetLife Louisiana has agreed to
consider all accrued and unpaid dividends on the $2.20 Preferred Stock as of
February 9, 1994, to have been paid and to allow the

54
<PAGE> 56

Company to pay future dividends on the $2.20 Preferred Stock in Common Stock in
lieu of cash, provided that the Company continues to pay all quarterly dividends
either in Common Stock or in cash. For purposes of determining the number of
shares of Common Stock to be issued in payment in lieu of a cash dividend, the
Common Stock will be valued at the average closing price for the Common Stock on
the New York Stock Exchange for the ten trading days commencing on the first
trading day after the Company publicly announces its intention to use Common
Stock in lieu of cash to pay the dividend.

Liquidation Rights

The $2.20 Preferred Stock has a liquidation preference of $20 per share,
plus accrued and unpaid dividends, before any distribution of assets is made to
holders of Common Stock or any other junior stock. If assets available for
distribution are insufficient to pay the full liquidation preference, all
classes of capital stock, if any, ranking on a parity as to liquidation rights
with the $2.20 Preferred Stock are entitled to share ratably in any such
distribution.

Redemption

The $2.20 Preferred Stock is redeemable, but only out of funds legally
available therefor, at the option of the Company, in whole or in part, on not
more than 45 and not less than 30 days' notice, at $20 per share plus dividends
accrued to the redemption date. If not sooner redeemed, on each February 15,
beginning on February 15, 1994, the Company is required to set aside funds and
effect the redemption of 6 2/3% (subject to certain credits) of the number of
shares of $2.20 Preferred Stock outstanding on February 15, 1994. If the Company
fails to pay dividends on the $2.20 Preferred Stock in an amount equal to at
least 12 quarterly dividends (whether or not consecutive) or if the Company
fails to make redemptions of $2.20 Preferred Stock when required with respect to
at least the number of shares to be redeemed in any three-year period, and if
all of the outstanding shares of $2.20 Preferred Stock are held by MetLife
Louisiana or by its affiliates, the Company is required to redeem, out of funds
legally available therefor, at the option of MetLife Louisiana or its affiliates
(the "$2.20 Preferred Stock Put Option"), within 60 days of the occurrence
thereof, all of the outstanding shares of $2.20 Preferred Stock at the
applicable redemption price plus dividends accrued to the redemption date. Prior
to any such redemption, the Company shall pay or make provision for payment of
all accrued and unpaid dividends on all shares of the Company's preferred stock.

Pursuant to the Amended MetLife Memorandum, MetLife Louisiana has agreed to
waive the $2.20 Preferred Stock Put Option and the annual mandatory redemption
requirements associated with the $2.20 Preferred Stock. The Company has agreed
not to exercise its right to optionally redeem the $2.20 Preferred Stock at any
time prior to February 9, 1998.

Ranking

The $2.20 Preferred Stock ranks senior to the Common Stock as to
liquidation and dividends.

Conversion

The shares of $2.20 Preferred Stock are convertible, at the option of the
holder thereof, into shares of Common Stock at a rate of 0.8696 shares of Common
Stock for each share of $2.20 Preferred Stock. The conversion price is subject
to adjustment in certain events, including (i) dividends (and other
distributions) payable to all holders of Common Stock in shares of the Company's
capital stock, including Common Stock, (ii) the issuance to all holders of
Common Stock of rights or warrants which entitle them to subscribe for or
purchase Common Stock at a price per share less than the current market price
(as defined), (iii) subdivisions, combinations and reclassifications of Common
Stock and (iv) distributions to all holders of Common Stock of evidences of
indebtedness of the Company or assets (including securities, but excluding those
rights or warrants referred to above and dividends and distributions paid in
cash out of current or retained earnings). In case of certain consolidations or
mergers to which the Company is a party or the sale or transfer of all or
substantially all of the assets of the Company, each share of $2.20 Preferred
Stock then outstanding is entitled to be converted after such consolidation,
merger, sale or transfer into the kind and

55
<PAGE> 57

amount of securities, cash and other property receivable upon the consolidation,
merger, sale or transfer by a holder of a number of shares of Common Stock into
which such share of $2.20 Preferred Stock might have been converted immediately
prior to such consolidation, merger, sale or transfer. Fractional shares of
Common Stock are not to be issued upon conversion, but, in lieu thereof, the
Company will pay a cash adjustment based on market price.

Pursuant to the Amended MetLife Memorandum, MetLife Louisiana has agreed to
refrain from exercising the conversion rights of the $2.20 Preferred Stock.

Voting Rights

The holders of $2.20 Preferred Stock are entitled to one vote per share,
voting together as a single class with the holders of Common Stock and any other
class or series which may similarly be entitled to vote with the holders of
Common Stock, on all matters on which the shares of Common Stock may vote,
including the elections of directors.

The affirmative vote of the holders of two-thirds of the outstanding shares
of $2.20 Preferred Stock, voting as a separate class, is required (i) to
authorize or increase the authorized amount of, or authorize any obligation or
security convertible into or evidencing the right to purchase shares of, any
additional class or series of stock ranking prior to the $2.20 Preferred Stock
as to the payment of dividends or the distribution of assets, (ii) to amend,
alter or repeal the voting powers, preferences or rights of the $2.20 Preferred
Stock in any respect adverse to the holders thereof or (iii) to authorize the
merger or consolidation of the Company if such merger or consolidation would
have an effect on the $2.20 Preferred Stock substantially similar to (i) or (ii)
above.

In addition, the affirmative vote of the holders of a majority of the
outstanding shares of $2.20 Preferred Stock, voting together as a single class,
is required in order to authorize any increase in authorized $2.20 Preferred
Stock or authorize or increase the authorized amount of, or authorize any
obligation or security convertible into or evidencing the right to purchase
shares of, any additional class or series of stock ranking on parity with the
$2.20 Preferred Stock as to the payment of dividends or the distribution of
assets.

Pursuant to the Amended MetLife Memorandum, the Board of Directors was
expanded from 13 to 16 members, and three new directors were selected from a
list proposed by MetLife Louisiana to fill the vacancies created thereby. The
three persons proposed by MetLife Louisiana were elected to the Board of
Directors. In addition, the Company amended its By-Laws to allow for the calling
of a special meeting of stockholders to elect one additional director in the
event a majority of the 16-member Board of Directors cannot be obtained on a
consistent basis. One of the three new directors proposed by MetLife Louisiana
has resigned and a second chose not to stand for re-election at the Company's
1994 annual meeting (which was held on May 26, 1994). The members of the Board
of Directors have reached an understanding that, if the MetLife Louisiana Option
has not been exercised in full by June 30, 1994, on such date the Board of
Directors will appoint one additional director to be selected from a list, to be
proposed by MetLife Louisiana and Oakville N.V., of persons associated with or
recommended by major stockholders.

Failure to Redeem $2.20 Preferred Stock or Pay Dividends

If the Company fails to make redemptions of $2.20 Preferred Stock when
required with respect to at least the number of shares to be redeemed on any two
redemption dates, and if the default in dividends described in the next
paragraph is not then in effect ("Dividend Default"), the number of directors
then constituting the Board of Directors shall be increased by two and the
holders of the $2.20 Preferred Stock, voting separately as a single class, shall
have the right to elect the two additional members of the Board of Directors.
Such right will expire when the arrearage in such redemptions has been cured or
when a Dividend Default has occurred.

If the Company fails to pay dividends on the $2.20 Preferred Stock in an
amount equal to at least six quarterly dividends (whether or not consecutive),
the number of directors then constituting the Board of Directors shall be
increased by two and the holders of the $2.20 Preferred Stock, voting together
as a single class with the holders of any other series of preferred stock having
similar voting rights, shall have the right to

56
<PAGE> 58

elect the two additional members of the Board of Directors. Such right will
expire when all accrued but unpaid dividends on the preferred stock have been
paid and dividends on the preferred stock for the then current quarterly period
have been paid or declared and set apart.

Future Preferred Stock and Offer to Repurchase

Pursuant to the Amended MetLife Memorandum, the Company has agreed to issue
to MetLife Louisiana, upon MetLife Louisiana's request, a new series of
preferred stock ("Future Preferred Stock") in the event that the MetLife
Louisiana Option is not exercised in full prior to its expiration and has agreed
to offer to repurchase 287,500 shares of the $2.20 Preferred Stock or, if issued
in lieu thereof, the Future Preferred Stock, each year commencing June 30, 1998.

RIGHTS AGREEMENT AND PARTICIPATING PREFERRED STOCK

Effective December 16, 1985, the Board of Directors declared a distribution
of one preferred stock purchase right on each outstanding share of Common Stock.
Each right entitles stockholders until December 16, 1995 (or such later date as
the Company may provide) to purchase one one-hundredth of a share of
Participating Preferred Stock, no par value ("Participating Preferred Stock"),
at an initial exercise price of $35 for each one one-hundredth of a share.
Certificates delivered upon transfer or new issuance of Common Stock contain a
notation incorporating by reference the agreement pursuant to which such rights
have been issued.

The rights are not exercisable, or transferable apart from the Common
Stock, until ten days after any person (an "Acquiring Person") acquires shares
of the Company's capital stock having at least 20% of the general voting power
without approval of the Board of Directors. Separate certificates representing
the rights will be mailed to holders of Common Stock as of such date.

If, after an Acquiring Person acquires shares of the Company's capital
stock having 20% of the general voting power in a transaction not approved by
the Board of Directors, the Company were to be acquired in a merger or other
business combination transaction, each right would require that provision be
made for its holder to be allowed to purchase, at the then-current exercise
price of the right, that number of shares of common stock of the surviving
company which at the time of such transaction would have a market value of two
times the exercise price of the right. Thus, for example, if the market value of
the acquiring company's common stock at the time of the transaction were $17.50
per share and the exercise price of the rights were $35 per right, each right
would entitle a holder to receive upon exercise four shares of the acquiring
company's common stock.

If the Company were the surviving corporation in the merger and the Common
Stock was not changed, provision would be made so that each holder of a right
(other than the Acquiring Person) would receive upon its exercise that number of
shares of Participating Preferred Stock having a market value of two times the
exercise price of the right.

In order to allow for flexibility, the rights are subject to redemption at
the election of the Board of Directors at $.05 per right at any time prior to
ten days after someone becomes an Acquiring Person. Once any party becomes an
Acquiring Person and such ten-day period has elapsed, the rights become
nonredeemable. The rights have no voting or dividend rights.

The Participating Preferred Stock is nonredeemable and ranks on a parity
with other series of Preferred Stock. Each share has a minimum preferential
quarterly dividend rate of $1.00 per share, but is entitled to an aggregate
dividend of 100 times any dividend declared on the Common Stock (other than a
dividend payable in shares of Common Stock).

In the event of liquidation, the holders of the Participating Preferred
Stock will be entitled to receive a preferred liquidation payment of $35 per
share, but will be entitled to receive an aggregate liquidation payment equal to
such $35 per share plus 100 times any payment made per share of Common Stock.
Each share of Participating Preferred Stock will be entitled to 100 votes,
voting together with the Common Stock and any other class of the Company's
capital stock having general voting power. Finally, in the event of any merger,

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<PAGE> 59

consolidation or other transaction in which shares of Common Stock are exchanged
for or changed into other stock or securities, cash or other property, the
Participating Preferred Stock requires that provision be made so that each share
of Participating Preferred Stock will receive 100 times the amount received per
share of Common Stock. The foregoing rights of the Participating Preferred Stock
are protected against dilution in certain events. Fractional shares of
Participating Preferred Stock in integral multiples of one one-hundredth of a
share will be issuable. Because of the nature of the Participating Preferred
Stock dividend, liquidation and voting rights, the value of a one one-hundredth
interest in a share of Participating Preferred Stock purchasable with each right
should generally approximate the value of one share of Common Stock.

Pursuant to the Amended MetLife Memorandum, the Company has agreed to cause
the preferred stock purchase rights to cease to exist in the event the Company
has not fully exercised the MetLife Louisiana Option before its expiration.

UNDERWRITING

The Underwriters named below (the "Underwriters"), for whom CS First Boston
Corporation, Smith Barney Shearson Inc. and Jefferies & Company, Inc. are acting
as representatives (the "Representatives"), have severally agreed to purchase
from the Company the following respective numbers of shares of Common Stock:

<TABLE>
<CAPTION>
NUMBER OF
UNDERWRITER SHARES
-------------------------------------------------------------------------- ---------
<S> <C>
CS First Boston Corporation...............................................
Smith Barney Shearson Inc.................................................
Jefferies & Company, Inc..................................................
---------
Total........................................................... 5,000,000
---------
---------
</TABLE>

The Underwriting Agreement provides that the obligations of the
Underwriters are subject to certain conditions precedent and that the
Underwriters will be obligated to purchase all of the Shares offered hereby
(other than those Shares covered by the over-allotment option described below)
if any are purchased. The Underwriting Agreement provides that, in the event of
a default by an Underwriter, in certain circumstances, the purchase commitments
of non-defaulting Underwriters may be increased or the Underwriting Agreement
may be terminated.

The Company has granted to the Underwriters an option, expiring at the
close of business on the 30th day after the date of the initial public offering
of the Common Stock offered hereby, to purchase up to 500,000 additional shares
of Common Stock at the initial public offering price less the underwriting
discount, all as set forth on the cover page of this Prospectus. The
Underwriters may exercise such option only to cover over-allotments in the sale
of the shares of Common Stock. To the extent such option is exercised, each
Underwriter will become obligated, subject to certain conditions, to purchase
approximately the same percentage of such additional shares of Common Stock as
it was obligated to purchase pursuant to the Underwriting Agreement.

The Company has been advised by the Representatives that the Underwriters
propose to offer the Shares to the public initially at the public offering price
set forth on the cover page of this Prospectus and, through the

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<PAGE> 60

Representatives, to certain dealers at such price less a concession of $ per
Share; that the Underwriters and such dealers may allow a discount of $ per
Share on sales to certain other dealers; and that after the initial public
offering the public offering price and concession and discount to dealers may be
changed by the Representatives.

The Company, MetLife Louisiana, Oakville N.V. and each of the Company's
directors and executive officers, have agreed not to offer, sell, contract to
sell or otherwise dispose of any shares of Common Stock or the Company's
preferred stock (other than, in the case of MetLife Louisiana, to the Company,
pursuant to the MetLife Louisiana Option) or any other securities convertible
into or exchangeable for Common Stock or the Company's preferred stock other
than upon conversion of convertible securities outstanding on the date hereof or
pursuant to employee benefit plans (including, but not limited to, stock option
plans) for a period of 90 days after the date of this Prospectus in the case of
the Company and each of the Company's directors and executive officers, for a
period of 60 days after the date of this Prospectus in the case of Oakville N.V.
(subject to earlier termination upon the occurrence of certain events), and
through July 22, 1994 (subject to earlier termination upon the occurrence of
certain events) in the case of MetLife Louisiana, in each case without the prior
written consent of CS First Boston Corporation.

The Company has agreed to indemnify the Underwriters against certain
liabilities, including civil liabilities under the Securities Act of 1933, as
amended (the "Act"), or contribute to payments which the Underwriters may be
required to make in respect thereof.

During the past 12 months, Smith Barney Shearson Inc. and Jefferies &
Company, Inc. have provided investment banking and advisory services to the
Company, for which they have received customary compensation.

CANADIAN RESIDENTS

RESALE RESTRICTIONS

The distribution of the Common Stock offered hereby in Canada is being made
only on a private placement basis exempt from the requirement that the Company
prepare and file a prospectus with the securities regulatory authorities in each
province where trades of the Common Stock being offered hereby are effected.
Accordingly, any resale of the Common Stock being offered hereby in Canada must
be made in accordance with applicable securities laws which will vary depending
on the relevant jurisdiction, and which may require resales to be made in
accordance with available statutory exemptions or pursuant to a discretionary
exemption granted by the applicable Canadian securities regulatory authority.
Purchasers pursuant to the Offering in Canada are advised to seek legal advice
prior to any resale of the Common Stock being offered hereby.

REPRESENTATION OF PURCHASERS

Each purchaser of the Common Stock being offered hereby in Canada who
receives a purchase confirmation will be deemed to represent to the Company and
the dealer from whom such purchase confirmation is received that (i) such
purchaser is entitled under applicable provincial securities laws to purchase
such Common Stock without the benefit of a prospectus qualified under such
securities laws, (ii) where required by law, that such purchaser is purchasing
as principal and not as agent, and (iii) such purchaser has reviewed the text
above under "Resale Restrictions."

NOTICE TO ONTARIO RESIDENTS

The Common Stock offered hereby is stock of a foreign issuer and Ontario
purchasers will not receive the contractual right of action prescribed by
section 32 of the Regulation under the Securities Act (Ontario). As a result,
Ontario purchasers must rely on other remedies that may be available, including
common law rights of action for damages or rescission or rights of action under
the civil liability provisions of the U.S. federal securities laws.

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<PAGE> 61

All of the Company's directors and officers, as well as the experts named
herein, may be located outside of Canada and, as a result, it may not be
possible for Ontario purchasers to effect service of process within Canada upon
the Company or such persons. All or a substantial portion of the assets of the
Company and such persons may be located outside of Canada and, as a result, it
may not be possible to satisfy a judgment against the Company or such persons in
Canada or to enforce a judgment obtained in Canadian courts against such Company
or persons outside of Canada.

NOTICE TO BRITISH COLUMBIA RESIDENTS

A purchaser of the Common Stock being offered hereby to whom the Securities
Act (British Columbia) applies is advised that such purchaser is required to
file with the British Columbia Securities Commission a report within ten days of
the sale of any of the Common Stock being offered hereby acquired by such
purchaser pursuant to this Offering. Such report must be in the form attached to
British Columbia Securities Commission Blanket Order BOR #88/5, a copy of which
may be obtained from the Company. Only one such report must be filed in respect
of the Common Stock being offered hereby acquired on the same date and under the
same prospectus exemption.

LEGAL MATTERS

The validity of the Common Stock will be passed upon for the Company by
Fulbright & Jaworski L.L.P., a registered limited liability partnership, San
Antonio, Texas. Certain legal matters in connection with the Offering will be
passed upon for the Underwriters by Baker & Botts, L.L.P., a registered limited
liability partnership, Houston, Texas.

EXPERTS

The consolidated financial statements as of December 31, 1993, December 31,
1992 and for the years ended December 31, 1993, December 31, 1992 and September
30, 1991 and for the three-month period ended December 31, 1991 included in this
Prospectus have been audited by Deloitte & Touche, independent auditors, as
stated in their reports appearing herein and elsewhere in the registration
statement, and have been so included in reliance upon the reports of such firm
given upon their authority as experts in accounting and auditing.

Information set forth in this Prospectus, including information included in
Note P of Notes to Consolidated Financial Statements, relating to estimated
proved reserves of oil and gas and the related estimates of future net revenues
and present values thereof (except for estimates of future income tax expense
related thereto) as of September 30, 1991; December 31, 1991; December 31, 1992;
December 31, 1993; and March 31, 1994 for properties in the United States and as
of September 30, 1991; December 31, 1992; and December 31, 1993 for properties
in Bolivia have been prepared by Netherland, Sewell & Associates, Inc.,
independent petroleum engineers, and are included herein and incorporated by
reference herein upon the authority of such firm as an expert in petroleum
engineering.

AVAILABLE INFORMATION

A registration statement on Form S-3 (the "Registration Statement") under
the Act has been filed by the Company with the Commission with respect to the
securities offered hereby. As permitted by the rules and regulations of the
Commission, this Prospectus omits certain information contained in the
Registration Statement on file with the Commission. For further information
pertaining to the securities offered hereby, reference is made to the
Registration Statement, including the exhibits filed as a part thereof. Tesoro
is subject to the informational requirements of the Securities Exchange Act of
1934, as amended (the "Exchange Act"), and, in accordance therewith, files
periodic reports, proxy and information statements and other information with
the Commission. The Registration Statement, including the exhibits thereto, as
well as such reports, proxy and information statements and other information,
can be inspected and copied at the public reference facilities maintained by the
Commission at Citicorp Center, 500 West Madison Street, Suite 1400,

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<PAGE> 62

Chicago, Illinois 60661-2511 and 7 World Trade Center, 13th Floor, New York, New
York 10048. Copies of such documents can be obtained from the Commission at
prescribed rates by writing to it at 450 Fifth Street, N.W., Washington, D.C.
20549. Reports, proxy and information statements and other information
concerning Tesoro are also available for inspection and copying at the offices
of the New York Stock Exchange, 20 Broad Street, New York, New York 10005, and
the Pacific Stock Exchange, 115 Sansome, San Francisco, California 94104, on
which exchanges certain securities of Tesoro are listed.

INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE

The Company's Annual Report on Form 10-K for the year ended December 31,
1993, the Company's Quarterly Report on Form 10-Q for the quarter ended March
31, 1994, and the description of the Common Stock contained in the Registration
Statement on Form 8-A of the Company, heretofore filed by the Company with the
Commission pursuant to the Exchange Act, are incorporated herein by reference
and made a part of this Prospectus, except as superseded or modified herein.

All documents filed by the Company pursuant to Section 13(a), 13(c), 14 or
15(d) of the Exchange Act after the date of this Prospectus and prior to the
termination of the offering of the securities offered hereby shall be deemed to
be incorporated by reference in this Prospectus and to be part hereof from the
date of filing of such documents. Any statement contained in a document
incorporated by reference herein shall be deemed modified or superseded for
purposes of this Prospectus to the extent that a statement contained herein or
in any other subsequently filed document which also is or is deemed to be
incorporated by reference herein modifies or supersedes such statement. Any
statement so modified or superseded shall not be deemed, except as so modified
or superseded, to constitute a part of this Prospectus.

The Company will provide without charge to each person, including any
beneficial owner, to whom a copy of this Prospectus is delivered, upon the
written or oral request of any such person, a copy of any document incorporated
by reference in this Prospectus (not including exhibits to those documents
unless such exhibits are specifically incorporated by reference into the
information incorporated into this Prospectus). Requests for such copies should
be directed to Mr. James E. Duncan, Tesoro Petroleum Corporation, 8700 Tesoro
Drive, San Antonio, Texas 78217, telephone number (210) 283-2440 or (800)
837-6768.

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<PAGE> 63

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
PAGE
-----
<S> <C>
PRO FORMA CONDENSED CONSOLIDATED FINANCIAL DATA
Pro Forma Statements of Condensed Consolidated Operations -- Year Ended
December 31, 1993................................................................ F-3
Pro Forma Statements of Condensed Consolidated Operations -- Three Months Ended
March 31, 1994................................................................... F-4
Pro Forma Condensed Consolidated Balance Sheet -- March 31, 1994.................... F-5
Notes to Pro Forma Condensed Consolidated Financial Data............................ F-6
CONSOLIDATED FINANCIAL STATEMENTS -- TESORO PETROLEUM CORPORATION
Independent Auditors' Report........................................................ F-8
Statements of Consolidated Operations -- Years Ended September 30, 1991, December
31, 1992 and December 31, 1993 and Three Months Ended December 31, 1991,
March 31, 1993 and March 31, 1994................................................ F-9
Consolidated Balance Sheets -- December 31, 1992, December 31, 1993 and March 31,
1994............................................................................. F-10
Statements of Consolidated Common Stock and Other Stockholders' Equity -- Years
Ended September 30, 1991, December 31, 1992 and December 31, 1993 and Three
Months Ended December 31, 1991 and March 31, 1994................................ F-12
Statements of Consolidated Cash Flows -- Years Ended September 30, 1991, December
31, 1992 and December 31, 1993 and Three Months Ended December 31, 1991,
March 31, 1993 and March 31, 1994................................................ F-13
Notes to Consolidated Financial Statements.......................................... F-14
</TABLE>

F-1
<PAGE> 64

PRO FORMA CONDENSED CONSOLIDATED FINANCIAL DATA

The unaudited pro forma financial data set forth the Company's historical
financial data adjusted to give effect to the Recapitalization and the Offering,
assuming net proceeds of $54.0 million, after deduction of $3.5 million of
underwriting discounts and estimated expenses, from the issuance of 5,000,000
shares of the Company's Common Stock at an offering price of $11.50 per share
pursuant to the Offering. The pro forma financial data assume that the proceeds
from the Offering are used to exercise the MetLife Louisiana Option in full at a
price of $53.0 million and take into account the payment of a cash dividend on
the $2.20 Preferred Stock in May 1994 from the Company's available cash. See
"Use of Proceeds."

The pro forma financial data have been prepared assuming the
Recapitalization and the Offering occurred as of January 1, 1993 for Pro Forma
Statements of Condensed Consolidated Operations presentation purposes and on
March 31, 1994 for Pro Forma Condensed Consolidated Balance Sheet presentation
purposes, subject to the assumptions and adjustments in the accompanying Notes
to Pro Forma Condensed Consolidated Financial Data. The pro forma financial data
are not necessarily indicative of the Company's results of operations or
financial position in the future or of what the Company's results of operations
or financial position would have been had the Recapitalization and the Offering
been consummated during the periods, or as of the dates, for which pro forma
financial data are presented. The pro forma financial data are based upon, and
should be read in conjunction with, the Company's historical Consolidated
Financial Statements, including the notes thereto.

F-2
<PAGE> 65

PRO FORMA STATEMENTS OF CONDENSED CONSOLIDATED OPERATIONS
YEAR ENDED DECEMBER 31, 1993
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

<TABLE>
<CAPTION>
PRO FORMA
PRO FORMA RECAPITALIZATION AND
RECAPITALIZATION OFFERING(A)
------------------------- -----------------------
HISTORICAL ADJUSTMENTS ADJUSTED ADJUSTMENTS ADJUSTED
---------- ----------- -------- ----------- --------
<S> <C> <C> <C> <C> <C>
Total Revenues(b)..................... $ 834,910 $834,910 $834,910
---------- -------- --------
Costs of Sales and Operating
Expenses............................ 756,764 756,764 756,764
General and Administrative Expenses... 16,712 16,712 16,712
Depreciation, Depletion and
Amortization........................ 22,591 22,591 22,591
Interest Expense(c)................... 14,550 (94)(e) 14,456 14,456
Other................................. 5,640 142 (e) 5,782 5,782
---------- -------- --------
Total Costs and Expenses......... 816,257 816,305 816,305
---------- -------- --------
Earnings Before Income Taxes and
Extraordinary Loss.................. 18,653 18,605 18,605
Income Tax Provision(d)............... 1,697 1,697 1,697
---------- -------- --------
Earnings Before Extraordinary Loss.... 16,956 16,908 16,908
Extraordinary Loss.................... -- (4,850)(e) (4,850) (4,850)
---------- -------- --------
Net Earnings.......................... 16,956 12,058 12,058
Preferred Stock Dividend
Requirements........................ 9,207 (2,882)(e) 6,325 (6,325)(f) --
---------- -------- --------
Net Earnings Applicable to
Common Stock........................ $ 7,749 $ 5,733 $ 12,058
---------- -------- --------
---------- -------- --------
Earnings (Loss) Per Primary and Fully
Diluted* Share:
Earnings Before Extraordinary
Loss............................. $ .54 $ .46 $ .71
Extraordinary Loss.................. -- (.21) (.20)
---------- -------- --------
Net Earnings........................ $ .54 $ .25 $ .51
---------- -------- --------
---------- -------- --------
Average Shares of Common Stock
Outstanding (in thousands):
Primary............................. 14,290 22,788 23,704(f)
Fully Diluted....................... 19,065 25,288 23,704(f)
</TABLE>

- ---------------

* Anti-dilutive

See Notes to Pro Forma Condensed Consolidated Financial Data.

F-3
<PAGE> 66

PRO FORMA STATEMENTS OF CONDENSED CONSOLIDATED OPERATIONS
THREE MONTHS ENDED MARCH 31, 1994
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

<TABLE>
<CAPTION>
PRO FORMA
PRO FORMA RECAPITALIZATION AND
RECAPITALIZATION OFFERING(A)
----------------------- -----------------------
HISTORICAL ADJUSTMENTS ADJUSTED ADJUSTMENTS ADJUSTED
---------- ----------- -------- ----------- --------
<S> <C> <C> <C> <C> <C>
Total Revenues(b)....................... $ 192,740 $192,740 $192,740
---------- -------- --------
Costs of Sales and Operating Expenses... 167,605 167,605 167,605
General and Administrative Expenses..... 3,627 3,627 3,627
Depreciation, Depletion and
Amortization.......................... 6,677 6,677 6,677
Interest Expense........................ 4,877 4,877 4,877
Other................................... 1,191 1,191 1,191
---------- -------- --------
Total Costs and Expenses...... 183,977 183,977 183,977
---------- -------- --------
Earnings Before Income Taxes and
Extraordinary Loss.................... 8,763 8,763 8,763
Income Tax Provision(d)................. 1,561 1,561 1,561
---------- -------- --------
Earnings Before Extraordinary Loss...... 7,202 7,202 7,202
Extraordinary Loss...................... (4,752) 4,752 (e) -- --
---------- -------- --------
Net Earnings............................ 2,450 7,202 7,202
Preferred Stock Dividend
Requirements.......................... 1,889 (308)(e) 1,581 (1,581)(f) --
---------- -------- --------
Net Earnings Applicable to
Common Stock.......................... $ 561 $ 5,621 $ 7,202
---------- -------- --------
---------- -------- --------
Earnings (Loss) Per Primary and
Fully Diluted* Share:
Earnings Before Extraordinary Loss.... $ .27 $ .24 $ .30
Extraordinary Loss.................... (.24) -- --
---------- -------- --------
Net Earnings.......................... $ .03 $ .24 $ .30
---------- -------- --------
---------- -------- --------
Average Shares of Common Stock
Outstanding (in thousands):
Primary............................... 19,455 23,232(g) 24,148(f)
Fully Diluted......................... 23,018 25,809(g) 24,225(f)
</TABLE>

- ---------------

* Anti-dilutive

See Notes to Pro Forma Condensed Consolidated Financial Data.

F-4
<PAGE> 67

PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET
MARCH 31, 1994
(DOLLARS IN THOUSANDS)

<TABLE>
<CAPTION>
PRO FORMA
OFFERING(a)
------------------------
HISTORICAL(h) ADJUSTMENTS ADJUSTED
------------- ----------- --------
<S> <C> <C> <C>
Assets:
Current Assets:
Cash and short-term investments.................... $ 49,412 (533) (j) $ 48,879
Receivables........................................ 59,487 59,487
Inventories........................................ 75,403 75,403
Prepaid expenses and other......................... 9,870 9,870
--------- --------
Total Current Assets.......................... 194,172 193,639
Net Property, Plant and Equipment..................... 222,418 222,418
Other Assets.......................................... 25,519 25,519
--------- --------
$ 442,109 $441,576
--------- --------
--------- --------
Liabilities and Stockholders' Equity:
Current Liabilities(i)................................ $ 77,784 $ 77,784
--------- --------
Other Liabilities..................................... 35,277 35,277
--------- --------
Long-Term Debt and Other Obligations(i)............... 184,950 184,950
--------- --------
Common Stock and Other Stockholders' Equity:
$2.20 Preferred Stock.............................. 57,500 (57,500) (k) --
Common Stock....................................... 3,743 152 (k) 3,895
Additional paid-in capital......................... 114,406 56,815 (k) 171,221
Accumulated deficit................................ (31,337) (31,337)
Deferred compensation.............................. (214) (214)
--------- --------
Total Common Stock and Other Stockholders'
Equity...................................... 144,098 143,565
--------- --------
$ 442,109 $441,576
--------- --------
--------- --------
</TABLE>

- ------------------------

See Notes to Pro Forma Condensed Consolidated Financial Data.

F-5
<PAGE> 68

NOTES TO PRO FORMA CONDENSED CONSOLIDATED FINANCIAL DATA

(a) The Company is currently prohibited under the terms of the indenture
governing the Subordinated Debentures from repurchasing its capital stock,
including the shares of $2.20 Preferred Stock and Common Stock subject to
the MetLife Louisiana Option, except from the proceeds of a substantially
concurrent sale of other shares of capital stock. If the net proceeds to
the Company from the Offering are not sufficient to exercise the MetLife
Louisiana Option in full, the Company would be able to exercise the MetLife
Louisiana Option only to the extent of the net proceeds from the Offering.

(b) The Company is involved in litigation with Tennessee Gas relating to a
natural gas sales contract. For additional information concerning this
dispute, see "Investment Considerations," "Legal Proceedings -- Tennessee
Gas Contract" and Notes K and P of Notes to Consolidated Financial
Statements.

(c) Interest expense in 1993 is net of a $5.2 million credit for settlement of
several state tax issues (see Note H of Notes to Consolidated Financial
Statements). Excluding this credit, interest expense for 1993 would have
been $19.7 million.

(d) No tax effect has been reflected in the adjustments to the Pro Forma
Statements of Condensed Consolidated Operations, as the Company has
provided a 100% valuation allowance to the extent of its net deferred tax
assets.

(e) In February 1994, the Company consummated exchange offers and adopted
amendments to its Restated Certificate of Incorporation pursuant to which
the Company's outstanding debt and preferred stock were restructured. A
description of the significant components of this Recapitalization,
together with the applicable accounting effects, follows:

Subordinated Debentures in the principal amount of $44.1 million were
tendered in exchange for a like principal amount of new Exchange Notes,
which satisfied the 1994 sinking fund requirement and, except for $.9
million, will satisfy sinking fund requirements for the Subordinated
Debentures through 1997. The Exchange Notes bear interest at 13% per annum,
are scheduled to mature on December 1, 2000 and have no sinking fund
requirements. The exchange resulted in an extraordinary loss of $4.8
million representing the excess of the market value of the Exchange Notes
over the carrying value of the Subordinated Debentures, increased by the
applicable unamortized debt issuance costs. Interest and other expense is
assumed to decrease by $.1 million for the Subordinated Debentures retired
and increased by $.1 million for the Exchange Notes issued.

The 1,319,563 outstanding shares of $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 and to pay $500,000 for
certain of their legal fees and expenses in connection with the settlement
of litigation related to the reclassification. The court awarded $500,000
and 73,913 shares of Common Stock for such legal fees and expenses, with
the remainder of the 131,956 shares to be issued to the former holders of
$2.16 Preferred Stock upon the court's orders becoming final and
nonappealable. A portion of the shares to be issued to the former holders
of $2.16 Preferred Stock may be awarded to counsel retained by a party
objecting to the settlement.

The Company and MetLife Louisiana, the holder of all the Company's
outstanding $2.20 Preferred Stock, entered into the Amended MetLife
Memorandum pursuant to which MetLife Louisiana agreed to waive all existing
mandatory redemption requirements of the $2.20 Preferred Stock, to consider
all accrued and unpaid dividends thereon through February 9, 1994
(aggregating approximately $21.2 million) 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 the MetLife Louisiana Option, pursuant to which the
Company has the option to purchase, until February 9, 1997, all shares of
the $2.20 Preferred Stock and Common Stock held by MetLife Louisiana, all
in consideration for, among other things, the issuance by the Company to
MetLife Louisiana of 1,900,075 shares of Common Stock. Such additional
shares are also subject to the MetLife Louisiana Option. Until June 30,
1994, the option exercise price is approximately $53.0 million, after
giving effect to a reduction in the option price for the cash dividend paid
on the $2.20 Preferred Stock in May 1994. The unexercised option price will
be increased by 3% on the last day of each calendar quarter until

F-6
<PAGE> 69

December 31, 1995, and by 3 1/2% on the last day of each quarter
thereafter, and will be reduced by cash dividends paid on the $2.20
Preferred Stock after February 9, 1994. The Company will be required to pay
dividends (in either cash or Common Stock) when due on the $2.20 Preferred
Stock in order for the MetLife Louisiana Option to remain outstanding. In
addition, the MetLife Louisiana Option is subject to certain minimum
exercise requirements to remain outstanding beyond one year and two years;
however, even if the net proceeds of the Offering are not sufficient to
exercise the MetLife Louisiana Option in full, such net proceeds will be
sufficient to satisfy all of the minimum exercise requirements.

Had the Recapitalization occurred on January 1, 1993, the extraordinary
loss on early extinguishment of debt would have been recognized during 1993
and preferred stock dividend requirements for the three months ended March
31, 1994 would have been reduced by approximately $308,000. There would be
no other significant pro forma adjustments for such period.

(f) Under the Offering, shares of outstanding capital stock of the Company are
assumed to change as follows:

<TABLE>
<CAPTION>
COMMON STOCK $2.20 PREFERRED STOCK
OUTSTANDING OUTSTANDING
------------ ---------------------
<S> <C> <C>
Offering......................................... 5,000,000 --
Exercise of MetLife Louisiana Option............. (4,084,160) (2,875,000)
------------ ----------
Net Increase (Decrease).......................... 915,840 (2,875,000)
------------ ----------
------------ ----------
</TABLE>

The Company's primary shares outstanding on a pro forma basis will increase
by 915,840 shares. Fully diluted shares will be reduced by a net 1,584,260
shares as a result of the exercise of the MetLife Louisiana Option to
reacquire the $2.20 Preferred Stock, each share of which is convertible by
its terms into .8696 shares of Common Stock, or an aggregate of 2,500,100
shares of Common Stock. The reacquisition of the $2.20 Preferred Stock
under the MetLife Louisiana Option would have eliminated the preferred
dividend requirements aggregating $6.3 million for the year ended December
31, 1993 and $1.6 million for the three months ended March 31, 1994.

(g) Had the Recapitalization occurred on January 1, 1993, the Historical
weighted average shares of Common Stock issued and outstanding for the
three months ended March 31, 1994 would have been approximately 23,232,000
shares, reflecting the pro forma issuance for the entire three month period
ended March 31, 1994 of the 6,465,859 shares, the 131,956 shares and the
1,900,075 shares referred to in (e) above.

(h) Includes the Recapitalization, which was consummated in February 1994.

(i) Current Liabilities exclude $6.1 million current portion of long-term debt
and other obligations, which amount is included in the respective line
item.

(j) The change in cash and short-term investments on a pro forma basis related
to the Offering result from the following (in thousands):

<TABLE>
<S> <C>
Offering............................................................. $ 57,500
Expenses Related to Offering......................................... (3,500)
Payment of Dividend in May 1994...................................... (1,581)
Exercise of MetLife Louisiana Option................................. (52,952)
--------
Decrease in Cash and Short-Term Investments.......................... $ (533)
--------
--------
</TABLE>

(k) The changes in Common Stock and Other Stockholders' Equity on a pro forma
basis result from the following (in thousands):

<TABLE>
<CAPTION>
$2.20 ADDITIONAL
PREFERRED COMMON PAID-IN
STOCK STOCK CAPITAL TOTAL
--------- ------ ---------- ----------
<S> <C> <C> <C> <C>
Offering................................... $ -- $ 833 $ 56,667 $ 57,500
Expenses Related to Offering............... -- -- (3,500) (3,500)
Payment of Dividend in May 1994............ -- -- (1,581) (1,581)
Exercise of MetLife Louisiana Option....... (57,500) (681 ) 5,229 (52,952)
--------- ------ ---------- ----------
Increase (Decrease) in Common Stock and
Other
Stockholders' Equity..................... $ (57,500) $ 152 $ 56,815 $ (533)
--------- ------ ---------- ----------
--------- ------ ---------- ----------
</TABLE>

F-7
<PAGE> 70

INDEPENDENT AUDITORS' REPORT

Board of Directors and Stockholders
Tesoro Petroleum Corporation

We have audited the accompanying consolidated balance sheets of Tesoro
Petroleum Corporation and subsidiaries as of December 31, 1993 and 1992, and the
related consolidated statements of operations, common stock and other
stockholders' equity and cash flows for the years ended December 31, 1993,
December 31, 1992 and September 30, 1991 and for the three-month period ended
December 31, 1991. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of Tesoro Petroleum Corporation
and subsidiaries at December 31, 1993 and 1992, and the results of their
operations and their cash flows for the years ended December 31, 1993, December
31, 1992 and September 30, 1991 and for the three-month period ended December
31, 1991, in conformity with generally accepted accounting principles.

As discussed in Note A of Notes to Consolidated Financial Statements, in
1992 the Company changed its method of accounting for postretirement benefits
other than pensions and accounting for income taxes.

DELOITTE & TOUCHE

San Antonio, Texas
February 10, 1994

F-8
<PAGE> 71

TESORO PETROLEUM CORPORATION

STATEMENTS OF CONSOLIDATED OPERATIONS
(DOLLARS IN THOUSANDS EXCEPT PER SHARE AMOUNTS)

THREE THREE MONTHS
MONTHS YEARS ENDED ENDED
YEAR ENDED ENDED DECEMBER 31, MARCH 31,
SEPTEMBER 30, DECEMBER 31, -------------------- --------------------
1991 1991 1992 1993 1993 1994
------------- ------------ ------- ------- ------- -------
(UNAUDITED)
<S> <C> <C> <C> <C> <C> <C>

Revenues:
Gross operating revenues............. $1,084,954 240,586 946,446 831,007 224,494 189,087
Interest income...................... 4,209 682 3,170 1,803 451 523
Gain on sales of assets.............. 119 9 4,024 60 48 2,680
Other................................ 1,734 2,596 732 2,040 1,488 450
---------- ------- ------- ------- ------- -------
Total Revenues............... 1,091,016 243,873 954,372 834,910 226,481 192,740
---------- ------- ------- ------- ------- -------
Costs and Expenses:
Costs of sales and operating
expenses.......................... 1,015,859 228,569 926,082 756,764 213,737 167,605
General and administrative........... 17,003 2,849 25,849 16,712 3,423 3,627
Depreciation, depletion and
amortization...................... 15,005 4,225 16,552 22,591 4,822 6,677
Interest expense..................... 18,804 4,966 21,115 14,550 5,013 4,877
Other................................ 5,312 722 4,636 5,640 1,663 1,191
---------- ------- ------- ------- ------- -------
Total Costs and Expenses..... 1,071,983 241,331 994,234 816,257 228,658 183,977
---------- ------- ------- ------- ------- -------
Earnings (Loss) Before Income Taxes,
the Cumulative Effect of Accounting
Changes and Extraordinary Loss on
Extinguishment of Debt............... 19,033 2,542 (39,862) 18,653 (2,177) 8,763
Income Tax Provision................... 15,094 2,958 5,383 1,697 732 1,561
---------- ------- ------- ------- ------- -------
Earnings (Loss) Before the Cumulative
Effect of Accounting Changes and
Extraordinary Loss on Extinguishment
of Debt.............................. 3,939 (416) (45,245) 16,956 (2,909) 7,202
Cumulative Effect of Accounting
Changes.............................. -- -- (20,630) -- -- --
Extraordinary Loss on Extinguishment of
Debt................................. -- -- -- -- -- (4,752)
---------- ------- ------- ------- ------- -------
Net Earnings (Loss).................... $ 3,939 (416) (65,875) 16,956 (2,909) 2,450
---------- ------- ------- ------- ------- -------
---------- ------- ------- ------- ------- -------
Net Earnings (Loss) Applicable to
Common Stock......................... $ (5,268) (2,717) (75,082) 7,749 (5,211) 561
---------- ------- ------- ------- ------- -------
---------- ------- ------- ------- ------- -------
Earnings (Loss) Per Primary and Fully
Diluted* Share:
Earnings (Loss) Before the Cumulative
Effect of Accounting Changes and
Extraordinary Loss on
Extinguishment of Debt............ $ (.37) (.19) (3.87) .54 (.37) .27
Cumulative Effect of Accounting
Changes........................... -- -- (1.47) -- -- --
Extraordinary Loss on Extinguishment
of Debt........................... -- -- -- -- -- (.24)
---------- ------- ------- ------- ------- -------
Net Earnings (Loss).................. $ (.37) (.19) (5.34) .54 (.37) .03
---------- ------- ------- ------- ------- -------
---------- ------- ------- ------- ------- -------
Weighted Average Common and Common
Equivalent Shares (in thousands)..... 14,069 14,067 14,063 14,290 14,070 19,455
---------- ------- ------- ------- ------- -------
---------- ------- ------- ------- ------- -------
</TABLE>

- ---------------

* Anti-dilutive

The accompanying notes are an integral part of these consolidated financial
statements.

F-9
<PAGE> 72

TESORO PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS)

<TABLE>
<CAPTION>
DECEMBER 31,
--------------------- MARCH 31,
1992 1993 1994
-------- ------- -------
(UNAUDITED)
<S> <C> <C> <C>

ASSETS
Current Assets:
Cash and cash equivalents (includes restricted cash of
$0, $25,420 and $26,550, respectively, as collateral
for letters of credit)................................ $ 46,869 36,596 49,412
Short-term investments................................... 20,021 5,952 --
Receivables, less allowance for doubtful accounts of
$2,587, $2,487 and $2,419, respectively............... 77,173 69,637 59,487
Inventories:
Crude oil, refined products and merchandise........... 70,875 71,011 72,261
Materials and supplies................................ 3,636 3,175 3,142
Prepaid expenses and other............................... 9,803 10,136 9,870
-------- ------- -------
Total Current Assets............................. 228,377 196,507 194,172
-------- ------- -------
Property, Plant and Equipment:
Refining and marketing................................... 275,213 282,286 284,818
Exploration and production, full-cost method of
accounting:
Properties being amortized............................ 45,182 74,684 85,836
Properties not yet evaluated.......................... 1,482 1,959 2,472
Oil field supply and distribution........................ 16,365 15,413 14,872
Corporate................................................ 10,431 11,121 11,608
-------- ------- -------
348,673 385,463 399,606
Less accumulated depreciation, depletion and
amortization.......................................... 150,191 172,312 177,188
-------- ------- -------
Net Property, Plant and Equipment................ 198,482 213,151 222,418
-------- ------- -------
Other Assets:
Investment in Tesoro Bolivia Petroleum Company........... 2,786 6,310 6,823
Other.................................................... 17,077 18,554 18,696
-------- ------- -------
Total Other Assets............................... 19,863 24,864 25,519
-------- ------- -------
$446,722 434,522 442,109
-------- ------- -------
-------- ------- -------
</TABLE>

The accompanying notes are an integral part of these consolidated financial
statements.

F-10
<PAGE> 73

TESORO PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS EXCEPT PER SHARE AMOUNTS)

<TABLE>
<CAPTION>
DECEMBER 31,
--------------------- MARCH 31,
1992 1993 1994
-------- ------- -------
(UNAUDITED)
<S> <C> <C> <C>
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable....................................... $ 49,120 43,192 45,161
Accrued liabilities.................................... 30,387 24,017 32,623
Current portion of long-term debt and other
obligations......................................... 26,287 4,805 6,094
-------- ------- -------
Total Current Liabilities...................... 105,794 72,014 83,878
-------- ------- -------
Other Liabilities........................................ 43,107 45,272 35,277
-------- ------- -------
Long-Term Debt and Other Obligations, Less Current
Portion................................................ 175,461 180,667 178,856
-------- ------- -------
Commitments and Contingencies
$2.20 Redeemable Cumulative Convertible Preferred Stock
and Accrued Dividends; $1 stated value; 2,875,000
shares issued and outstanding; redemption and
liquidation value of $78,056 in 1993 ($71,731 in
1992).................................................. 71,695 78,051 --
-------- ------- -------
Common Stock and Other Stockholders' Equity:
Preferred stock, no par value, authorized 5,000,000
shares including redeemable preferred shares:
$2.20 Cumulative convertible preferred stock; $1
stated value; 2,875,000 shares issued and
outstanding; redemption and liquidation value of
$58,291........................................... -- -- 57,500
$2.16 Cumulative convertible preferred stock; $1
stated value; 1,319,563 shares issued and
outstanding; liquidation value of $42,134 in 1993
($39,283 in 1992)................................. 1,320 1,320 --
Common stock, par value $.16 2/3; authorized 50,000,000
shares; 14,071,040, 14,089,236 and 22,456,968 shares
issued and outstanding, respectively................ 2,345 2,348 3,743
Additional paid-in capital............................. 86,992 86,985 114,406
Retained earnings (deficit)............................ (39,647) (31,898) (31,337)
-------- ------- -------
51,010 58,755 144,312
Less deferred compensation............................. 345 237 214
-------- ------- -------
50,665 58,518 144,098
-------- ------- -------
$446,722 434,522 442,109
-------- ------- -------
-------- ------- -------
</TABLE>

The accompanying notes are an integral part of these consolidated financial
statements.

F-11
<PAGE> 74

TESORO PETROLEUM CORPORATION

STATEMENTS OF CONSOLIDATED COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY
(INFORMATION FOR THE THREE-MONTH PERIOD ENDED MARCH 31, 1994 IS UNAUDITED)
(DOLLARS IN THOUSANDS)

<TABLE>
<CAPTION>
$2.16 CUMULATIVE
$2.20 CUMULATIVE CONVERTIBLE
CONVERTIBLE PREFERRED STOCK COMMON STOCK ADDITIONAL RETAINED
PREFERRED STOCK -------------------- ------------------- PAID-IN EARNINGS DEFERRED
SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT CAPITAL (DEFICIT) COMPENSATION
-------- ------- --------- ------- --------- ------ -------- -------- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Balances at September 30,
1990................... -- $ -- 1,319,576 $ 1,320 14,059,952 $2,343 $ 86,608 $ 51,330 $(216)
Net earnings........... -- -- -- -- -- -- -- 3,939 --
Cash dividends on
preferred stocks..... -- -- -- -- -- -- -- (8,028) --
Stock awards........... -- -- -- -- 8,213 2 56 -- 51
Other.................. -- -- -- -- -- -- -- (32) --
--------- ------- ---------- ------- ---------- ------ -------- -------- -----
Balances at September 30,
1991................... -- -- 1,319,576 1,320 14,068,165 2,345 86,664 47,209 (165)
Net loss............... -- -- -- -- -- -- -- (416) --
Stock awards........... -- -- -- -- (1,120) (1) (6) -- 29
Other.................. -- -- -- -- -- -- -- (8) --
--------- ------- ---------- ------- ---------- ------ -------- -------- -----
Balances at December 31,
1991................... -- -- 1,319,576 1,320 14,067,045 2,344 86,658 46,785 (136)
Net loss............... -- -- -- -- -- -- -- (65,875) --
Accrued dividends on
preferred stocks, not
declared or paid..... -- -- -- -- -- -- -- (20,525) --
Conversion of preferred
stock to common
stock................ -- -- (13) -- 22 -- -- -- --
Stock awards........... -- -- -- -- 4,095 1 334 -- (209)
Other.................. -- -- -- -- (122) -- -- (32) --
--------- ------- ---------- ------- ---------- ------ -------- -------- -----
Balances at December 31,
1992................... -- -- 1,319,563 1,320 14,071,040 2,345 86,992 (39,647) (345)
Net earnings........... -- -- -- -- -- -- -- 16,956 --
Accrued dividends on
preferred stocks, not
declared or paid..... -- -- -- -- -- -- -- (9,175) --
Stock awards........... -- -- -- -- 18,196 3 (7) -- 108
Other.................. -- -- -- -- -- -- -- (32) --
--------- ------- ---------- ------- ---------- ------ -------- -------- -----
Balances at December 31,
1993................... -- -- 1,319,563 1,320 14,089,236 2,348 86,985 (31,898) (237)
Net earnings........... -- -- -- -- -- -- -- 2,450 --
Reclassification of
$2.16 Preferred Stock
and accrued and
unpaid dividends
thereon into common
stock................ -- -- (1,319,563) (1,320) 6,465,859 1,077 9,692 -- --
Issuance of common
stock in connection
with reclassification
of $2.20 Preferred
Stock into equity
capital.............. 2,875,000 57,500 -- -- 1,900,075 317 20,914 -- --
Costs of
Recapitalization..... -- -- -- -- -- -- (3,185) -- --
Cash dividends on
preferred stocks..... -- -- -- -- -- -- -- (103) --
Accrued dividends on
preferred stocks..... -- -- -- -- -- -- -- (1,783) --
Other.................. -- -- -- -- 1,798 1 -- (3) 23
--------- ------- ---------- ------- ---------- ------ -------- -------- -----
Balances at March 31,
1994................... 2,875,000 $57,500 -- $ -- 22,456,968 $3,743 $114,406 $(31,337) $(214)
--------- ------- ---------- ------- ---------- ------ -------- -------- -----
--------- ------- ---------- ------- ---------- ------ -------- -------- -----
</TABLE>

The accompanying notes are an integral part of these consolidated financial
statements.

F-12
<PAGE> 75

TESORO PETROLEUM CORPORATION

STATEMENTS OF CONSOLIDATED CASH FLOWS
(DOLLARS IN THOUSANDS)

<TABLE>
<CAPTION>
YEAR ENDED THREE MONTHS YEARS ENDED THREE MONTHS
SEPTEMBER ENDED DECEMBER 31, ENDED MARCH 31,
30, DECEMBER 31, ---------------------- ---------------------
1991 1991 1992 1993 1993 1994
--------- ---------- ----------- --------- ---------- ---------
<S> <C> <C> <C> <C> <C> <C>
(UNAUDITED)
Cash Flows From (Used In)
Operating Activities:
Net earnings (loss)............................. $ 3,939 (416) (65,875) 16,956 (2,909) 2,450
Adjustments to reconcile net earnings (loss) to
net cash from (used in) operating activities:
Cumulative effect of accounting changes..... -- -- 20,630 -- -- --
Loss (gain) on extinguishment of debt....... -- -- -- (1,422) 4,752
Depreciation, depletion and amortization.... 15,005 4,225 16,552 22,591 4,822 6,677
Gain on sales of assets..................... (119 (9) (4,024) (60) (48) (2,680)
Other....................................... 2,704 599 4,231 1,901 662 361
Changes in assets and liabilities:
Receivables.............................. 33,531 6,524 12,320 7,539 3,520 11,151
Inventories.............................. (20,663 (10,620) 7,986 325 13,372 (1,217)
Investment in Tesoro Bolivia Petroleum
Company................................ (5,991 8,756 3,908 (3,524) 377 (513)
Other assets............................. 2,899 (4,748) 3,484 (2,435) 1,011 1,834
Accounts payable and other current
liabilities............................ (11,253 (3,877) (5,282) (12,800) 4,563 8,272
Obligation payments to State of
Alaska................................. -- -- -- (12,910) (10,797) (710)
Other liabilities and obligations........ (2,107 (774) 17,458 1,901 1,262 (118)
-------- ------- ------- ------- -------- --------
Net cash from (used in) operating
activities........................... 17,945 (340) 11,388 19,484 14,413 30,259
-------- ------- ------- ------- -------- --------
Cash Flows From (Used In)
Investing Activities:
Capital expenditures............................ (24,484 (3,858) (15,446) (37,451) (5,084) (18,475)
Proceeds from sales of assets, net of
expenses...................................... 2,087 35 12,905 194 107 2,014
Purchases of short-term investments............. -- -- (23,976) (26,245) (8,410) --
Sales of short-term investments................. -- -- 3,955 40,314 20,021 5,952
Other........................................... (2,298 1 1,478 (247) (206) 351
-------- ------- ------- ------- -------- --------
Net cash from (used in) investing
activities............................. (24,695 (3,822) (21,084) (23,435) 6,428 (10,158)
-------- ------- ------- ------- -------- --------
Cash Flows From (Used In) Financing Activities:
Repurchase of debentures...................... -- -- -- (9,675) (9,675) --
Payments of long-term debt.................... (1,272 (512) (6,468) (1,643) (211) (10,222)
Issuance of long-term debt.................... -- 3,000 2,024 5,000 -- 5,000
Dividends on preferred stocks................. (8,028 -- -- -- -- (103)
Other......................................... (25 (7) (20) )(4 )(5 (1,960)
-------- ------- ------- ------- -------- --------
Net cash from (used in) financing
activities........................... (9,325 2,481 (4,464) (6,322) (9,891) (7,285)
-------- ------- ------- ------- -------- --------
Increase (Decrease) in Cash and Cash
Equivalents..................................... (16,075 (1,681) (14,160) (10,273) 10,950 12,816
Cash and Cash Equivalents at Beginning of
Period.......................................... 78,785 62,710 61,029 46,869 46,869 36,596
-------- ------- ------- ------- -------- --------
Cash and Cash Equivalents
at End of Period................................ $ 62,710 61,029 46,869 36,596 57,819 49,412
-------- ------- ------- ------- -------- --------
-------- ------- ------- ------- -------- --------
Supplemental Cash Flow Disclosures:
Interest paid................................... $ 17,839 234 17,805 19,288 8,477 7,105
Income taxes paid............................... $ 13,694 3,425 6,446 5,125 755 961
</TABLE>

The accompanying notes are an integral part of these consolidated financial
statements.

F-13
<PAGE> 76

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(INFORMATION FOR THE THREE-MONTH PERIODS ENDED MARCH 31, 1993 AND 1994 IS
UNAUDITED)

NOTE A -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Presentation

The Consolidated Financial Statements include the accounts of Tesoro
Petroleum Corporation and its subsidiaries (collectively the "Company" or
"Tesoro") after elimination of significant intercompany balances and
transactions. Certain prior period amounts have been reclassified to conform
with the 1993 presentation.

Effective January 1, 1992, the Company changed its fiscal year-end from
September 30 to December 31. Unless otherwise indicated, the information
contained herein addresses the Company's results of operations for the year
ended December 31, 1993, compared to the year ended December 31, 1992 and the
year ended September 30, 1991 and its financial condition as of December 31,
1993 and December 31, 1992. The results of operations for the three-month period
ended December 31, 1991 are discussed separately.

Interim Reporting

The interim consolidated financial statements are unaudited but, in the
opinion of management, incorporate all adjustments necessary for a fair
presentation of the Company's financial position and results of operations for
such interim periods. Such adjustments are of a normal recurring nature. The
results of operations for any interim period are not necessarily indicative of
results for the full year.

Cash and Cash Equivalents and Short-Term Investments

The Company considers all highly liquid investments purchased with a
maturity of three months or less to be cash equivalents. During 1992, the
Company began investing in short-term debt securities with original maturities
in excess of 90 days. These investments are classified as short-term investments
in the Company's Consolidated Balance Sheets. Cash equivalents and short-term
investments are stated at cost, which approximates market value. For information
regarding restricted cash, see Note I.

Inventories

The Company follows the lower of cost (last-in, first-out basis -- LIFO) or
market method for valuing inventories of crude oil and wholesale refined
products. All other inventories are valued principally at the lower of cost
(generally on a first-in, first-out or weighted average basis) or market.

Futures and Options Hedge Contracts

The Company uses commodity futures and options contracts primarily to hedge
the impact of price fluctuations on anticipated purchases of crude oil. Gains
and losses on commodity futures and options hedge contracts are deferred until
recognized in income when the related crude oil is charged to costs of sales.

Property, Plant and Equipment

The Company uses the full-cost method of accounting for oil and gas
properties. Under this method, all costs associated with property acquisition
and exploration and development activities are capitalized into cost centers
that are established on a country-by-country basis. For each cost center, the
capitalized costs are subject to a limitation so as not to exceed the present
value of future net revenues from estimated production of proved oil and gas
reserves net of income tax effect plus the lower of cost or estimated fair value
of unproved properties included in the cost center. Capitalized costs within a
cost center, together with estimates of costs for future development,
dismantlement and abandonment, are amortized on a unit-of-production method
using the proved oil and gas reserves for each cost center. The Company's
investment in certain oil and gas properties is excluded from the amortization
base until the properties are evaluated. No gain or loss is

F-14
<PAGE> 77

recognized on the sale of oil and gas properties except in the case of the sale
of properties involving significant remaining reserves. Proceeds from the sale
of insignificant reserves and undeveloped properties are applied to reduce the
costs in the cost centers.

Assets recorded under capital leases have been capitalized in accordance
with promulgations from the Financial Accounting Standards Board. Amortization
of such assets is recorded over the shorter of lease terms or useful lives under
methods which are consistent with the Company's depreciation policy for owned
assets.

Depreciation of other property is provided using primarily the
straight-line method with rates based on the estimated useful lives of the
properties and with an estimated salvage value of 20% for refinery assets and
generally 10% for other assets. Amortization of leasehold improvements is
provided using the straight-line method over the term of the respective lease or
the useful life of the asset, whichever period is less.

Postretirement Benefits Other Than Pensions

The Company accounts for postretirement benefits other than pensions in
accordance with Statement of Financial Accounting Standards No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions" ("SFAS No. 106").
The projected future cost of providing postretirement benefits other than
pensions, such as health care and life insurance, are expensed as employees
render service instead of when benefits are paid. Prior to the adoption of SFAS
No. 106, the Company had expensed these benefits on a pay-as-you-go basis. The
adoption of SFAS No. 106, effective January 1, 1992, resulted in a net charge of
$21.6 million, or $1.54 per share, for the cumulative effect of the change in
accounting principle for periods prior to 1992, which were not restated. In
addition, the adoption of SFAS No. 106 resulted in an increase of $1.2 million,
or $.09 per share, in the 1992 net loss before cumulative effect of accounting
changes.

Income Taxes

The Company accounts for income taxes in accordance with Statement of
Financial Accounting Standards No. 109, "Accounting for Income Taxes" ("SFAS No.
109"). Deferred tax assets and liabilities are recognized for future tax
consequences attributable to differences between financial statement carrying
amounts of existing assets and liabilities and their respective tax bases.
Measurement of deferred tax assets and liabilities is based on enacted tax rates
expected to apply to taxable income in the years in which those temporary
differences are expected to be recovered or settled. Under SFAS No. 109, the
effect on deferred tax assets and liabilities of a change in tax rates is
recognized in income in the period that includes the enactment date. The Company
adopted SFAS No. 109 effective January 1, 1992 by recognizing a net benefit of
$1.0 million, or $.07 per share, for the cumulative effect of the accounting
change. Periods prior to 1992 were not restated. The adoption of SFAS No. 109
did not have a significant effect on 1992 results of operations.

Environmental Expenditures

Environmental expenditures that relate to current operations are expensed
or capitalized as appropriate. Expenditures that relate to an existing condition
caused by past operations, and which do not contribute to current or future
revenue generation, are expensed. Liabilities are recorded when environmental
assessments and/or remedial efforts are probable, and the cost can be reasonably
estimated. Generally, the timing of these accruals coincides with completion of
a feasibility study or the Company's commitment to a formal plan of action.

Deferred Compensation

Deferred compensation represents the excess of market value over the sales
price of restricted common stock awarded to certain employees of the Company.
The deferred compensation is being amortized over the period from the date of
award to the dates the shares become unrestricted (the period for which the
payment for services is being made).

F-15
<PAGE> 78

Earnings (Loss) Per Share

Primary earnings (loss) per share is calculated on net earnings (loss)
after deducting dividend requirements on preferred stocks and is based on the
weighted average number of common and common equivalent shares outstanding
during the period. Fully diluted earnings (loss) per share is the same as
primary earnings (loss) per share since the assumed conversion of preferred
stocks to common shares would be anti-dilutive.

NOTE B -- RECAPITALIZATION

In February 1994, the Company consummated exchange offers and adopted
amendments to its Restated Certificate of Incorporation pursuant to which the
Company's outstanding debt and preferred stock were restructured (the
"Recapitalization"). The Recapitalization has significantly improved the
Company's capital structure.

The significant components of the Recapitalization, together with the
applicable accounting effects, were as follows:

- The Company exchanged $44.1 million principal amount of new 13% Exchange
Notes ("Exchange Notes") due December 1, 2000 for a like principal amount
of 12 3/4% Subordinated Debentures ("Subordinated Debentures") due March
15, 2001. This exchange satisfied the 1994 sinking fund requirement and,
except for $.9 million, will satisfy sinking fund requirements for the
Subordinated Debentures through 1997.

The exchange of the Subordinated Debentures was accounted for as an
early extinguishment of debt in the first quarter of 1994, resulting in
a charge of $4.8 million as an extraordinary loss on this transaction,
which represented the excess of the estimated market value of the
Exchange Notes over the carrying value of the Subordinated Debentures.
The carrying value of the Subordinated Debentures exchanged was reduced
by applicable unamortized debt issue costs. No tax benefit was available
to offset the extraordinary loss as the Company has provided a 100%
valuation allowance to the extent of its deferred tax assets.

- The 1,319,563 outstanding shares of the Company's $2.16 Cumulative
Convertible Preferred Stock ("$2.16 Preferred Stock"), which had a $25
per share liquidation preference, plus accrued and unpaid dividends
aggregating $9.5 million at February 9, 1994, were reclassified into
6,465,859 shares of the Common Stock. The Company also agreed to issue up
to 131,956 shares of Common Stock on behalf of the holders of $2.16
Preferred Stock and to pay $500,000 for certain of their legal fees and
expenses in connection with the settlement of litigation related to the
reclassification. The court awarded $500,000 and 73,913 shares of Common
Stock for such legal fees and expenses, with the remainder of the 131,956
shares to be issued to the former holders of the $2.16 Preferred Stock
upon the court's orders becoming final and nonappealable. A portion of
the shares to be issued to the former holders of $2.16 Preferred Stock
may be awarded to counsel retained by a party objecting to the
settlement.

The issuance of the Common Stock in connection with the
reclassification and settlement of litigation that was recorded in 1994
resulted in an increase in Common Stock of approximately $1 million,
equal to the aggregate par value of the Common Stock issued, and an
increase in additional paid-in capital of approximately $9 million.

- The Company and MetLife Security Insurance Company of Louisiana ("MetLife
Louisiana"), the holder of all of the Company's outstanding $2.20
Cumulative Convertible Preferred Stock ("$2.20 Preferred Stock"), entered
into an agreement (the "Amended MetLife Memorandum") with regard to the
$2.20 Preferred Stock pursuant to which MetLife Louisiana agreed to waive
all existing mandatory redemption requirements, to consider all accrued
and unpaid dividends thereon (aggregating $21.2 million at February 9,
1994) to have been paid, to allow the Company to pay future dividends on
the $2.20 Preferred Stock in Common Stock in lieu of cash, to waive or
refrain from exercising certain other rights of the $2.20 Preferred Stock
and to grant to the Company a three-year option to purchase all of
MetLife Louisiana's holdings of $2.20 Preferred Stock and Common Stock
for approximately $53 million prior to June 30, 1994 after giving effect
to the cash dividend paid in May 1994, all in

F-16
<PAGE> 79

consideration for, among other things, the issuance by the Company to
MetLife Louisiana of 1,900,075 shares of Common Stock. Such additional
shares are subject to the option granted by MetLife Louisiana. The
unexercised option price will be increased by 3% on the last day of each
calendar quarter until December 31, 1995, and by 3 1/2% on the last day
of each quarter thereafter, and will be reduced by cash dividends paid on
the $2.20 Preferred Stock after February 9, 1994. The Company will be
required to pay dividends (in either cash or Common Stock) when due on
the $2.20 Preferred Stock in order for the option to remain outstanding.
In addition, the option is subject to certain minimum exercise
requirements to remain outstanding beyond one year and two years.

These actions have resulted in the reclassification of the $2.20 Preferred
Stock into equity capital at its aggregate liquidation preference of $57.5
million and the recording of an increase in additional paid-in capital of
approximately $21 million in February 1994.

The pro forma effects of the Recapitalization on the Company's results of
operations, assuming the Recapitalization had occurred on January 1, 1993, are
as follows (in millions except per share amounts):

<TABLE>
<CAPTION>
YEAR ENDED THREE MONTHS ENDED
DECEMBER 31, 1993 MARCH 31, 1994
------------------- ------------------
PRO PRO
HISTORICAL FORMA HISTORICAL FORMA
------- ------ ------ ------
<S> <C> <C> <C> <C>
(UNAUDITED) (UNAUDITED)
Total Revenues............................. $ 834.9 834.9 192.7 192.7
------- ------ ------ ------
------- ------ ------ ------
Earnings Before Extraordinary Loss......... $ 17.0 16.9 7.2 7.2
Extraordinary Loss......................... -- 4.8 4.8 --
------- ------ ------ ------
Net Earnings............................... 17.0 12.1 2.4 7.2
Preferred Stock Dividend Requirements...... 9.2 6.3 1.9 1.6
------- ------ ------ ------
Net Earnings Applicable to Common Stock.... $ 7.8 5.8 .5 5.6
------- ------ ------ ------
------- ------ ------ ------
Earnings (Loss) Per Primary and Fully
Diluted* Share:
Earnings Before Extraordinary Loss....... $ .54 .46 .27 .24
Extraordinary Loss....................... -- (.21) (.24) --
------- ------ ------ ------
Net Earnings............................. $ .54 .25 .03 .24
------- ------ ------ ------
------- ------ ------ ------
Average Common and Common Equivalent Shares
Outstanding (in thousands):
Primary.................................. 14,290 22,788 19,455 23,232
Fully Diluted............................ 19,065 25,288 23,018 25,809
</TABLE>

- ---------------
* Anti-dilutive

See Notes I, L and M for further information on the Company's long-term
debt and equity, including restrictions on dividend payments.

F-17
<PAGE> 80

NOTE C -- CHANGE IN FISCAL YEAR-END

The Company changed its fiscal year-end from September 30 to December 31,
effective January 1, 1992. The Statement of Consolidated Operations and the
Statement of Consolidated Cash Flows for the three months ended December 31,
1991 are presented in the accompanying Consolidated Financial Statements.
Comparative financial information is presented below (in thousands, except per
share amounts):

STATEMENTS OF CONSOLIDATED OPERATIONS

<TABLE>
<CAPTION>
THREE MONTHS ENDED
DECEMBER 31,
----------------------
1990 1991
-------- -------
(UNAUDITED)
<S> <C> <C>

Revenues:
Gross operating revenues........................................... $334,098 240,586
Interest income.................................................... 1,410 682
Gain on sales of assets............................................ 177 9
Other.............................................................. 499 2,596
-------- -------
Total Revenues............................................. 336,184 243,873
-------- -------
Costs and Expenses:
Costs of sales and operating expenses.............................. 312,047 228,569
General and administrative......................................... 4,033 2,849
Depreciation, depletion and amortization........................... 3,058 4,225
Interest expense................................................... 4,639 4,966
Other.............................................................. 761 722
-------- -------
Total Costs and Expenses................................... 324,538 241,331
-------- -------
Earnings before Income Taxes......................................... 11,646 2,542
Income Tax Provision................................................. 6,793 2,958
-------- -------
Net Earnings (Loss).................................................. $ 4,853 (416)
-------- -------
-------- -------
Net Earnings (Loss) Applicable to Common Stock....................... $ 2,552 (2,717)
-------- -------
-------- -------
Earnings (Loss) Per Primary and Fully Diluted* Share................. $ .18 (.19)
-------- -------
-------- -------
</TABLE>

- ---------------

* Anti-dilutive

F-18
<PAGE> 81

STATEMENTS OF CONSOLIDATED CASH FLOWS

<TABLE>
<CAPTION>
THREE MONTHS ENDED
DECEMBER 31,
---------------------------
1990 1991
----------- -----------
(UNAUDITED)
<S> <C> <C>

Cash Flows From (Used In) Operating Activities:
Net earnings (loss)............................................... $ 4,853 (416)
Adjustments to reconcile net earnings (loss) to net cash used in
operating activities:
Depreciation, depletion and amortization..................... 3,058 4,225
Gain on sales of assets...................................... (177) (9)
Other........................................................ 836 599
Changes in assets and liabilities:
Receivables............................................... 14,313 6,524
Inventories............................................... (24,687) (10,620)
Investment in Tesoro Bolivia Petroleum Company............ (4,383) 8,756
Other assets.............................................. (3,325) (4,748)
Accounts payable and other current liabilities............ (8,307) (3,877)
Other liabilities and obligations......................... 1,105 (774)
----------- -----------
Net cash used in operating activities..................... (16,714) (340)
----------- -----------
Cash Flows From (Used In) Investing Activities:
Capital expenditures.............................................. (6,136) (3,858)
Proceeds from sales of assets..................................... 692 35
Other............................................................. (829) 1
----------- -----------
Net cash used in investing activities..................... (6,273) (3,822)
----------- -----------
Cash Flows From (Used In) Financing Activities:
Payments of long-term debt........................................ (409) (512)
Issuance of long-term debt........................................ -- 3,000
Dividends on preferred stocks..................................... (2,294) --
Other............................................................. 2 (7)
----------- -----------
Net cash from (used in) financing activities.............. (2,701) 2,481
----------- -----------
Decrease in Cash and Cash Equivalents............................... (25,688) (1,681)
Cash and Cash Equivalents at Beginning of Period.................... 78,785 62,710
----------- -----------
Cash and Cash Equivalents at End of Period.......................... $ 53,097 61,029
----------- -----------
----------- -----------
Supplemental Cash Flow Disclosures:
Interest paid..................................................... $ 218 234
Income taxes paid................................................. $ 2,663 3,425
</TABLE>

NOTE D -- INVENTORIES

Inventories valued by the LIFO method amounted to approximately $65.6
million, $63.0 million and $63.7 million at March 31, 1994, December 31, 1993
and 1992, respectively. At March 31, 1994 and December 31, 1993, inventories
valued using LIFO approximated replacement cost. At December 31, 1992
inventories valued using LIFO were lower than replacement cost by approximately
$9.6 million.

NOTE E -- PROPERTY, PLANT AND EQUIPMENT

Effective May 1, 1992, the Company's subsidiaries, Tesoro Indonesia
Petroleum Company and Tesoro Tarakan Petroleum Company (collectively "Tesoro
Indonesia"), sold their 100% interest in two separate contracts of operations
with Pertamina, the state-owned petroleum company of Indonesia. The sales
included all of Tesoro Indonesia's interests in fixtures, wells, pipelines,
tanks, compressors, rigs and other equipment in

F-19
<PAGE> 82

the contract areas, and inventories of crude oil and materials and supplies. The
consideration received by Tesoro Indonesia totaled $6.6 million in cash and the
assumption by the purchaser of liabilities of approximately $6.3 million and all
remaining expenditure commitments. During 1992, these sales transactions
resulted in pretax net gains to the Company of approximately $5.8 million after
related expenses.

In 1992, the Company sold its corporate airplane and related assets for
$3.3 million in cash with no significant pretax gain to the Company. The Company
also sold certain oil and gas properties in South Texas for $2.1 million in
cash, which proceeds reduced the carrying value of the Company's oil and gas
properties and no gain or loss was recognized. In addition, the Company sold its
remaining drilling rigs for cash proceeds of $1.6 million resulting in a pretax
loss of $1.1 million during 1992.

In January 1994, the Company sold its terminal facilities in Valdez, Alaska
for cash proceeds of $2.0 million and a note receivable of $3.0 million, which
resulted in a pretax gain to the Company of approximately $2.8 million during
the three months ended March 31, 1994.

NOTE F -- INVESTMENT IN TESORO BOLIVIA PETROLEUM COMPANY

The Company's subsidiary, Tesoro Bolivia Petroleum Company ("Tesoro
Bolivia"), holds an interest in a joint venture agreement to explore for and
produce hydrocarbons in Bolivia. The joint venture has an agreement with the
Bolivian Government and YPFB, the Bolivian state-owned oil company, for
collection of receivables for sales of natural gas and condensate to YPFB, which
in turn sells the natural gas to the Republic of Argentina. The agreement
provides, among other things, that receipts from natural gas sales subsequent to
December 31, 1987 be placed in a restricted bank account ("Restricted Account")
from which only payments for investments and expenses in Bolivia can be made
until April 1992, or until cumulative deposits to the Restricted Account equal
$90.0 million. Cumulative deposits to the Restricted Account have totaled $90.0
million and receipts for natural gas sales are now free of restrictions to the
joint venture. The increase in the book value of this investment during 1993
represented earnings and cash invested in Tesoro Bolivia reduced by cash
received free of restrictions.

NOTE G -- ACCRUED LIABILITIES

The Company's current accrued liabilities as shown in the Consolidated
Balance Sheets include the following (in thousands):

<TABLE>
<CAPTION>
DECEMBER 31,
------------------- MARCH 31,
1992 1993 1994
------- ------ ---------
<S> <C> <C> <C>
(UNAUDITED)
Accrued Interest.................................... $14,401 5,185 1,950
Accrued Environmental Costs......................... 4,632 6,171 6,046
Accrued Product Taxes............................... 517 749 9,216
Other............................................... 10,837 11,912 15,411
------- ------ ------
Accrued Liabilities............................... $30,387 24,017 32,623
------- ------ ------
------- ------ ------
</TABLE>

Other liabilities classified as noncurrent in the Consolidated Balance
Sheets consist of the following (in thousands):

<TABLE>
<CAPTION>
DECEMBER 31,
------------------- MARCH 31,
1992 1993 1994
------- ------ ---------
<S> <C> <C> <C>
(UNAUDITED)
Accrued Postretirement Benefits..................... $25,088 27,270 26,432
Accrued Dividends on $2.16 Preferred Stock.......... 6,294 9,145 --
Deferred Income Taxes............................... 7,402 3,792 3,912
Other............................................... 4,323 5,065 4,933
------- ------ ------
Other Liabilities................................. $43,107 45,272 35,277
------- ------ ------
------- ------ ------
</TABLE>

F-20
<PAGE> 83

NOTE H -- INCOME TAXES

The income tax provision includes the following (in thousands):

THREE THREE MONTHS
YEAR MONTHS YEARS ENDED ENDED
ENDED ENDED DECEMBER 31, MARCH 31,
SEPTEMBER 30, DECEMBER 31, ----------------- --------------
1991 1991 1992 1993 1993 1994
------------- ------------ ----- ------ --- -----
(UNAUDITED)
<S> <C> <C> <C> <C> <C> <C>

Federal:
Current........................... $ 455 -- 418 -- -- 200
Deferred.......................... (201) 80 (454) -- -- --
Foreign............................. 14,661 2,826 5,104 3,419 749 761
State............................... 179 52 315 (1,722) (17) 600
------- ----- ----- ------ --- -----
$15,094 2,958 5,383 1,697 732 1,561
------- ----- ----- ------ --- -----
------- ----- ----- ------ --- -----
</TABLE>

During 1993, the Company resolved several outstanding issues with state
taxing authorities resulting in a reduction of $3.0 million in state income tax
expense and $5.2 million in related interest expense.

Deferred income taxes and benefits are provided for differences between
financial statement carrying amounts of existing assets and liabilities and
their respective tax bases. Temporary differences and the resulting deferred tax
assets and liabilities are summarized as follows (in thousands):

<TABLE>
<CAPTION>
DECEMBER 31, MARCH
--------------------- 31,
1992 1993 1994
-------- ------- -------
(UNAUDITED)
<S> <C> <C> <C>

Deferred Tax Assets:
Net operating losses available for utilization
through the year 2008....................... $ 21,501 24,890 21,823
Settlement with the State of Alaska............ 24,476 21,583 21,583
Accrued postretirement benefits................ 6,947 8,359 8,359
Settlement with Department of Energy........... 4,616 4,443 4,443
Other.......................................... 12,137 7,220 7,005
-------- ------- -------
Total Deferred Tax Assets.............. 69,677 66,495 63,213
Deferred Tax Liabilities:
Accelerated depreciation and property-related
items....................................... (42,475) (45,965) (46,261)
-------- ------- -------
Deferred Tax Assets Before Valuation Allowance... 27,202 20,530 16,952
Valuation Allowance.............................. (27,202) (20,530) (16,952)
Other............................................ (6,660) (442) (250)
State Income and Alternative Minimum Taxes....... (742) (3,350) (3,662)
-------- ------- -------
Net Deferred Tax Liability..................... $ (7,402) (3,792) (3,912)
-------- ------- -------
-------- ------- -------
</TABLE>

F-21
<PAGE> 84

The following table sets forth the components of the Company's results of
operations and a reconciliation of the normal statutory federal income tax with
the provision for income taxes (in thousands):

<TABLE>
<CAPTION>
THREE
YEAR ENDED MONTHS YEARS ENDED THREE MONTHS
ENDED ENDED DECEMBER 31, ENDED MARCH 31,
SEPTEMBER 30, DECEMBER 31, ----------------- ---------------
1991 1991 1992 1993 1993 1994
------------- ------------ ------- ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
(UNAUDITED)
Earnings (Loss) Before Income Taxes,
the Cumulative Effect of Accounting
Changes and Extraordinary Loss on
Extinguishment of Debt:
United States....................... $(15,581) (4,493) (60,117) 10,906 (3,153) 6,874
Foreign............................. 34,614 7,035 20,255 7,747 976 1,889
-------- ------ ------- ------ ------ ------
$ 19,033 2,542 (39,862) 18,653 (2,177) 8,763
-------- ------ ------- ------ ------ ------
-------- ------ ------- ------ ------ ------
Income Taxes at Statutory U.S.
Corporate Tax Rate.................. $ 6,471 864 (13,553) 6,529 (740) 3,067
Effect of:
Foreign income taxes, net of U.S.
tax benefit...................... 14,661 2,826 5,104 3,419 749 761
State income taxes (benefit), net of
U.S. tax benefit................. 179 52 315 (1,722) -- 600
Accounting limitation (recognition)
of an operating loss tax
benefit.......................... -- -- 13,553 (6,529) 740 --
Utilization of net operating loss
carryforwards.................... (6,471) (864) -- -- -- (3,067)
Alternative minimum tax............. 455 -- -- -- -- 200
Other............................... (201) 80 (36) -- (17) --
-------- ------ ------- ------ ------ ------
Income Tax Provision............. $ 15,094 2,958 5,383 1,697 732 1,561
-------- ------ ------- ------ ------ ------
-------- ------ ------- ------ ------ ------
</TABLE>

At December 31, 1993, the Company's net operating loss carryforwards were
approximately $71.1 million for regular tax and approximately $56.1 million for
alternative minimum tax. These tax loss carryforwards are available for future
years and, if not used, will begin to expire in the year 2004. Also at December
31, 1993, the Company had approximately $8.2 million of investment tax credits
and employee stock ownership credits available for carryover to subsequent
years. These credits, if not used, will begin to expire in the year 2001.

If the Company has an "ownership change" as defined by the Internal Revenue
Code of 1986, the Company's use of its net operating loss carryforwards and
general business credits after such ownership change will be subject to an
annual limit. Under certain interpretations of existing Internal Revenue Service
(IRS) regulations, the Recapitalization, as discussed in Note B, resulted in an
ownership change. The Company has taken the position that an ownership change
under existing law did not occur prior to the recapitalization and did not occur
as a result thereof. Because there are substantial interpretive questions
concerning such IRS regulations and there is uncertainty as to events which may
occur after the Recapitalization, there can be no assurance that an ownership
change did not occur as a result of the Recapitalization or will not occur as a
result of future events. If an ownership change is ultimately deemed to have
occurred at the time of the Recapitalization, the Company's use of its net
operating loss carryforwards and general business credits at February 9, 1994
would be limited to approximately $14.5 million per year.

F-22
<PAGE> 85

NOTE I -- LONG-TERM DEBT AND OTHER OBLIGATIONS

Long-term debt and other obligations consist of the following (in
thousands):

<TABLE>
<CAPTION>
DECEMBER 31, MARCH
--------------------- 31,
1992 1993 1994
-------- ------- -------
(UNAUDITED)
<S> <C> <C> <C>
12 3/4% Subordinated Debentures due 2001................... $107,510 98,154 58,580
13% Exchange Notes due 2000................................ -- -- 44,116
Liability to State of Alaska............................... 71,989 61,666 61,656
Liability to Department of Energy.......................... 13,194 13,194 13,194
Exploration and Production Loan............................ -- 5,000 --
Industrial Revenue Bonds................................... 3,483 2,752 2,752
Capital Lease Obligations (interest at 11%)................ 4,368 3,934 3,983
Other...................................................... 1,204 772 669
-------- ------- -------
201,748 185,472 184,950
Less Current Portion....................................... 26,287 4,805 6,094
-------- ------- -------
$175,461 180,667 178,856
-------- ------- -------
-------- ------- -------
</TABLE>

Based on the closing market price, the fair value of the Subordinated
Debentures, exclusive of accrued interest, was approximately $108.3 million at
December 31, 1993 and approximately $64.6 million at March 31, 1994 and the fair
value of the Exchange Notes, exclusive of accrued interest, was approximately
$44.9 million at March 31, 1994. The carrying value of the other long-term debt
and obligations approximated the Company's estimate of the fair value of such
items.

As discussed in Note B, approximately four years of sinking fund
requirements on the Subordinated Debentures were satisfied by the exchange offer
included in the Recapitalization. After giving effect to the Recapitalization,
sinking fund requirements and aggregate maturities of long-term debt and
obligations for each of the five years following December 31, 1993 are as
follows (in thousands):

<TABLE>
<CAPTION>
SINKING
AGGREGATE FUND
MATURITIES REQUIREMENTS TOTAL
---------- ------------ ------
<S> <C> <C> <C>
1994.............................................. $ 4,805 -- 4,805
1995.............................................. $ 5,750 -- 5,750
1996.............................................. $12,279 -- 12,279
1997.............................................. $ 7,412 884 8,296
1998.............................................. $ 7,395 11,250 18,645
</TABLE>

Letter of Credit Requirements

On October 29, 1993, the Company elected to terminate its secured Letter of
Credit Facility Agreement ("Credit Facility") dated July 27, 1989, which was
scheduled to expire in March 1994 and which provided for the issuance of up to
$40 million in letters of credit at the date of termination. In the latter half
of 1993, the Company negotiated several interim credit arrangements
collateralized by either cash or inventory to permit the Company to secure the
purchases of crude oil feedstocks and to meet other operating and corporate
credit requirements. With respect to these interim credit arrangements, the
Company has entered into several uncommitted letter of credit facilities which
provide for the issuance of letters of credit on a cash-secured basis. Total
availability pursuant to the uncommitted letter of credit arrangements was in
excess of $80 million at March 31, 1994.

At December 31, 1993, the Company had arranged for the issuance of $25
million of outstanding letters of credit which were secured by restricted cash
deposits. At 1992 year-end, under the terms of the previous Credit Facility, the
Company was required to maintain a minimum $30 million cash balance and
specified levels of equity and working capital.

F-23
<PAGE> 86

In addition, effective September 30, 1993, the Company entered into a
waiver and substitution of collateral agreement ("Substitution Agreement") with
the State of Alaska, the Company's largest supplier of crude oil. Under the
Substitution Agreement, the Company pledged the capital stock of Tesoro Alaska
Petroleum Company ("Tesoro Alaska"), a wholly-owned subsidiary of the Company,
and substantially all of its crude oil and refined product inventory in Alaska
to secure its purchases of royalty crude oil. The Substitution Agreement allowed
the Company to reduce its letter of credit requirements to $25 million as of
December 31, 1993. This agreement extended through January 1, 1995 and contained
various covenants and restrictions customary to inventory financing
transactions.

At March 31, 1994 and December 31, 1993, the Company had restricted cash of
$26.6 million and $25.4 million, respectively, for use as collateral for
outstanding letters of credit under the interim financing arrangements.

Exploration and Production Financing

Effective October 29, 1993, Tesoro Exploration and Production Company
("Tesoro E&P"), a wholly-owned subsidiary of the Company, entered into a $30
million reducing revolving credit facility ("E&P Facility") secured by the
capital stock of Tesoro E&P and its natural gas properties in the Bob West Field
in South Texas. At December 31, 1993, $5.0 million was outstanding under this
facility.

The E&P Facility, which was scheduled to expire December 31, 1996, was
guaranteed by the Company, contained certain financial covenants that were to be
maintained by Tesoro E&P and bore interest at prime plus 1% per annum or, at
Tesoro E&P's option, Libor plus 2.5% per annum. The E&P Facility contains
restrictions that prohibit borrowings under the facility to be used by Tesoro
E&P or the Company for debt service, including interest and principal on the
Company's 12 3/4% Subordinated Debentures, or for payment of common or preferred
dividends.

Revolving Credit Facility

Letters of credit available under the Revolving Credit Facility are limited
to a borrowing base calculation. As of May 13, 1994, the borrowing base, which
is comprised of eligible accounts receivable, inventory and domestic oil and gas
reserves, was approximately $91 million. As of May 13, 1994, the Company had
outstanding letters of credit under the new facility of $34 million, with a
remaining unused availability of $57 million. Cash borrowings are limited to the
amount of the oil and gas reserve component of the borrowing base, which has
initially been determined to be approximately $32 million. Cash borrowings under
the Revolving Credit Facility will reduce the availability of letters of credit
on a dollar-for-dollar basis; however, letter of credit issuances will not
reduce cash borrowing availability unless the aggregate dollar amount of
outstanding letters of credit exceeds the sum of the accounts receivable and
inventory components of the borrowing base.

Under the terms of the Revolving Credit Facility, the Company is required
to maintain specified levels of working capital, tangible net worth and cash
flow. Among other matters, the Revolving Credit Facility has certain
restrictions with respect to (i) capital expenditures, (ii) incurrence of
additional indebtedness, and (iii) dividends on capital stock. The Revolving
Credit Facility contains other covenants customary in credit arrangements of
this kind.

F-24
<PAGE> 87

arrangements that were cancelled in conjunction with the completion of the new
Revolving Credit Facility included the E&P Facility and the Substitution
Agreement discussed above. In addition, the completion of the Revolving Credit
Facility provides the Company significant flexibility in the investment of
excess cash balances, as the Company is no longer required to maintain minimum
cash balances or to cash secure letters of credit.

During May 1994, the National Bank of Alaska and the Alaska Industrial
Development & Export Authority agreed to provide a loan to the Company of up to
$15 million of the $24 million cost of the vacuum unit for the Refinery (the
"Vacuum Unit Loan"). The Vacuum Unit Loan will mature on January 1, 2002, will
require 28 equal quarterly payments beginning April 1, 1995 and will bear
interest at the unsecured 90-day commercial paper rate, adjusted quarterly, plus
2.6% per annum for two-thirds of the amount borrowed and at the National Bank of
Alaska floating prime rate plus 1/4 of 1% per annum for the remainder. The
Vacuum Unit Loan is secured by a first lien on the Refinery.

12 3/4% Subordinated Debt and 13% Exchange Notes

In 1983, the Company issued $120 million of 12 3/4% Subordinated Debentures
at a price of 84.559% of the principal amount, due March 15, 2001. The
debentures are redeemable at the option of the Company at 100% of principal
amount plus accrued interest. Sinking fund payments sufficient to retire $11.25
million principal amount of debentures annually commenced on March 15, 1993. The
Company satisfied the initial sinking fund requirement by purchasing $11.25
million principal amount of debentures at market value on January 26, 1993. The
exchange of $44.1 million principal amount of Subordinated Debentures for
Exchange Notes in February 1994 satisfied the 1994 sinking fund requirement and,
except for $.9 million, satisfied sinking fund requirements for the Subordinated
Debentures through 1997 (see Note B). At March 31, 1994, December 31, 1993 and
December 31, 1992, subordinated debt amounted to $58.6 million (net of discount
of $6.0 million), $98.2 million (net of discount of $10.6 million) and $107.5
million (net of discount of $12.5 million), respectively. The indenture contains
restrictions on payment of dividends on the Company's common stock and purchases
or redemptions of common or preferred stocks. Due to losses which have been
incurred, as of December 31, 1993, the Company must generate approximately $131
million of future net earnings applicable to common stock or from the issuance
of capital stock before future dividends can be paid on common stock or before
purchases or redemptions can be made of common or preferred stocks.

As part of the Recapitalization discussed in Note B, in February 1994,
Subordinated Debentures in the principal amount of $44.1 million were exchanged
for a like amount of new 13% Exchange Notes. The Exchange Notes mature on
December 1, 2000, and have no sinking fund requirements. The Exchange Notes are
redeemable at the option of the Company at 100% of principal amount plus accrued
interest except that no optional redemption may be made unless an equal
principal amount of, or all the outstanding, Subordinated Debentures, are
concurrently redeemed. The Exchange Notes rank pari passu with the other senior
debt of the Company and with the Subordinated Debentures, and senior in right of
payment of the obligation to the State of Alaska (discussed below) and all other
subordinated indebtedness of the Company. The indenture governing the Exchange
Notes contains limitations on dividends which are less restrictive than the
limitation under the Subordinated Debentures. For information on the pro forma
effects of the exchange, see Note B.

State of Alaska

In January 1993, the Company and its subsidiary, Tesoro Alaska Petroleum
Company ("Tesoro Alaska"), entered into an agreement ("Agreement") with the
State of Alaska ("State") that settled Tesoro Alaska's contractual dispute with
the State. In addition to $62 million accrued through September 30, 1992, a
charge of $10.5 million for the settlement was included in the Company's
operations during the fourth quarter of 1992.

Under the Agreement, Tesoro Alaska paid the State $10.3 million in January
1993 and is obligated to make variable monthly payments to the State through
December 2001 based on a per barrel charge that is currently 16 cents and
increases 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. In January 2002, Tesoro

F-25
<PAGE> 88

Alaska is obligated to pay the State $60 million; provided, however, that such
payment may be deferred indefinitely by continuing the variable monthly payments
to the State beginning at 34 cents per barrel for 2002 and increasing one cent
per barrel annually thereafter. Variable monthly payments made after December
2001 will not reduce the $60 million obligation to the State. The imputed rate
of interest used by the Company on the $60 million obligation was 13%. The $60
million obligation is evidenced by a security bond, and the bond and the
throughput barrel obligations are secured by a second mortgage on the Company's
Alaska refinery. Tesoro Alaska's obligations under the Agreement and the
mortgage are subordinated to current and future senior debt of up to $175
million plus any indebtedness incurred in the future to improve the Company's
Alaska refinery.

The State's claim against Tesoro Alaska arose out of certain provisions in
present and past contracts with the State that required Tesoro Alaska to pay the
State additional retroactive amounts if the State prevailed in litigation
against the producers of North Slope crude oil ("Producers"). As a result of
settlements between the State and the Producers, the State claimed that the
royalty oil it sold Tesoro Alaska and others was undervalued to the extent that
the Producers undervalued their oil.

Department of Energy

A Consent Order entered into by the Company with the Department of Energy
("DOE") in 1989 settled all issues relating to the Company's compliance with
federal petroleum price and allocation regulations from 1973 through decontrol
in 1981. Through March 31, 1994, the Company had paid $41.7 million to the DOE
since 1989. The Company's remaining obligation is to pay $13.2 million,
exclusive of interest at 6%, over the next eight years.

Industrial Revenue Bonds and Other

The industrial revenue bonds mature in 1998 and require semiannual payments
of approximately $365,000. The bonds bear interest at a variable rate (4 1/2% at
December 31, 1993) which is equal to 75% of the National Bank of Alaska's prime
rate. The bonds are collateralized by the Company's Alaska refinery sulphur
recovery unit which had a carrying value of approximately $6.9 million at
December 31, 1993.

Capital Lease Obligations

The Company is the lessee of certain buildings and equipment under capital
leases with remaining lease terms of 4 to 25 years. These buildings and
equipment are used in the Company's convenience store operations in Alaska. The
assets and liabilities under capital leases are recorded at the present value of
the minimum lease payments. Property, plant and equipment at December 31, 1993
included assets held under capital leases of $6.0 million with a net book value
of $2.6 million.

NOTE J -- EMPLOYEE BENEFIT PLANS

Retirement Plan

For all eligible employees, the Company provides a qualified
noncontributory retirement plan. Plan benefits are based on years of service and
compensation. It is the Company's policy to fund costs accrued to the extent
such costs are tax deductible. The components of net pension expense (income)
for the Company's retirement plan are presented below (in thousands):

<TABLE>
<CAPTION>
YEARS ENDED
YEAR ENDED DECEMBER 31,
SEPTEMBER 30, -------------------
1991 1992 1993
------- ------ ------
<S> <C> <C> <C>
Service Costs....................................... $ 762 717 931
Interest Cost....................................... 3,482 3,492 3,513
Actual Return on Plan Assets........................ (7,646) (1,763) (5,695)
Net Amortization and Deferral....................... 3,167 (2,231) 1,488
------- ------ ------
Net Pension Expense (Income)...................... $ (235) 215 237
------- ------ ------
------- ------ ------
</TABLE>

F-26
<PAGE> 89

For the three months ended March 31, 1994, March 31, 1993 and December 31,
1991, net pension expense for the Company's retirement plan totaled $204,000,
$160,000 and $90,000, respectively.

In addition to the retirement plan pension expense above, during 1992 the
Company recognized a curtailment gain of $1.0 million for employee terminations
in conjunction with a cost reduction program.

The funded status of the Company's retirement plan and amounts included in
the Company's Consolidated Balance Sheets are set forth in the following table
(in thousands):

<TABLE>
<CAPTION>
DECEMBER 31,
SEPTEMBER 30, -------------------
1991 1992 1993
------- ------ ------
<S> <C> <C> <C>
Actuarial Present Value of Benefit Obligation:
Vested benefit obligation......................... $33,959 34,806 41,200
------- ------ ------
------- ------ ------
Accumulated benefit obligation.................... $35,556 36,460 43,694
------- ------ ------
------- ------ ------
Plan Assets at Fair Value........................... $39,772 39,326 40,718
Projected Benefit Obligation........................ 40,305 40,989 48,700
------- ------ ------
Plan Assets Less Than Projected Benefit
Obligation........................................ (533) (1,663) (7,982)
Unrecognized Net Loss............................... 5,889 7,222 11,997
Unrecognized Prior Service Costs.................... (779) (588) (518)
Unrecognized Net Transition Asset................... (9,664) (8,120) (6,883)
------- ------ ------
Accrued Pension Expense Liability................. $(5,087) (3,149) (3,386)
------- ------ ------
------- ------ ------
</TABLE>

Retirement plan assets are primarily comprised of common stock and bond
funds. Actuarial assumptions used to measure the projected benefit obligations
at December 31, 1993 included a discount rate of 7% and a compensation increase
rate of 4 1/2%. At December 31, 1992, the discount rate used was 9% and the
compensation increase rate used was 6%. The expected long-term rate of return on
assets was 9% for 1993 and 1992.

Executive Security Plan

The Company's executive security plan ("ESP") provides executive officers
and other key personnel with supplemental death or retirement benefits in
addition to those benefits available under the Company's group life insurance
and retirement plans. These supplemental retirement benefits are provided by a
nonqualified, noncontributory plan and are based on years of service and
compensation. Funding is provided based upon the estimated requirements of the
plan. The components of net pension expense for the ESP are presented below (in
thousands):

<TABLE>
<CAPTION>
YEAR YEARS ENDED
ENDED DECEMBER 31,
SEPTEMBER 30, -------------------
1991 1992 1993
------------- ------ ------
<S> <C> <C> <C>
Service Costs....................................... $ 581 293 426
Interest Cost....................................... 546 353 291
Actual Return on Plan Assets........................ (628) (1,004) (256)
Net Amortization and Deferral....................... 590 994 295
------- ------ ------
Net Pension Expense............................... $ 1,089 636 756
------- ------ ------
------- ------ ------
</TABLE>

For the three months ended March 31, 1994, March 31, 1993 and December 31,
1991, net pension expense for the ESP totaled $204,000, $186,000 and $242,000,
respectively.

During the three months ended March 31, 1994 and the years ended December
31, 1993 and 1992, the Company incurred additional ESP expense of $.4 million,
$.5 million and $3.5 million, respectively, for settlement losses and other
benefits resulting from a cost reduction program, other employee terminations
and sales of assets.

F-27
<PAGE> 90

The funded status of the ESP and amounts included in the Company's
Consolidated Balance Sheets are set forth in the following table (in thousands):

<TABLE>
<CAPTION>
DECEMBER 31,
SEPTEMBER 30, -----------------
1991 1992 1993
------ ----- -----
<S> <C> <C> <C>
Actuarial Present Value of Benefit Obligation:
Vested benefit obligation............................ $6,368 2,410 2,394
------ ----- -----
------ ----- -----
Accumulated benefit obligation....................... $6,420 2,464 2,792
------ ----- -----
------ ----- -----
Plan Assets at Fair Value.............................. $6,658 2,924 3,139
Projected Benefit Obligation........................... 6,420 2,738 3,069
------ ----- -----
Plan Assets in Excess of Projected Benefit
Obligation........................................... 238 186 70
Unrecognized Net Loss.................................. 2,147 1,409 1,177
Unrecognized Prior Service Costs....................... 1,287 679 619
Unrecognized Net Transition Obligation................. 2,412 1,254 1,110
------ ----- -----
Prepaid Pension Asset................................ $6,084 3,528 2,976
------ ----- -----
------ ----- -----
</TABLE>

Assets of the ESP consist of a group annuity contract. Actuarial
assumptions used to measure the projected benefit obligation at December 31,
1993 included a discount rate of 7% and a compensation rate increase of 4 1/2%.
At December 31, 1992, the discount rate used was 9% and the compensation rate
increase used was 5%. The expected long-term rate of return on assets was 9% for
1993 and 1992.

Postretirement Benefits Other than Pensions

In addition to providing pension benefits, the Company provides health care
and life insurance benefits to retirees and eligible dependents who were
participating in the Company's group insurance program at retirement. These
benefits are provided through unfunded defined benefit plans. The health care
plans are contributory, with retiree contributions adjusted periodically, and
contain other cost-sharing features such as deductibles and coinsurance. The
life insurance plan is noncontributory.

As discussed in Note A, the Company adopted SFAS No. 106 effective January
1, 1992 and incurred a net charge of $21.6 million ($16.1 million for health
care benefits and $5.5 million for life insurance benefits) for the cumulative
effect of the change in accounting principle. The components of net periodic
postretirement benefits expense, other than pensions, for 1992 and 1993 included
the following (in thousands):

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-----------------------------------
1992 1993
--------------- --------------
HEALTH LIFE HEALTH LIFE
CARE INSURANCE CARE INSURANCE
------ --- ----- ---
<S> <C> <C> <C> <C>
Service Costs........................................... $ 400 100 420 100
Interest Costs.......................................... 1,332 457 1,396 492
------ --- ----- ---
Net Periodic Postretirement Expense................... $1,732 557 1,816 592
------ --- ----- ---
------ --- ----- ---
</TABLE>

Prior to 1992, the costs of providing health care and life insurance
benefits to retired employees were expensed as claims were paid. In 1991, the
costs of providing retirees with health care benefits amounted to $751,000 and
life insurance benefits amounted to $299,000. For the three months ended March
31, 1994, retiree health care and life insurance benefits totaled $768,000 and
$178,000, respectively. For the three months ended March 31, 1993, retiree
health care and life insurance benefits totaled $454,000 and $148,000,
respectively. For the three months ended December 31,1991, retiree health care
and life insurance benefits totaled $191,000 and $59,000, respectively.

F-28
<PAGE> 91

The Company continues to fund the cost of postretirement health care and
life insurance benefits on a pay-as-you-go basis. The following table shows the
status of the plans reconciled with the amounts in the Company's Consolidated
Balance Sheets (in thousands):

<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31,
1992 1993
----------------- -----------------
HEALTH LIFE HEALTH LIFE
CARE INSURANCE CARE INSURANCE
------- ----- ------ ------
<S> <C> <C> <C> <C>
Accumulated Postretirement Benefit Obligation:
Retirees..................................... $12,183 4,038 19,079 4,915
Active participants eligible to retire....... 625 615 1,566 571
Other active participants.................... 4,144 1,154 5,824 1,658
------- ----- ------ ------
16,952 5,807 26,469 7,144
Unrecognized Net Loss.......................... (820) -- (8,685) (1,044)
------- ----- ------ ------
Accrued Postretirement Benefit Liability..... $16,132 5,807 17,784 6,100
------- ----- ------ ------
------- ----- ------ ------
</TABLE>

The weighted average annual assumed rate of increase in the per capita cost
of covered health care benefits was assumed to be 12% for 1994, decreasing
gradually to 7% by the year 2010 and remaining at that level thereafter. This
health care cost trend rate assumption has a significant effect on the amount of
the obligation and periodic cost reported. For example, an increase in the
assumed health care cost trend rates by one percentage point in each year would
increase the accumulated postretirement obligation as of December 31, 1993 by
$2.9 million and the aggregate of service cost and interest cost components of
net periodic postretirement benefits for the year then ended by $.4 million.

Actuarial assumptions used to measure the accumulated postretirement
benefit obligation at December 31, 1993 included a discount rate of 7% and a
compensation rate increase of 4 1/2%. At December 31, 1992, the discount rate
was 8 1/2% and the compensation rate increase was 6%.

Thrift Plan

The Company's employee thrift plan provides for contributions by eligible
employees into designated investment funds with a matching contribution by the
Company of 50% of the employee's basic contribution. The Company's contributions
amounted to $482,000, $474,000 and $439,000 during 1993, 1992 and 1991,
respectively. For the three months ended March 31, 1994, March 31, 1993 and
December 31, 1991, the Company's contributions amounted to $113,000, $102,000
and $107,000, respectively.

Cost Reduction Program and Other Employee Terminations

In addition to the ESP settlement losses and other benefits and the
retirement plan curtailment gain discussed above, during 1992 the Company
incurred charges of $6.6 million for expenses to implement a cost reduction
program and other employee terminations.

NOTE K -- COMMITMENTS AND CONTINGENCIES

Operating Leases

The Company has various noncancellable operating leases related to
convenience stores, equipment, property, vessels and other facilities. Lease
terms range from one year to 40 years and generally contain

F-29
<PAGE> 92

multiple renewal options. Future minimum annual payments for operating leases,
as of December 31, 1993, are as follows (in thousands):

<TABLE>
<S> <C>
1994............................................................... $17,157
1995............................................................... 4,946
1996............................................................... 3,860
1997............................................................... 3,265
1998............................................................... 3,125
Thereafter......................................................... 13,885
-------
Total.................................................... $46,238
-------
-------
</TABLE>

Total rental expense for the years ended September 30, 1991, December 31,
1992 and December 31, 1993 and the three months ended December 31, 1991, March
31, 1993 and March 31, 1994 was $19.9 million, $24.3 million, $32.5 million,
$6.0 million, $8.3 million and $8.1 million, respectively. Rental expense for
the years ended September 30, 1991, December 31, 1992 and December 31, 1993 and
the three months ended December 31, 1991, March 31, 1993 and March 31, 1994
included $9.9 million, $12.0 million, $22.9 million, $2.9 million, $5.7 million
and $6.0 million, respectively, for the lease of two vessels used to transport
crude oil to or refined products from the Company's Alaska refinery. The lease
for one of these vessels extends through October 1994 with a renewal option
available through October 1996. The lease for the second vessel extends through
July 1994 with a renewal option available through January 1995.

Gas Purchase and Sales Contract

The Company is selling a portion of the gas from its Bob West Field to
Tennessee Gas Pipeline Company ("Tennessee Gas") under a Gas Purchase and Sales
Agreement (the "Tennessee Gas Contract") which provides that the price of gas
shall be the maximum price as calculated in accordance with Section 102(b)(2)
(the "Contract Price") of the Natural Gas Policy Act of 1978 (the "NGPA").

Tennessee Gas filed suit against the Company alleging that the Tennessee
Gas Contract is not applicable to the Company's properties and that the gas
sales price should be the price calculated under the provisions of Section 101
of the NGPA rather than the Contract Price. During March 1994, the Contract
Price was $7.84 per Mcf, the Section 101 price was $4.58 per Mcf and the average
spot market price was $2.09 per Mcf. Tennessee Gas also claimed that the
contract should be considered an "output contract" under Section 2.306 of the
Texas Business and Commerce Code and that the increases in volumes tendered
under the contract exceeded those allowable for an output contract. The Company
continues to receive payment from Tennessee Gas based on the Contract Price for
all volumes that are subject to the contract under the Company's interpretation.

F-30
<PAGE> 93

court decision was the first reported decision in Texas holding that a
take-or-pay contract was an output contract. As a result, it is not clear what
standard the trial court would be required to apply in determining whether the
increases were in bad faith or unreasonably disproportionate. The appellate
court acknowledged in its opinion that the standards used in evaluating other
kinds of output contracts would not be appropriate in this context. The Company
believes that the appropriate standard would be whether the development of the
field was undertaken in a manner that a prudent operator would have undertaken
in the absence of an above-market sales price. Under that standard, 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 March 31, 1994, under the Tennessee Gas Contract based on the Contract
Price, which net revenues aggregated $21.1 million more than the Section 101
prices and $38.9 million in excess of the spot market prices. If Tennessee Gas
ultimately prevails in this litigation, the Company could be required to return
to Tennessee Gas the difference between the spot market price for gas and the
Contract Price, plus interest, if awarded by the court. An adverse judgment in
this case could have a material adverse effect on the Company.

In a separate letter to the Company, Tennessee Gas asserted that the gas
delivered under the Tennessee Gas Contract did not meet contractual
specifications and indicated that it intended to refuse future deliveries of gas
unless the deficiency was corrected within 30 days. The Company believes that
its future deliveries of gas will meet contractual specifications. For further
information concerning the effect of the Tennessee Gas Contract on certain of
the Company's revenues and cash flows, see Note P.

Other

In March 1992, the Company received a Compliance Order and Notice of
Violation from the U.S. Environmental Protection Agency ("EPA") alleging
possible violations by the Company of the New Source Performance Standards under
the Clean Air Act at its Alaska refinery. The Company is continuing in its
efforts to resolve these issues with the EPA; however, no final resolution has
been reached. The Company believes that the ultimate resolution of this matter
will not have a material adverse effect upon the Company's business or financial
condition.

The Company is subject to extensive federal, state and local environmental
laws and regulations. These laws, which are constantly changing, regulate the
discharge of materials into the environment and may require the Company to
remove or mitigate the environmental effects of the disposal or release of
petroleum or chemical substances at various sites. The Company is currently
involved with two waste disposal sites in Louisiana at which it has been named a
potentially responsible party under the Federal Superfund law. Although this law
might impose joint and several liability upon each party at any site, the extent
of the Company's allocated financial contribution to the cleanup of these sites
is expected to be limited based on the number of companies and the volumes of
waste involved. At each site, a number of large companies have also been named
as potentially responsible parties and are expected to cooperate in the cleanup.
The Company is also involved in remedial response and has incurred cleanup
expenditures associated with environmental matters at a number of other sites
including certain of its own properties.

F-31
<PAGE> 94

At March 31, 1994, the Company had accrued $6.0 million for environmental
costs. Based on currently available information, including the participation of
other parties or former owners in remediation actions, the Company believes
these accruals are adequate. Conditions which require additional expenditures
may exist for various Company sites, including, but not limited to, the
Company's refinery, service stations (current and closed locations) and
petroleum product terminals, and for compliance with the Clean Air Act. The
amount of such future expenditures cannot presently be determined by the
Company.

The Company transports its crude oil and a substantial portion of its
refined products utilizing Kenai Pipe Line Company's ("KPL") pipeline and marine
terminal facilities in Kenai, Alaska. In March 1994, KPL filed a revised tariff
with the Federal Energy Regulatory Commission ("FERC") for dock loading
services, which 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. Following the FERC's rejection of KPL's tariff
and the commencement of negotiations for the purchase by the Company of the dock
facilities, KPL filed a temporary tariff that would increase the Company's
annual cost by approximately $1.5 million. The negotiations between the Company
and KPL are continuing. The Company believes that the ultimate resolution of
this matter will not have a material adverse effect upon the financial condition
or results of operations of the Company.

In May 1994, a former customer threatened to file suit against the Company
for a refund in the amount of approximately $1.2 million, plus interest of
approximately $4.4 million and attorney's fees, related to two gasoline
purchases from the Company in 1979. The customer also alleges entitlement to
treble damages and punitive damages in the aggregate amount of $16.8 million.
The refund claim is based on allegations that the Company renegotiated the
acquisition price of gasoline sold to the customer and failed to pass on the
benefit of the renegotiated price to the customer in violation of Department of
Energy price and allocation controls then in effect. The Company believes the
claim is without merit and anticipates that the ultimate resolution of this
matter will not have a material adverse effect on the Company.

NOTE L -- REDEEMABLE PREFERRED STOCK

In March 1983, the Company sold 2,875,000 shares of a series of redeemable
preferred stock at $20 per share. The stock is held by MetLife Louisiana, which
is a subsidiary of Metropolitan Life Insurance Company. The class of stock, of
which there were 2,875,000 shares authorized, issued and outstanding at December
31, 1993 and 1992, has been designated the $2.20 Cumulative Convertible
Preferred Stock ("$2.20 Preferred Stock"). This series has one vote per share,
is convertible into .8696 shares of Common Stock for each share of Preferred
Stock, has a stated value of $1 per share and a liquidation price of $20 per
share plus accrued dividends. The $2.20 Preferred Stock ranks in parity with the
$2.16 Cumulative Convertible Preferred Stock as to liquidation and dividends.

The redeemable preferred stock was recorded at fair value on the date of
issuance less issue costs. The excess of the redemption value over the carrying
value is being accreted by periodic charges to retained earnings over the life
of the issue. During 1993 and 1992, the carrying value of the redeemable
preferred stock was increased for mandatorily redeemable accumulated dividends,
not declared or paid, by charges to retained earnings. As of December 31, 1993,
dividends in arrears on the $2.20 Preferred Stock amounted to approximately
$19.8 million, or $6.875 per share.

As discussed in Note B, in February 1994, the agreement between the Company
and MetLife Louisiana was amended with regard to such preferred shares to waive
all existing mandatory redemption requirements, to consider all accrued and
unpaid dividends (aggregating $21.2 million at February 9, 1994) to have been
paid, to allow the Company to pay future dividends in Common Stock in lieu of
cash, to waive or refrain from exercising other rights of the $2.20 Preferred
Stock and to grant to the Company an option to purchase, during the next three
years, all shares of the $2.20 Preferred Stock and Common Stock held by MetLife
Louisiana for approximately $53 million (amount at February 9, 1994, increasing
by 12% to 14% annually) subject to certain conditions, in consideration for,
among other things, the issuance by the Company to MetLife Louisiana of
1,900,075 shares of Common Stock. Such additional shares are subject to the
option granted by MetLife Louisiana. After giving effect to the
Recapitalization, MetLife Louisiana's Common and Preferred

F-32
<PAGE> 95

Stock holdings approximated 27% of the Company's voting securities. For
information on the pro forma effects of these amendments, see Note B.

NOTE M -- COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY

For information regarding the effects of the Recapitalization on the
Company's Common Stock and Other Stockholders' Equity, refer to Note B.

$2.16 Cumulative Convertible Preferred Stock

The Company has designated a class of preferred stock, of which there were
1,319,563 shares outstanding at December 31, 1993 and 1992 and 200,000 shares
reserved for the granting of options under a stock option plan of the Company.
This class, designated the $2.16 Cumulative Convertible Preferred Stock ("$2.16
Preferred Stock"), has voting rights, is convertible into Common Stock at the
rate of 1.7241 shares of Common Stock for each share of Preferred Stock, has a
stated value of $1 per share and a liquidation value of $25 per share, and is
repurchasable at the option of the Company at liquidation value plus accrued
dividends. The $2.16 Preferred Stock ranks in parity with the $2.20 Preferred
Stock as to liquidation and dividends.

During 1993 and 1992, the liability for accumulated dividends, not declared
or paid, on the $2.16 Preferred Stock was accrued by charges to retained
earnings. As of December 31, 1993, dividends in arrears on the $2.16 Preferred
Stock amounted to approximately $8.9 million, or $6.75 per share.

As discussed in Note B, in February 1994, the outstanding shares of the
Company's $2.16 Preferred Stock, plus accrued and unpaid dividends thereon
(aggregating $9.5 million at February 9, 1994), were reclassified into shares of
the Company's Common Stock.

Incentive Stock Plans

The Company's Amended Incentive Stock Plan of 1982 (the "1982 Plan")
provides for the granting of stock incentives in the form of stock options,
stock appreciation rights and stock awards to officers and key employees. The
stock options are exercisable in accordance with the option plans and expire no
later than ten years from the date of grant. Stock appreciation rights are
exercisable in three to five annual installments, normally beginning with the
first anniversary date of the grant, and expire ten years from the date of
grant. The stock appreciation rights entitle the employee to receive, without
payment to the Company, the incremental increase in market value of the related
stock from date of grant to date of exercise, payable in cash. Related
compensation expense is charged to earnings over periods earned. During 1993,
1992 and 1991 and the three months ended March 31, 1993 and December 31, 1991,
no compensation expense was recognized since the market value of the Company's
Common Stock remained below the exercise price. During the three months ended
March 31, 1994, compensation expense related to the stock appreciation rights
was approximately $29,000, as a result of the market price of the related stock
exceeding the exercise price of the stock appreciation rights. Stock awards
totaling 83,015 common shares, 100,000 common shares and 12,000 common shares
were granted at par value to certain employees of the Company in 1993, 1992 and
1991, respectively. Related compensation expense is charged to earnings over the
periods that the shares are earned and amounted to $572,000, $142,000, $135,000
and $28,000 for 1993, 1992 and 1991 and the three months ended December 31,
1991, respectively, and $23,000 and $29,000, respectively, for the three months
ended March 31, 1994 and 1993.

On February 9, 1994, the Company's shareholders approved the Executive
Long-Term Incentive Plan (the "1993 Plan") which permits the issuance of awards
in a variety of forms, including restricted stock, incentive stock options,
nonqualified stock options, stock appreciation rights and performance share and
performance unit awards. The 1993 Plan provides for the grant of up to 1,250,000
shares of the Company's Common Stock and, unless earlier terminated, will expire
as to the issuance of awards on September 15, 2003. No awards have been made
under the 1993 Plan.

At March 31, 1994, December 31, 1993 and 1992 and September 30, 1991, the
Company had 1,250,000, 60,002, 392,566 and 852,381 unoptioned shares,
respectively, available for granting of options, rights and awards under the
1982 Plan and the 1993 Plan and 5,067,117, 6,064,809, 6,084,809 and 6,093,231
shares of unissued Common Stock, respectively, reserved for conversion of
preferred stock and the Plans. During 1988,

F-33
<PAGE> 96

an amendment to the 1982 Plan was approved which increased the number of shares
of Common Stock which may be granted or transferred from 1,500,000 to 2,000,000.
The additional shares were registered with the Securities and Exchange
Commission during 1994. The 1982 Plan expired on February 24, 1994 as to
issuance of options, rights and awards; however, grants made before such date
that have not been fully exercised will remain outstanding pursuant to their
terms.

A summary of activity in the incentive stock plans is set forth below:

<TABLE>
<CAPTION>
STOCK APPRECIATION
STOCK OPTIONS RIGHTS
TOTAL -------------------- ---------------------
RESERVED OUTSTANDING EXERCISABLE OUTSTANDING EXERCISABLE
-------- -------- ------- -------- --------
<S> <C> <C> <C> <C> <C>
Balances at September 30, 1990.... 1,355,257 226,296 124,430 275,863 173,449
Becoming exercisable............ -- -- 39,684 -- 40,230
Cancelled or expired............ (25,207) (4,491) (4,491) (31,999) (31,999)
Stock awards.................... (12,000) -- -- -- --
-------- -------- ------- -------- --------
Balances at September 30, 1991.... 1,318,050 221,805 159,623 243,864 181,680
Granted at $3.925 to $4.840..... -- 600,000 -- -- --
Becoming exercisable............ -- -- 34,243 -- 34,248
Cancelled or expired............ -- (109,171) (90,786) (119,414) (101,030)
Stock awards.................... (8,400) -- -- -- --
-------- -------- ------- -------- --------
</TABLE>

<TABLE>
<S> <C> <C> <C> <C> <C>
Balances at December 31, 1992..... 1,309,650 712,634 103,080 124,450 114,898
Granted at $2.925 to $5.250..... -- 349,680 -- -- --
Becoming exercisable............ -- -- 127,044 -- 7,042
Cancelled or expired............ -- (45,444) (44,278) (54,687) (53,521)
Stock awards.................... (20,000) -- -- -- --
-------- -------- ------- -------- --------
Balances at December 31, 1993..... 1,289,650 1,016,870 185,846 69,763 68,419
Reserved........................ 1,250,000 -- -- -- --
Becoming exercisable............ -- -- 31,344 -- 1,344
Exercised....................... (24,587) (14,215) (14,215) (10,372) (10,372)
Cancelled or expired............ (80,002) (20,000) -- -- --
-------- -------- ------- -------- --------
Balances at March 31, 1994........ 2,435,061 982,655 202,975 59,391 59,391
-------- -------- ------- -------- --------
-------- -------- ------- -------- --------
Price per share or right.......... $ 2.925 to $12.625 $ 8.375 to $14.000
</TABLE>

Preferred Stock Purchase Rights

In November 1985, the Company's Board of Directors declared a distribution
of one preferred stock purchase right for each share of the Company's Common
Stock. Each right will entitle the holder to buy 1/100 of a share of a newly
authorized Series A Participating Preferred Stock at an exercise price of $35
per right. The rights become exercisable on the tenth day after public
announcement that a person or group has acquired 20% or more of the Company's
Common Stock. The rights may be redeemed by the Company prior to becoming
exercisable by action of the Board of Directors at a redemption price of $.05
per right. If the Company is acquired by any person after the rights become
exercisable, each right will entitle its holder to purchase stock of the
acquiring company having a market value of twice the exercise price of each
right. At December 31, 1993, there were 14,089,236 rights outstanding which will
expire in December 1995. In conjunction with the Recapitalization in 1994
discussed in Note B, the Company issued an additional 8,365,934 rights.

F-34
<PAGE> 97

NOTE N -- FINANCIAL INFORMATION BY BUSINESS SEGMENT

Tesoro is primarily engaged in three business segments: crude oil refining
and marketing of refined petroleum products; the exploration and production of
natural gas; and oil field supply and distribution of fuels and lubricants.
Geographically, the refining and marketing operations are concentrated in Alaska
and on the West Coast, the exploration and production operations are located in
South Texas and Bolivia, and the wholesale marketing of fuel and lubricants is
conducted along the Texas and Louisiana Gulf Coast area. The Company sold its
Indonesian exploration and production operations in May 1992. Income taxes,
interest, general and administrative expenses and certain other corporate items
are not allocated to the operating segments.

<TABLE>
<CAPTION>
THREE MONTHS
YEAR THREE MONTHS YEARS ENDED ENDED
ENDED ENDED DECEMBER 31, MARCH 31,
SEPTEMBER 30, DECEMBER 31, -------------- --------------
1991 1991 1992 1993 1993 1994
------------- ------------ ---- ---- ---- ----
(IN MILLIONS) (UNAUDITED)
<S> <C> <C> <C> <C> <C> <C>
Gross Operating Revenues:
Refining and Marketing(1).............. $ 898.6 196.8 810.7 687.2 194.6 150.3
Exploration and Production:
United States(2).................... 5.2 2.4 18.8 50.5 7.7 17.4
Bolivia............................. 24.5 4.6 17.9 12.6 2.8 2.8
Indonesia........................... 29.5 5.5 6.0 -- -- --
Oil Field Supply and Distribution...... 134.3 36.5 93.5 80.7 19.4 18.6
Intersegment Eliminations(3)........... (7.1) (5.2) (.4) -- -- --
-------- ----- ----- ----- ----- -----
Total.......................... $1,085.0 240.6 946.5 831.0 224.5 189.1
-------- ----- ----- ----- ----- -----
-------- ----- ----- ----- ----- -----
Operating Profit (Loss), Including Gain
on Sales of Assets(4):
Refining and Marketing.............. $ 19.3 1.7 (14.9) 15.2 1.2 6.4
Exploration and Production:
United States(2).................. .6 .3 8.9 32.3 4.2 11.2
Bolivia........................... 21.2 5.3 12.6 8.4 1.4 1.9
Indonesia......................... 13.8 1.8 7.6 -- -- --
Oil Field Supply and Distribution... (.5) (1.2) (4.7) (3.6) (.8) (1.2)
-------- ----- ----- ----- ----- -----
Total Operating Profit......... 54.4 7.9 9.5 52.3 6.0 18.3
Corporate and Unallocated Costs.......... (35.4) (5.4) (49.4) (33.6) 8.2 9.5
-------- ----- ----- ----- ----- -----
Earnings (Loss) Before Income Taxes, the
Cumulative Effect of Accounting Changes
and Extraordinary Loss on
Extinguishment
of Debt................................ $ 19.0 2.5 (39.9) 18.7 (2.2) 8.8
-------- ----- ----- ----- ----- -----
-------- ----- ----- ----- ----- -----
Total Assets:
Refining and marketing................. $ 322.7 328.5 308.0 281.5 284.0 279.4
Exploration and Production:
United States....................... 32.3 33.0 34.1 67.2 40.7 71.4
Bolivia............................. 15.6 6.8 2.9 6.5 2.6 7.0
Indonesia........................... 11.8 10.7 .3 -- .3 --
Oil Field Supply and Distribution...... 32.2 27.6 23.2 21.3 21.5 19.2
Corporate.............................. 82.2 88.1 78.2 58.0 78.6 65.1
-------- ----- ----- ----- ----- -----
Total Assets................... $ 496.8 494.7 446.7 434.5 427.7 442.1
-------- ----- ----- ----- ----- -----
-------- ----- ----- ----- ----- -----
</TABLE>

(Table continued on following page)

F-35
<PAGE> 98

- ---------------

(1) Includes revenues of $165.9 million, $101.0 million and $20.5 million in
fiscal years 1991, 1992 and 1993, respectively, and $2.9 million and $5.2
million for the three months ended March 31, 1993 and 1994, respectively,
derived from export sales to customers in Far Eastern markets.

(2) Includes revenues and operating profit of $5.4 million in 1992 resulting
from a change in estimate of the Company's revenues from natural gas
production in South Texas (see Note K).

(3) Represents intersegment eliminations, primarily sales from Refining and
Marketing to Oil Field Supply and Distribution, at prices which approximate
market.

(4) Operating profit represents pretax earnings (loss) before certain corporate
expenses, interest income and interest expense. Total operating profit has
been reconciled to earnings (loss) before income taxes, the cumulative
effect of accounting changes and extraordinary loss on extinguishment of
debt. As discussed in Note E, operating profit from the Exploration and
Production segment in 1992 included a $5.8 million gain from the sales of
the Company's Indonesian operations and operating profit from the refining
and marketing segment for the three months ended March 31, 1994 included a
$2.8 million gain from the sale of the Company's Valdez, Alaska terminal.

F-36
<PAGE> 99

NOTE O -- QUARTERLY FINANCIAL DATA (UNAUDITED)

<TABLE>
<CAPTION>
QUARTERS ENDED
--------------------------------------------------------------------------------------
SEPTEM- DECEM- SEPTEM- DECEM-
MARCH 31, JUNE 30, BER 30, BER 31, MARCH 31, JUNE 30, BER 30, BER 31, MARCH 31,
1992 1992 1992 1992 1993 1993 1993 1993 1994
------ ----- ----- ----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
(IN MILLIONS EXCEPT PER SHARE DATA)
Total Revenues...................... $223.2 251.2 244.5 235.5 226.5 186.2 215.2 207.0 192.7
------ ----- ----- ----- ----- ----- ----- ----- -----
------ ----- ----- ----- ----- ----- ----- ----- -----
Operating Profit (Loss)............. $ 2.7 5.6 7.6 (6.4) 6.0 8.9 13.1 24.3 18.3
------ ----- ----- ----- ----- ----- ----- ----- -----
------ ----- ----- ----- ----- ----- ----- ----- -----
Net Earnings (Loss) Before
Cumulative Effect of Accounting
Changes and Extraordinary Loss.... $(11.0) (5.2) (3.2) (24.9) (2.9) 1.5 1.7 16.7 7.2
Accounting Changes.................. (21.0) (.3) (.3) -- -- -- -- -- --
Extraordinary Loss.................. -- -- -- -- -- -- -- -- (4.8)
------ ----- ----- ----- ----- ----- ----- ----- -----
Net Earnings (Loss)................. $(32.0) (5.5) (3.5) (24.9) (2.9) 1.5 1.7 16.7 2.4
------ ----- ----- ----- ----- ----- ----- ----- -----
------ ----- ----- ----- ----- ----- ----- ----- -----
Primary Earnings (Loss) Per Share:
Earnings (loss) before cumulative
effect of accounting changes and
extraordinary loss.............. $ (.95) (.53) (.39) (1.93) (.37) (.06) (.04) 1.00 .27
Accounting changes................ (1.49) (.03) (.02) -- -- -- -- -- --
Extraordinary loss................ -- -- -- -- -- -- -- -- (.24)
------ ----- ----- ----- ----- ----- ----- ----- -----
Net earnings (loss)............... $(2.44) (.56) (.41) (1.93) (.37) (.06) (.04) 1.00 .03
------ ----- ----- ----- ----- ----- ----- ----- -----
------ ----- ----- ----- ----- ----- ----- ----- -----
Fully Diluted Earnings (Loss)
Per Share......................... $(2.44) (.56) (.41) (1.93) (.37) (.06) (.04) .87 .03
------ ----- ----- ----- ----- ----- ----- ----- -----
------ ----- ----- ----- ----- ----- ----- ----- -----
Market Price Per Common Share:
High.............................. $6 5/8 5 3/8 5 1/2 3 5/8 5 5/8 6 5/8 7 3/4 7 1/2 12 3/8
Low............................... $4 5/8 4 1/4 3 2 1/2 3 5 5 1/8 5 1/8 5 1/4
</TABLE>

The 1992 first quarter included charges of $20.6 million for the cumulative
effect of accounting changes, $2.4 million for a cost reduction program and $1.0
million for asset write-downs. The 1992 third quarter included a $5.8 million
gain from the sales of the Company's Indonesian operations. The fourth quarter
of 1992 included revenues and operating profit of $5.4 million ($.38 per share)
resulting from a change in estimate of the Company's revenues from natural gas
production in the South Texas field (see Note K) and additional charges of $10.5
million for the settlement with the State of Alaska and $5.6 million for the
cost reduction program and other employee terminations.

The 1993 second quarter and fourth quarters included benefits of $3.0
million and $5.2 million, respectively, for resolution of several state tax
issues. A $5.0 million charge for an inventory erosion was recorded in the 1993
third quarter. Included in the 1993 fourth quarter, however, was a $5.7 million
offset to the inventory adjustment taken earlier in the year. Inventory levels
at the 1993 year-end were greater than projected earlier in the year due to
changing market conditions. The 1993 fourth quarter benefited from the decline
in crude oil prices, while the Company's refined product margins held steady or
improved.

The 1994 first quarter included an extraordinary loss on early
extinguishment of debt as a result of $44.1 million principal amount of
Subordinated Debentures being exchanged for a like amount of Exchange Notes as
part of the Recapitalization and a gain of $2.8 million from the sale of the
Company's Valdez, Alaska terminal.

F-37
<PAGE> 100

NOTE P -- OIL AND GAS PRODUCING ACTIVITIES

The following information regarding the Company's exploration and
production activities should be read in conjunction with Notes E and K.

Capitalized Costs Relating to Oil and Gas Producing Activities

<TABLE>
<CAPTION>
DECEMBER 31,
---------------------
SEPTEMBER 30,
1991 1992 1993
------- ------ ------
<S> <C> <C> <C>
(IN THOUSANDS)
Capitalized Costs:
Proved properties................................... $29,100 34,050 60,489
Unproved properties:
Properties being amortized....................... 8,511 11,132 12,856
Properties not being amortized................... 8,242 1,482 1,959
------- ------ ------
45,853 46,664 75,304
Accumulated depreciation, depletion and
amortization..................................... 15,713 15,006 26,118
------- ------ ------
Net Capitalized Costs............................ $30,140 31,658 49,186
------- ------ ------
------- ------ ------
</TABLE>

Costs Incurred in Oil and Gas Property Acquisition, Exploration and
Development Activities

<TABLE>
<CAPTION>
UNITED
STATES BOLIVIA INDONESIA TOTAL
------- --- ----- ------
<S> <C> <C> <C> <C>
(IN THOUSANDS)
Year Ended December 31, 1993:
Property acquisition, unproved................... $ 887 -- -- 887
Exploration...................................... 2,257 -- -- 2,257
Development...................................... 25,496 -- -- 25,496
------- --- ----- ------
$28,640 -- -- 28,640
------- --- ----- ------
------- --- ----- ------
Year Ended December 31, 1992:
Property acquisition, unproved................... $ 9 -- -- 9
Exploration...................................... 977 6 333 1,316
Development...................................... 7,922 -- 109 8,031
------- --- ----- ------
$ 8,908 6 442 9,356
------- --- ----- ------
------- --- ----- ------
Three Months Ended December 31, 1991:
Property acquisition, unproved................... $ (7) -- -- (7)
Exploration...................................... 1,037 15 24 1,076
Development...................................... 1,881 -- 60 1,941
------- --- ----- ------
$ 2,911 15 84 3,010
------- --- ----- ------
------- --- ----- ------
Year Ended September 30, 1991:
Property acquisition, unproved................... $ 582 -- 3 585
Exploration...................................... 9,975 45 9 10,029
Development...................................... 7,226 -- 1,476 8,702
------- --- ----- ------
$17,783 45 1,488 19,316
------- --- ----- ------
------- --- ----- ------
</TABLE>

The Company's investment in oil and gas properties included $2.0 million in
unevaluated properties which have been excluded from the amortization base as of
December 31, 1993. The Company anticipates that the majority of these costs,
substantially all of which were incurred in 1993, will be included in the
amortization base during 1994.

F-38
<PAGE> 101

Results of Operations from Oil and Gas Producing Activities

The following table sets forth the results of operations for oil and gas
producing activities, in the aggregate by geographic area, with income tax
expense computed using the statutory tax rate for the period adjusted for
permanent differences, tax credits and allowances.

<TABLE>
<CAPTION>
UNITED
STATES(1) BOLIVIA INDONESIA TOTAL
------- ------ ------ ------
<S> <C> <C> <C> <C>
(IN THOUSANDS EXCEPT AS INDICATED)
Year Ended December 31, 1993:
Gross revenues -- sales to nonaffiliates.......... $50,228 12,594 -- 62,822
Lifting cost...................................... 6,763 1,152 -- 7,915
Administrative support and other.................. 939 3,046 -- 3,985
Depreciation, depletion and amortization.......... 11,111 -- -- 11,111
------- ------ ------ ------
Pretax results of operations...................... 31,415 8,396 -- 39,811
Income tax expense................................ 6,647 5,160 -- 11,807
------- ------ ------ ------
Results of operations from producing
activities(2).................................. $24,768 3,236 -- 28,004
------- ------ ------ ------
------- ------ ------ ------
Depletion rates per net equivalent mcf............ $ .78 -- --
------- ------ ------
------- ------ ------
Year Ended December 31, 1992:
Gross revenues -- sales to nonaffiliates.......... $18,850 17,898 5,975 42,723
Lifting cost...................................... 3,796 688 3,698 8,182
Administrative support and other.................. 1,216 4,635 107 5,958
Gain (loss) on sales of assets.................... (3) -- 5,750(3) 5,747
Depreciation, depletion and amortization.......... 4,862 -- 336 5,198
------- ------ ------ ------
Pretax results of operations...................... 8,973 12,575 7,584 29,132
Income tax expense................................ 305 7,108 3,066 10,479
------- ------ ------ ------
Results of operations from producing
activities(2).................................. $ 8,668 5,467 4,518 18,653
------- ------ ------ ------
------- ------ ------ ------
Depletion rates per net equivalent mcf............ $ .95 -- .15
------- ------ ------
------- ------ ------
Three Months Ended December 31, 1991:
Gross revenues -- sales to nonaffiliates.......... $ 2,426 4,634 5,474 12,534
Lifting cost...................................... 1,071 122 2,915 4,108
Administrative support and other.................. 242 (765)(5) 107 (416)
Depreciation, depletion and amortization.......... 848 -- 606 1,454
------- ------ ------ ------
Pretax results of operations...................... 265 5,277 1,846 7,388
Income tax expense................................ 9 2,744 1,413 4,166
------- ------ ------ ------
Results of operations from producing
activities(2).................................. $ 256 2,533 433 3,222
------- ------ ------ ------
------- ------ ------ ------
Depletion rates per net equivalent mcf............ $ .94 -- .31
------- ------ ------
------- ------ ------
Year Ended September 30, 1991:
Gross revenues -- sales to nonaffiliates.......... $ 5,179 24,557 29,507 59,243
Lifting cost...................................... 1,218 650 9,467 11,335
Administrative support and other.................. 424 2,710 4,497(4) 7,631
Depreciation, depletion and amortization.......... 2,920 -- 1,712 4,632
------- ------ ------ ------
Pretax results of operations...................... 617 21,197 13,831 35,645
Income tax expense................................ 12 12,015 8,766 20,793
------- ------ ------ ------
Results of operations from producing
activities(2).................................. $ 605 9,182 5,065 14,852
------- ------ ------ ------
------- ------ ------ ------
Depletion rates per net equivalent mcf............ $ 1.06 -- .22
------- ------ ------
------- ------ ------
</TABLE>

- ---------------

(1) See Note K regarding litigation involving a natural gas sales contract.

(2) Excludes corporate general and administrative and financing costs.

(3) Represents gain from the sales of the Company's Indonesian operations
effective May 1, 1992.

(4) Includes a $2.0 million charge for an arbitration award involving a royalty
dispute on Indonesian crude oil production.

(5) Includes a $1.3 million credit for Bolivian transaction taxes.

F-39
<PAGE> 102

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Reserves (Unaudited)

The following table sets forth the computation of the standardized measure
of discounted future net cash flows relating to proved reserves and the changes
in such cash flows in accordance with Statement of Financial Accounting
Standards No. 69 ("SFAS No. 69"). The standardized measure is the estimated
excess future cash inflows from proved reserves less estimated future production
and development costs, estimated future income taxes and a discount factor.
Future cash inflows represent expected revenues from production of year-end
quantities of proved reserves based on year-end prices and any fixed and
determinable future escalation provided by contractual arrangements in existence
at year-end. Escalation based on inflation, federal regulatory changes and
supply and demand are not considered. Estimated future production costs related
to year-end reserves are based on year-end costs. Such costs include, but are
not limited to, production taxes and direct operating costs. Inflation and other
anticipatory costs are not considered until the actual cost change takes effect.
Estimated future income tax expenses are computed using the appropriate year-end
statutory tax rates. Consideration is given for the effects of permanent
differences, tax credits and allowances. A discount rate of 10% is applied to
the annual future net cash flows after income taxes.

The methodology and assumptions used in calculating the standardized
measure are those required by SFAS No. 69. The standardized measure is not
intended to be representative of the fair market value of the Company's proved
reserves. The calculations of revenues and costs do not necessarily represent
the amounts to be received or expended by the Company.

As indicated in Note K, certain of the Company's South Texas production
activities are involved in litigation pertaining to a natural gas sales contract
with Tennessee Gas. Although the outcome of any litigation is uncertain, based
upon advice from outside legal counsel, management believes that the Company
will ultimately prevail in this dispute. Accordingly, the Company has based its
calculation of the standardized measure of discounted future net cash flows on
the Contract Price which it is currently receiving. However, if Tennessee Gas
were to prevail, the impact on the Company's future revenues and cash flows
would be significant. Based on the Contract Price, the standardized measure of
discounted future net cash flows relating to proved reserves in the United
States at December 31, 1993 was $103 million, compared to $59 million at spot
market prices.

<TABLE>
<CAPTION>
UNITED
STATES(1) BOLIVIA INDONESIA TOTAL
-------- -------- ------- --------
<S> <C> <C> <C> <C>
(IN THOUSANDS)
As of December 31, 1993:
Future cash inflows................................ $315,788 133,363 -- 449,151
Future production costs............................ (59,398) (31,092) -- (90,490)
Future development costs........................... (48,020) (2,981) -- (51,001)
-------- -------- ------- --------
Future net cash flows before income tax expense.... 208,370 99,290 -- 307,660
Future income tax expense.......................... (76,500) (52,334) -- (128,834)
-------- -------- ------- --------
Future net cash flows.............................. 131,870 46,956 -- 178,826
10% annual discount factor......................... (29,118) (20,516) -- (49,634)
-------- -------- ------- --------
Standardized measure of discounted future net cash
flows........................................... $102,752 26,440 -- 129,192
-------- -------- ------- --------
-------- -------- ------- --------
As of December 31, 1992:
Future cash inflows................................ $215,172 146,555 -- 361,727
Future production costs............................ (33,162) (40,374) -- (73,536)
Future development costs........................... (30,294) (9,248) -- (39,542)
-------- -------- ------- --------
Future net cash flows before income tax expense.... 151,716 96,933 -- 248,649
Future income tax expense.......................... (42,884) (56,682) -- (99,566)
-------- -------- ------- --------
Future net cash flows.............................. 108,832 40,251 -- 149,083
10% annual discount factor......................... (21,744) (16,628) -- (38,372)
-------- -------- ------- --------
Standardized measure of discounted future net cash
flows........................................... $ 87,088 23,623 -- 110,711
-------- -------- ------- --------
-------- -------- ------- --------
</TABLE>

(Table continued on following page)

F-40
<PAGE> 103

<TABLE>
<CAPTION>
UNITED
STATES(1) BOLIVIA INDONESIA TOTAL
-------- -------- ------- --------
<S> <C> <C> <C> <C>
(IN THOUSANDS)
As of December 31, 1991:
Future cash inflows................................ $ 69,405 289,143 113,877 472,425
Future production costs............................ (10,167) (52,667) (87,913) (150,747)
Future development costs........................... (13,334) (11,760) (8,545) (33,639)
-------- -------- ------- --------
Future net cash flows before income tax expense.... 45,904 224,716 17,419 288,039
Future income tax expense.......................... (4,179) (127,824) (12,178) (144,181)
-------- -------- ------- --------
Future net cash flows.............................. 41,725 96,892 5,241 143,858
10% annual discount factor......................... (10,853) (46,023) -- (56,876)
-------- -------- ------- --------
Standardized measure of discounted future net cash
flows........................................... $ 30,872 50,869 5,241 86,982
-------- -------- ------- --------
-------- -------- ------- --------
As of September 30, 1991:
Future cash inflows................................ $ 67,514 302,022 88,234 457,770
Future production costs............................ (11,184) (53,482) (68,400) (133,066)
Future development costs........................... (13,370) (11,760) (8,260) (33,390)
-------- -------- ------- --------
Future net cash flows before income tax expense.... 42,960 236,780 11,574 291,314
Future income tax expense.......................... (5,457) (136,543) (6,352) (148,352)
-------- -------- ------- --------
Future net cash flows.............................. 37,503 100,237 5,222 142,962
10% annual discount factor......................... (7,147) (45,955) (814) (53,916)
-------- -------- ------- --------
Standardized measure of discounted future net cash
flows........................................... $ 30,356 54,282 4,408 89,046
-------- -------- ------- --------
-------- -------- ------- --------
</TABLE>

- ---------------

(1) See Note K regarding litigation involving a natural gas sales contract.

Changes in Standardized Measure of Discounted Future Net Cash Flows
(Unaudited)

<TABLE>
<CAPTION>
THREE
YEAR MONTHS YEARS ENDED
ENDED ENDED DECEMBER 31,
SEPTEMBER 30, DECEMBER 31, --------------------
1991 1991 1992 1993
-------- ------ ------- -------
<S> <C> <C> <C> <C>
(IN THOUSANDS)
Sales and transfers of oil and gas produced,
net of production costs....................... $(45,005) (8,713) (31,208) (52,766)
Net changes in prices and production costs...... (29,828) 222 (32,397) (21,160)
Extensions, discoveries and improved recovery... 19,998 1,802 104,219 73,792
Development costs incurred...................... 9,544 2,289 10,012 25,510
Revisions of estimated future development
costs......................................... (12,633) (2,316) (18,666) (24,052)
Revisions of previous quantity estimates........ (37,392) 4,565 (15,384) 31,031
Purchases and sales of minerals in-place........ 47,418 -- (5,884) --
Accretion of discount........................... 10,251 2,226 8,174 11,071
Net changes in income taxes..................... 24,197 (2,139) 4,863 (24,945)
-------- ------ ------- -------
Net increase (decrease)......................... (13,450) (2,064) 23,729 18,481
Beginning of period............................. 102,496 89,046 86,982 110,711
-------- ------ ------- -------
End of period................................... $ 89,046 86,982 110,711 129,192
-------- ------ ------- -------
-------- ------ ------- -------
</TABLE>

F-41
<PAGE> 104

Reserve Quantity Information (Unaudited)

The following estimates of the Company's proved oil and gas reserves are
based on evaluations prepared by Netherland, Sewell & Associates, Inc. (except
for estimates of reserves at December 31, 1991 for properties in Bolivia and for
all periods for properties in Indonesia, which estimates were prepared by the
Company's in-house engineers). Reserves were estimated in accordance with
guidelines established by the Securities and Exchange Commission and Financial
Accounting Standards Board, which require that reserve estimates be prepared
under existing economic and operating conditions with no provision for price and
cost escalations except by contractual arrangements.

<TABLE>
<CAPTION>
UNITED
STATES(2) BOLIVIA TOTAL
------- ------- -------
<S> <C> <C> <C>
Proved Gas Reserves (millions of cubic feet)(1):
At September 30, 1990..................................... 11,118 85,040 96,158
Revisions of previous estimates........................... (1,217) 696 (521)
Purchase of minerals in-place............................. -- 36,545 36,545
Extensions, discoveries and other additions............... 25,950 -- 25,950
Production................................................ (2,710) (7,052) (9,762)
------- ------- -------
At September 30, 1991..................................... 33,141 115,229 148,370
Revisions of previous estimates........................... 1,054 (35) 1,019
Extensions, discoveries and other additions............... 3,585 -- 3,585
Production................................................ (896) (1,729) (2,625)
------- ------- -------
At December 31, 1991...................................... 36,884 113,465 150,349
Revisions of previous estimates........................... (9,601) 651 (8,950)
Extensions, discoveries and other additions............... 53,952 -- 53,952
Production................................................ (5,110) (7,108) (12,218)
Sales of minerals in-place................................ (2,372) -- (2,372)
------- ------- -------
At December 31, 1992...................................... 73,753 107,008 180,761
Revisions of previous estimates........................... 16,304 (693) 15,611
Extensions, discoveries and other additions............... 44,291 -- 44,291
Production................................................ (14,150) (7,020) (21,170)
------- ------- -------
At December 31, 1993(3)................................... 120,198 99,295 219,493
------- ------- -------
------- ------- -------
Proved Developed Gas Reserves included above
(millions of cubic feet):
At September 30, 1990..................................... 5,046 79,623 84,669
At September 30, 1991..................................... 18,011 107,765 125,776
At December 31, 1991...................................... 21,187 106,036 127,223
At December 31, 1992...................................... 34,160 91,376 125,536
At December 31, 1993(3)................................... 65,652 99,295 164,947
</TABLE>

(Table continued on following page)

F-42
<PAGE> 105

<TABLE>
<CAPTION>
UNITED
STATES BOLIVIA INDONESIA TOTAL
--- ----- ------ ------
<S> <C> <C> <C> <C>
Proved Oil Reserves (thousands of barrels)(1):
At September 30, 1990................................. 4 2,058 11,226 13,288
Revisions of previous estimates....................... 2 59 (5,513) (5,452)
Purchase of minerals in-place......................... -- 953 -- 953
Extensions, discoveries and other additions........... 3 -- -- 3
Production............................................ (4) (242) (1,209) (1,455)
--- ----- ------ ------
At September 30, 1991................................. 5 2,828 4,504 7,337
Revisions of previous estimates....................... -- 1 1,333 1,334
Production............................................ (1) (58) (266) (325)
--- ----- ------ ------
At December 31, 1991.................................. 4 2,771 5,571 8,346
Revisions of previous estimates....................... 1 (266) -- (265)
Production............................................ (1) (242) (328) (571)
Sales of minerals in-place............................ (4) -- (5,243) (5,247)
--- ----- ------ ------
At December 31, 1992.................................. -- 2,263 -- 2,263
Revisions of previous estimates....................... -- 152 -- 152
Production............................................ -- (242) -- (242)
--- ----- ------ ------
At December 31, 1993(3)............................... -- 2,173 -- 2,173
--- ----- ------ ------
--- ----- ------ ------
Proved Developed Oil Reserves included above
(thousands of barrels):
At September 30, 1990................................. 4 1,987 11,226 13,217
At September 30, 1991................................. 5 2,738 4,504 7,247
At December 31, 1991.................................. 4 2,680 5,571 8,255
At December 31, 1992.................................. -- 2,098 -- 2,098
At December 31, 1993(3)............................... -- 2,173 -- 2,173
</TABLE>

- ---------------

(1) The Company was not required to file reserve estimates with federal
authorities or agencies during the periods presented.

(2) See Note K regarding litigation involving a natural gas sales contract.

(3) No major discovery or adverse event has occurred since December 31, 1993
that would cause a significant change in proved reserves.

F-43
<PAGE> 106

-- The Company's production from the Bob
West Field
averaged 58 million cubic feet of natural
gas per day
during December 1993.

(PHOTO OF A NATURAL
GAS WELL)
(MAP OF THE BOB WEST FIELD SHOWING
EXISTING CRUDE LOCATIONS AND
TENNESSEE GAS CONTRACT ACREAGE.)

Since the discovery of the Bob
West Field in 1990, Tesoro has
drilled 31 gross wells within the
field without a single dry hole. --
(PHOTO OF A
DRILLING RIG)
(MAP OF THE BOB WEST FIELD
SHOWING EXISTING CRUDE
LOCATIONS AND TENNESSEE GAS
CONTRACT ACREAGE.)

-- There are currently
four drilling rigs in
operation in the 4000
acre Bob West Field.
<PAGE> 107

- ------------------------------------------------------
NO DEALER, SALESPERSON OR OTHER INDIVIDUAL HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATION NOT CONTAINED IN THIS PROSPECTUS AND,
IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATION MUST NOT BE RELIED UPON AS
HAVING BEEN AUTHORIZED BY THE COMPANY OR ANY UNDERWRITER. THIS PROSPECTUS DOES
NOT CONSTITUTE AN OFFER TO SELL OR A SOLICITATION OF AN OFFER TO BUY ANY OF THE
SECURITIES OFFERED HEREBY IN ANY JURISDICTION TO ANY PERSON TO WHOM IT IS
UNLAWFUL TO MAKE SUCH OFFER IN SUCH JURISDICTION. NEITHER THE DELIVERY OF THIS
PROSPECTUS NOR ANY SALE MADE HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE
ANY IMPLICATION THAT THE INFORMATION HEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT
TO THE DATE HEREOF OR THAT THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF THE
COMPANY SINCE SUCH DATE.
------------------
TABLE OF CONTENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Prospectus Summary..................... 3
Investment Considerations.............. 11
The Company............................ 14
Use of Proceeds........................ 14
Price Range of Common Stock and
Dividend Policy...................... 15
Capitalization......................... 16
Selected Financial Data................ 17
Management's Discussion and Analysis of
Financial Condition and Results of
Operations........................... 19
Business............................... 33
Management............................. 49
Possible Change in Board of
Directors............................ 51
Legal Proceedings...................... 51
Description of Capital Stock........... 53
Underwriting........................... 58
Canadian Residents..................... 59
Legal Matters.......................... 60
Experts................................ 60
Available Information.................. 60
Incorporation of Certain Documents by
Reference............................ 61
Index to Consolidated Financial
Statements........................... F-1
</TABLE>

- ------------------------------------------------------

5,000,000 SHARES

COMMON STOCK
$.16 2/3 PAR VALUE)
PROSPECTUS

CS FIRST BOSTON

SMITH BARNEY SHEARSON INC.

JEFFERIES & COMPANY, INC.

- ------------------------------------------------------
<PAGE> 108

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

ITEM 14. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.

The expenses to be paid by the Registrant in connection with the issuance
and distribution of the Common Stock are estimated as follows:

<TABLE>
<S> <C>
Securities and Exchange Commission registration fee........................ $21,455
NASD filing fee............................................................ 6,722
NYSE additional listing fee................................................ 19,250
Blue Sky fees and expenses................................................. 10,000
Accounting fees and expenses............................................... *
Legal fees and expenses.................................................... *
Printing and engraving fees................................................ *
Transfer agent's fees and expenses......................................... *
Miscellaneous expenses..................................................... *
-------
Total............................................................ $ *
-------
-------
</TABLE>

- ---------------
* To be filed by amendment.

ITEM 15. INDEMNIFICATION OF DIRECTORS AND OFFICERS.

Section 145 of the Delaware General Corporation Law empowers the Company
to, and the bylaws of the Company provide that it shall, to the full extent
authorized or permitted by the laws of the State of Delaware, indemnify any
person who is made, or threatened to be made, a party to an action, suit or
proceeding (whether civil, criminal, administrative or investigative) by reason
of the fact that he, his testator or intestate is or was a director, officer or
employee of the Company, respectively, or serves or served any other enterprise
at the request of the Company.

Article Ninth of the Company's Certificate of Incorporation provides that
no director of the Company will be personally liable to the Company or its
stockholders for monetary damages for breach of fiduciary duty by such directors
as a director; provided, however, that such article will not eliminate or limit
liability of a director to the extent provided by applicable law (i) for any
breach of the director's duty of loyalty to the Company or its stockholders,
(ii) for acts or omissions not in good faith or which involve intentional
misconduct or a knowing violation of the law, (iii) under Section 174 of the
General Corporation Law of the State of Delaware, or (iv) for any transaction
from which the director derived an improper personal benefit. The effect of this
provision is to eliminate the personal liability of a director to the Company
and its stockholders for monetary damages for breach of his fiduciary duty as a
director to the extent allowed under the GCL.

The Underwriting Agreement (Exhibit 1) provides for indemnification by the
Underwriter of the Company and its directors and officers, and by the Company of
the Underwriter for certain liabilities, including liabilities, arising under
the Securities Act of 1933, as amended.

The above discussion of the Company's Certificate of Incorporation and
Bylaws, Section 145 of the Delaware Law and the Underwriting Agreement is not
intended to be exhaustive and is qualified in its entirety by each of such
documents and such statute.

The Company has entered into indemnification agreements with its directors
and certain of its officers.

II-1
<PAGE> 109

ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

(a) Exhibits

<TABLE>
<S> <C>
+1.1 -- Draft form of Underwriting Agreement.
*4.1 -- Restated Certificate of Incorporation of the Company (incorporated by
reference herein to Exhibit 3 to the Company's Annual Report on Form
10-K for the fiscal year ended December 31, 1993, File No. 1-3473).
*4.2 -- Bylaws of the Company, as amended through February 9, 1994
(incorporated by reference herein to Exhibit 3(a) to the Company's
Annual Report on Form 10-K for the fiscal year ended December 31,
1993, File No. 1-3473).
*4.3 -- Amendment to Restated Certificate of Incorporation of the Company
adding a new Article IX limiting Directors' Liability (incorporated by
reference herein to Exhibit 3(b) to the Company's Annual Report on
Form 10-K for the fiscal year ended December 31, 1993, File No.
1-3473).
*4.4 -- Certificate of Designation Establishing a Series of $2.20 Cumulative
Convertible Preferred Stock, dated as of January 26, 1983
(incorporated by reference herein to Exhibit 3(c) to the Company's
Annual Report on Form 10-K for the fiscal year ended December 31,
1993, File No. 1-3473).
*4.5 -- Certificate of Designation Establishing a Series A Participating
Preferred Stock, dated as of December 16, 1985 (incorporated by
reference herein to Exhibit 3(d) to the Company's Annual Report on
Form 10-K for the fiscal year ended December 31, 1993, File No.
1-3473).
*4.6 -- Certificate of Amendment, dated as of February 9, 1994, to Restated
Certificate of Incorporation of the Company amending Article IV,
Article V, Article VII and Article VIII (incorporated by reference
herein to Exhibit 3(e) to the Company's Annual Report on Form 10-K for
the fiscal year ended December 31, 1993, File No. 1-3473).
*4.7 -- 12 3/4% Subordinated Debentures due March 15, 2001, Form of Indenture,
dated March 15, 1983 (incorporated by reference herein to Exhibit 4(b)
to Registration Statement No. 2-81960).
*4.8 -- 13% Exchange Notes due December 1, 2000, Indenture, dated February 8,
1994 (incorporated by reference herein to Exhibit 2 to the Company's
Registration Statement on Form 8-A filed March 2, 1994).
*4.9 -- Rights Agreement dated December 16, 1985 between the Company and
Chemical Bank, N.A. successor to InterFirst Bank Fort Worth, N.A.
(incorporated by reference herein to Exhibit 4(i) to the Company's
Annual Report on Form 10-K for the fiscal year ended September 30,
1985, File No. 1-3473).
*4.10 -- Amendment to Rights Agreement dated December 16, 1985 between the
Company and Chemical Bank, N.A. (incorporated by reference herein to
Exhibit 4(c) to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 1992, File No. 1-3473).
*4.11 -- Forbearance Agreement dated as of March 24, 1993 between the Company
and MetLife Security Insurance Company of Louisiana (incorporated by
reference herein to Exhibit 4(n) to the Company's Annual Report on
Form 10-K for the fiscal year ended December 31, 1992, File No.
1-3473).
*4.12 -- Amendment to the Forbearance Agreement dated as of November 12, 1993
between the Company and MetLife Security Insurance Company of
Louisiana (incorporated by reference herein to Exhibit 4(o) to the
Company's Registration Statement No. 33-68282 on Form S-4).
</TABLE>

II-2
<PAGE> 110

<TABLE>
<S> <C>
*4.13 -- Memorandum of Understanding dated as of August 31, 1993 between the
Company and MetLife Security Insurance Company of Louisiana
(incorporated by reference herein to Exhibit 10(q) of the Company's
Registration Statement No. 33-68282 on Form S-4).
*4.14 -- Amended Memorandum of Understanding dated as of December 14, 1993
between the Company and MetLife Security Insurance Company of
Louisiana (incorporated by reference herein to Exhibit 4(p) of the
Company's Registration Statement No. 33-68282 on Form S-4).
*4.15 -- Stock Purchase Agreement dated as of February 9, 1994 between the
Company and MetLife Security Insurance Company of Louisiana
(incorporated by reference herein to Exhibit 4(i) to the Company's
Annual Report on Form 10-K for the fiscal year ended December 31,
1993, File No. 1-3473).
*4.16 -- Registration Rights Agreement dated February 9, 1994 between the
Company and MetLife Security Insurance Company of Louisiana
(incorporated by reference herein to Exhibit 4(j) to the Company's
Annual Report on Form 10-K for the fiscal year ended December 31,
1993, File No. 1-3473).
*4.17 -- Call Option Agreement dated February 9, 1994 between the Company and
MetLife Security Insurance Company of Louisiana (incorporated by
reference herein to Exhibit 4(k) to the Company's Annual Report on
Form 10-K for the fiscal year ended December 31, 1993, File No.
1-3473).
*4.18 -- Tesoro Exploration and Production Company's Loan Agreement dated as of
October 29, 1993 (incorporated by reference herein to Exhibit 4(b) to
the Company's report on Form 10-Q for the quarter ended September 30,
1993, File No. 1-3473).
*4.19 -- Agreement for Waiver and Substitution of Collateral dated as of
September 30, 1993 by and between Tesoro Alaska Petroleum Company and
the State of Alaska (incorporated by reference herein to Exhibit 4(c)
to the Company's report on Form 10-Q for the quarter ended September
30, 1993, File No. 1-3473).
*4.20 -- Credit Agreement (the "Credit Agreement") dated as of April 20, 1994
among the Company and Texas Commerce Bank National Association ("TCB")
as Issuing Bank and as Agent, and certain other banks named therein
(incorporated by reference herein to Exhibit 10.1 to the Company's
report on Form 10-Q for the quarter ended March 31, 1994, File No.
1-3473).
*4.21 -- Guaranty Agreement dated as of April 20, 1994 among various
subsidiaries of the Company and TCB, as Issuing Bank and as Agent, and
certain other banks named therein (incorporated by reference herein to
Exhibit 10.2 to the Company's report on Form 10-Q for the quarter
ended March 31, 1994, File No. 1-3473).
*4.22 -- Mortgage, Deed of Trust, Assignment of Production, Security Agreement
and Financing Statement dated as of April 20, 1994 from Tesoro
Exploration and Production Company, entered into in connection with
the Credit Agreement (incorporated by reference herein to Exhibit 10.3
to the Company's report on Form 10-Q for the quarter ended March 31,
1994, File No. 1-3473)
*4.23 -- Deed of Trust, Security Agreement and Financing Statement dated as of
April 20, 1994 among Tesoro Alaska Petroleum Company, TransAlaska
Title Insurance Agency, Inc., as Trustee, and TCB, as Agent, entered
into in connection with the Credit Agreement (incorporated by
reference herein to Exhibit 10.4 to the Company's report on Form 10-Q
for the quarter ended March 31, 1994, File No. 1-3473).
*4.24 -- Pledge Agreement dated as of April 20, 1994 by the Company in favor of
TCB, entered into in connection with the Credit Agreement
(incorporated by reference herein to Exhibit 10.5 to the Company's
report on Form 10-Q for the quarter ended March 31, 1994, File No.
1-3473).
</TABLE>

II-3
<PAGE> 111

<TABLE>
<S> <C>
*4.25 -- Security Agreement (Accounts and Inventory) dated as of April 20, 1994
between the Company and TCB, entered into in connection with the
Credit Agreement (incorporated by reference herein to Exhibit 10.6 to
the Company's report on Form 10-Q for the quarter ended March 31,
1994, File No. 1-3473).
*4.26 -- Security Agreement (Accounts and Inventory) dated as of April 20, 1994
between Tesoro Alaska Petroleum Company and TCB, entered into in
connection with the Credit Agreement (incorporated by reference herein
to Exhibit 10.7 to the Company's report on Form 10-Q for the quarter
ended March 31, 1994, File No. 1-3473).
*4.27 -- Security Agreement (Accounts) dated as of April 20, 1994 between
Tesoro Petroleum Distributing Company and TCB, entered into in
connection with the Credit Agreement (incorporated by reference herein
to Exhibit 10.8 to the Company's report on Form 10-Q for the quarter
ended March 31, 1994, File No. 1-3473).
*4.28 -- Security Agreement (Accounts and Inventory) dated as of April 20, 1994
between Tesoro Exploration and Production Company and TCB, entered
into in connection with the Credit Agreement (incorporated by
reference herein to Exhibit 10.9 to the Company's report on Form 10-Q
for the quarter ended March 31, 1994, File No. 1-3473).
*4.29 -- Security Agreement (Accounts and Inventory) dated as of April 20, 1994
between Tesoro Refining, Marketing & Supply Company and TCB, entered
into in connection with the Credit Agreement (incorporated by
reference herein to Exhibit 10.10 to the Company's report on Form 10-Q
for the quarter ended March 31, 1994, File No. 1-3473).
+4.30 -- $15,000,000 Construction Loan Agreement dated May 26, 1994, between
National Bank of Alaska and Tesoro Alaska Petroleum Company.
+5.1 -- Opinion of Fulbright & Jaworski L.L.P.
23.1 -- Consent of Deloitte & Touche.
+23.2 -- Consent of Fulbright & Jaworski L.L.P. (included in Exhibit 5.1).
**23.3 -- Consent of Netherland, Sewell & Associates, Inc.
24.1 -- Power of Attorney (included on signature page of original filing).
</TABLE>

- ---------------

+ To be filed by amendment.

* Incorporated by reference as shown.

** Previously filed.

ITEM 17. UNDERTAKINGS.

The undersigned Registrant hereby undertakes that, for purposes of
determining any liability under the Securities Act, each filing of the
Registrant's annual report pursuant to Section 13(a) or Section 15(d) of the
Exchange Act that is incorporated by reference in this Registration Statement
shall be deemed to be a new registration statement relating to the securities
offered therein, and the offering of such securities at that time shall be
deemed to be the initial bona fide offering thereof.

Insofar as indemnification for liabilities arising under the Securities Act
may be permitted to directors, officers and controlling persons of the
Registrant pursuant to the foregoing provisions, or otherwise, the Registrant
has been advised that in the opinion of the Securities and Exchange Commission
such indemnification is against public policy as expressed in the Securities Act
and is, therefore, unenforceable. In the event that a claim for indemnification
against such liabilities (other than the payment by the Registrant of expenses
incurred or paid by a director, officer or controlling person of the Registrant
in the successful defense of any action, suit or proceeding) is asserted by such
director, officer or controlling person in connection with the securities being
registered, the Registrant will, unless in the opinion of its counsel the matter
has been

II-4
<PAGE> 112

settled by controlling precedent, submit to a court of appropriate jurisdiction
the question whether such indemnification by it is against public policy as
expressed in the Securities Act and will be governed by the final adjudication
of such issue.

The undersigned Registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities
Act, the information omitted from the form of prospectus filed as part of
this Registration Statement in reliance upon Rule 430A and contained in a
form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or
(4) or 497(h) under the Securities Act shall be deemed to be part of this
Registration Statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities
Act, each post-effective amendment that contains a form of prospectus shall
be deemed to be a new Registration Statement relating to the securities
offered therein, and the offering of such securities at that time shall be
deemed to be the initial bona fide offering thereof.

II-5
<PAGE> 113

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the Registrant
certifies that it has reasonable grounds to believe that it meets all of the
requirements for filing on Form S-3 and has duly caused this Registration
Statement to be signed on its behalf by the undersigned, thereunto duly
authorized, in the City of San Antonio, State of Texas, on May 27, 1994.

TESORO PETROLEUM CORPORATION

By: /s/ BRUCE A. SMITH
------------------------------
Bruce A. Smith
Executive Vice President and
Chief Financial Officer

We the undersigned directors and officers of Tesoro Petroleum Corporation,
do hereby constitute and appoint Michael D. Burke and Bruce A. Smith, and each
of them, our true and lawful attorneys-in-fact and agents, with full power of
substitution and resubstitution in each of them, to do any and all acts and
things in our respective names and on our respective behalves in the capacities
indicated below that either of them may deem necessary or advisable to enable
Tesoro Petroleum Corporation to comply with the Securities Act of 1933 and any
rules, regulations and requirements of the Securities and Exchange Commission,
in connection with the Registration Statement, including specifically, but not
limited to, the power and authority to sign for us and any of us in our
respective names in the capacities indicated below any and all amendments
(including post-effective amendments) hereto and file the same, with all
exhibits thereto and other documents therewith, with the Securities and Exchange
Commission; and we do hereby ratify and confirm all that Michael D. Burke and
Bruce A. Smith, or either of them, shall do or cause to be done by virtue
hereof.

Pursuant to the requirements of the Securities Act of 1933, this
Registration Statement has been signed by the following persons in the
capacities and on the dates indicated.

<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
- --------------------------------------------- ---------------------------- -------------
<S> <C> <C>
/s/ CHARLES WOHLSTETTER* Chairman of the Board of May 27, 1994
- --------------------------------------------- Directors and Director
Charles Wohlstetter

/s/ MICHAEL D. BURKE* Director, President and May 27, 1994
- --------------------------------------------- Chief Executive Officer
Michael D. Burke (Principal Executive
Officer)

/s/ BRUCE A. SMITH Executive Vice President and May 27, 1994
- --------------------------------------------- Chief Financial Officer
Bruce A. Smith (Principal Financial
Officer and Principal
Accounting Officer)

/s/ RAY C. ADAM* Director May 27, 1994
- ---------------------------------------------
Ray C. Adam

/s/ ROBERT J. CAVERLY* Director May 27, 1994
- ---------------------------------------------
Robert J. Caverly

/s/ PETER M. DETWILER* Director May 27, 1994
- ---------------------------------------------
Peter M. Detwiler
</TABLE>

II-6
<PAGE> 114

<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
- --------------------------------------------- ---------------------------- -------------
<S> <C> <C>
/s/ STEVEN H. GRAPSTEIN* Director May 27, 1994
- ---------------------------------------------
Steven H. Grapstein

/s/ CHARLES F. LUCE* Director May 27, 1994
- ---------------------------------------------
Charles F. Luce

/s/ RAYMOND K. MASON, SR.* Director May 27, 1994
- ---------------------------------------------
Raymond K. Mason, Sr.

/s/ JOHN J. MCKETTA, JR.* Director May 27, 1994
- ---------------------------------------------
John J. McKetta, Jr.

/s/ STEWART G. NAGLER* Director May 27, 1994
- ---------------------------------------------
Stewart G. Nagler

/s/ WILLIAM S. SNEATH* Director May 27, 1994
- ---------------------------------------------
William S. Sneath

/s/ ARTHUR SPITZER* Director May 27, 1994
- ---------------------------------------------
Arthur Spitzer

/s/ MURRAY L. WEIDENBAUM* Director May 27, 1994
- ---------------------------------------------
Murray L. Weidenbaum

*By /s/ BRUCE A. SMITH
- ---------------------------------------------
Bruce A. Smith
as attorney-in-fact
</TABLE>

II-7
<PAGE> 115

EXHIBIT INDEX

<PAGE> 116

<PAGE> 117

- ---------------

+ To be filed by amendment.

* Incorporated by reference as shown.

** Previously filed.

<PAGE> 1

EXHIBIT 23.1

INDEPENDENT AUDITORS' CONSENT

Board of Directors and Stockholders
Tesoro Petroleum Corporation

We consent to the incorporation by reference in this Registration Statement
of Tesoro Petroleum Corporation on Form S-3 of our report dated February 10,
1994, included in the Annual Report on Form 10-K of Tesoro Petroleum Corporation
for the year ended December 31, 1993, and to the use of our report dated
February 10, 1994, appearing in the Prospectus, which is a part of this
Registration Statement. We also consent to the references to us under the
heading "Experts" in such Prospectus.

DELOITTE & TOUCHE

San Antonio, Texas

May 27, 1994