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

                                  FORM 10-K

(MARK ONE)

   [X]            ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D)
                    OF THE SECURITIES EXCHANGE ACT OF 1934

                 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1995

                                      OR
   [ ]          TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D)
                    OF THE SECURITIES EXCHANGE ACT OF 1934

                        COMMISSION FILE NUMBER 1-7667
                           ------------------------

                       SANTA FE ENERGY RESOURCES, INC.
            (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)

        DELAWARE                                        36-2722169
(STATE OF INCORPORATION)                    (I.R.S. EMPLOYER IDENTIFICATION NO.)

                         1616 SOUTH VOSS, SUITE 1000
                             HOUSTON, TEXAS 77057
         (ADDRESS OF PRINCIPAL EXECUTIVE OFFICES, INCLUDING ZIP CODE)

     REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE:  (713) 507-5000
                           ------------------------

         SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:

                                                           NAME OF EACH
    TITLE OF EACH CLASS                             EXCHANGE ON WHICH REGISTERED
Common Stock, $.01 par value                            New York Stock Exchange

      SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:  None

     Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X} No [ ]

     Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ].

     The aggregate market value of the voting stock held by non-affiliates of
the Registrant as of February 1, 1996 was approximately $875 million.

    Shares of Common Stock outstanding at February 1, 1996 -- 90,329,311.

                      DOCUMENTS INCORPORATED BY REFERENCE:

            PROXY STATEMENT DATED MARCH 21, 1996 .......... PART III

                                     PAGE i

                                TABLE OF CONTENTS

                                        PAGE
PART I
Items  1 and 2.  Business and
Properties...........................     1
     General.........................     1
     Corporate Restructuring
     Program.........................     2
     Reserves........................     3
     Domestic Development
     Activities......................     4
     Domestic Exploration
     Activities......................     6
     International Development
     Activities......................     7
     International Exploration
     Activities......................     9
     Drilling Activities.............    10
     Producing Wells.................    10
     Domestic Acreage................    11
     Foreign Acreage.................    11
     Current Markets for Oil and
     Gas.............................    11
     Santa Fe Energy Trust...........    12
     Other Business Matters..........    13

Item  3.  Legal Proceedings..........    18
Item  4.  Submission of Matters to a
           Vote of Security Holders..    18
           Executive Officers of
           Santa Fe..................    18

PART II
Item  5.  Market for Registrant's
           Common Equity and Related
           Stockholder Matters.......    19
Item  6.  Selected Financial Data....    20
Item  7.  Management's Discussion and
           Analysis of Financial
           Condition and Results Of
           Operations................    22
Item  8.  Financial Statements and
           Supplementary Data........    29
Item  9.  Changes in and
           Disagreements with
           Accountants on Accounting
           and Financial Disclosure..    29

PART III
Item 10.  Directors and Executive
           Officers of the Registrant    30
Item 11.  Executive Compensation.....    30
Item 12.  Security Ownership of
           Certain Beneficial Owners and
           Management................    30
Item 13.  Certain Relationships and
           Related Transactions......    30

PART IV
Item 14.  Exhibits, Financial
           Statement Schedules and
           Reports on Form 8-K.......    30
Signatures...........................    67

                                        i

                                    PART I

CERTAIN DEFINITIONS
     As used herein, the following terms have the specific meanings set out:
"Bbl" means barrel. "MBbl" means thousand barrels. "MMBbl" means million
barrels. "Mcf" means thousand cubic feet. "MMcf" means million cubic feet. "Bcf"
means billion cubic feet. "BOE" means barrel of oil equivalent. "MBOE" means
thousand barrels of oil equivalent and "MMBOE" means million barrels of oil
equivalent. Natural gas volumes are converted to barrels of oil equivalent using
the ratio of 6.0 Mcf of natural gas to 1.0 barrel of crude oil. Unless otherwise
indicated, natural gas volumes are stated at the official temperature and
pressure basis of the area in which the reserves are located. "Replacement cost"
refers to a fraction, of which the numerator is equal to the costs incurred by
the Company for property acquisition, exploration and development and of which
the denominator is equal to proved reserve additions from extensions,
discoveries, improved recovery, acquisitions and revisions of previous
estimates. "Improved recovery," "enhanced oil recovery" and "EOR" include all
methods of supplementing natural reservoir forces and energy, or otherwise
increasing ultimate recovery from a reservoir, such as waterfloods, cyclic
steam, steam drive and CO2 (carbon dioxide) injection and fireflood projects.
"Heavy oil" is low gravity, high viscosity crude oil.

ITEMS 1 AND 2.  BUSINESS AND PROPERTIES

GENERAL

     Santa Fe Energy Resources, Inc. ("Santa Fe" or the "Company") is engaged in
the exploration, development and production of crude oil and natural gas in the
continental United States and in certain foreign areas. At December 31, 1995 the
Company had worldwide proved reserves totaling 320.1 MMBOE (consisting of
approximately 279.2 MMBbls of oil and approximately 245.1 Bcf of natural gas),
of which approximately 92% were domestic reserves and approximately 8% were
foreign reserves. During 1995 the Company's worldwide production aggregated
approximately 33.3 MMBOE, of which approximately 72% was crude oil and
approximately 28% was natural gas. A substantial portion of the Company's
domestic oil production is in long-lived fields with well-established production
histories. With the sales of non-core properties pursuant to the Company's
corporate restructuring program (see "-- Corporate Restructuring Program"), the
Company has focused its activities in three domestic core areas -- the Permian
Basin in Texas and New Mexico, the offshore Gulf of Mexico and the San Joaquin
Valley of California -- as well as in Argentina and Indonesia.

     Santa Fe was incorporated in Delaware in 1971 as Santa Fe Natural
Resources, Inc., a wholly owned subsidiary of a predecessor of Santa Fe Pacific
Corporation ("SFP"). On January 8, 1990 Santa Fe Energy Company, which
previously conducted a substantial portion of Santa Fe's domestic exploration
and development operations, merged into Santa Fe. Santa Fe thereafter changed
its name to Santa Fe Energy Resources, Inc. On March 8, 1990 Santa Fe sold
11,700,000 previously unissued shares of common stock in initial public
offerings. On December 4, 1990 SFP distributed all of the shares of Santa Fe's
common stock it held to its shareholders. In May 1992 Adobe Resources
Corporation ("Adobe") was merged with and into the Company (the "Adobe Merger").

     For the five years ended December 31, 1995 the Company has replaced
approximately 161% of its production at an average replacement cost of $4.89 per
BOE. Over the last five years, the Company has increased its overall production
by increasing production from its existing properties and through acquisitions,
and has reduced its overall cost structure in order to enhance operating results
and to mitigate the Company's financial exposure in a low oil and natural gas
price environment. For example, over the five-year period ended December 31,
1995, Santa Fe has increased its average daily production from 71.4 MBOE per day
in 1991 to 91.3 MBOE per day in 1995 and has reduced its average production
costs (including related production, severance and ad valorem taxes) from $6.06
per BOE in 1991 to $5.15 per BOE in 1995.

                                        1

     Most of the Company's domestic crude oil production is located in
California and Texas, while its domestic natural gas production comes primarily
from the Gulf of Mexico, New Mexico and Texas. During 1995 the Company's
domestic daily production averaged approximately 58.5 MBbls of crude oil and
137.7 MMcf of natural gas. Substantially all of the Company's oil and gas
production is sold at market responsive prices. The domestic crude oil marketing
activities of the Company are conducted through its Santa Fe Energy Products
Division ("Energy Products"), which is also engaged in crude oil trading. A
substantial portion of the Company's domestic natural gas production is
currently marketed under the terms of a sales contract with Hadson Corporation
("Hadson"). See "-- Current Markets for Oil and Gas."

     A substantial portion of the Company's domestic oil production is in
long-lived fields with well-established production histories and where enhanced
oil recovery ("EOR") methods are employed. As of December 31, 1995 approximately
65% of the Company's domestic proved crude oil and liquids reserves and 53% of
its 1995 average daily domestic production of crude oil and liquids were
attributable to the Midway-Sunset field in the San Joaquin Valley of California,
where the Company first began production in 1905. Nearly all of the reserves in
this field are heavy oil, the production of which depends primarily on steam
injection. As of December 31, 1995, an additional 26% of the Company's domestic
proved crude oil and liquids reserves and approximately 25% of its 1995 average
daily domestic production of crude oil and liquids were attributable to five
other oil producing properties: the Wasson and Reeves fields in the Permian
Basin of west Texas and the South Belridge, Kern River and Coalinga fields in
the San Joaquin Valley.

     The Company's foreign production is located in the El Tordillo and Sierra
Chata fields in Argentina and in the Salawati Basin and Salawati Island areas of
Indonesia. Production from the Argentine operations averaged 2,600 barrels of
oil and 11.9 MMcf of natural gas per day in 1995 and production from the
Indonesian operations averaged 5,200 barrels of oil per day in 1995. The
Company's Argentine natural gas production is from the Sierra Chata field, which
commenced production in the second quarter of 1995.

     The Company maintains an active exploration and development program, a
significant portion of which consists of EOR projects on the producing fields
discussed above. During 1995, Santa Fe spent $204.6 million on capital programs
and has budgeted $200.5 million of expenditures for 1996. The actual amount
expended by the Company in 1996 will be based upon numerous factors, the
majority of which are outside its control, including, without limitation,
prevailing oil and natural gas prices and the outlook therefor and the
availability of funds.

     In the United States, at December 31, 1995, the Company held oil and gas
rights to 337,631 net undeveloped leasehold and fee acres in 16 states and
offshore areas. Outside the United States, at December 31, 1995, the Company
held exploration rights with respect to an aggregate of 2,249,065 net
undeveloped acres in Argentina, Ecuador, Gabon and Indonesia.

CORPORATE RESTRUCTURING PROGRAM

     In the fourth quarter of 1993 the Company adopted a corporate restructuring
program which included (i) the concentration of capital spending in the
Company's core operating areas, (ii) the disposition of non-core assets, (iii)
the elimination of the $0.04 per share quarterly Common Stock dividend and (iv)
an evaluation of the Company's capital and cost structures to examine ways to
increase flexibility and strengthen the Company's financial performance. See
Note 2 to the Consolidated Financial Statements.

     The Company's capital program is concentrated in three domestic core areas
-- the Permian Basin in Texas and New Mexico, the offshore Gulf of Mexico and
the San Joaquin Valley of California -- as well as its productive areas in
Argentina and Indonesia. The domestic program includes exploration and
development activities in the Delaware, Strawn, Cisco-Canyon and Atoka Morrow
formations in west Texas and southeast New Mexico, a drilling program for the
offshore Gulf of Mexico natural gas properties and a drilling and workover
program in the San Joaquin Valley of

                                        2

California. Internationally, the program includes exploration and development
activities in Argentina, Indonesia, Ecuador and Gabon, including expansion of
the Company's Sierra Chata field in Argentina, where gas sales commenced in
April 1995.

     During 1993 the Company sold properties having combined production of 4,100
barrels of oil and 21.7 MMcf per day and estimated proved reserves of
approximately 16.7 MMBOE for total proceeds of $91.4 million, sold its natural
gas gathering and processing assets for Hadson securities and realized
approximately $11.3 million from the sale of its remaining Depositary Units in
Santa Fe Energy Trust (the "Trust") and $8.3 million from the sale of its
interest in certain other oil and gas properties. As a result of these
transactions, the Company disposed of substantially all of its inventory of
non-core properties. In 1995, the Company sold its holdings in Hadson for $55.2
million in cash. See Notes 2 and 3 of the Notes to Consolidated Financial
Statements.

     As a result of the review of its cost structure the Company implemented a
cost reduction program that included the reduction of its salaried work force by
approximately 20%, an improvement in the efficiency of its information systems
and reductions in other general and administrative costs.

     As a result of the review of its capital structure, in May 1994, in
concurrent public offerings, the Company issued $100.0 million of 11% Senior
Subordinated Debentures due 2004 (the "Debentures") and 10,700,000 shares of
$.732 Series A Convertible Preferred Stock (the "Series A Preferred"). The net
proceeds from the offerings, $187.5 million after deducting related costs and
expenses, were used to retire $132.3 million of existing long-term debt and to
pay $6.5 million in accrued interest and prepayment penalties due upon the
retirement of such debt and the remaining $48.7 million was used for working
capital purposes. The refinancing reduced required debt amortization in the
near-term and provided additional financial flexibility.

RESERVES

     The following tables set forth information regarding changes in the
Company's estimates of proved net reserves from January 1, 1993 to December 31,
1995 and the balance of the Company's estimated proved developed reserves at
December 31 of each of the years 1992 through 1995.
<TABLE>
<CAPTION>
                                                                       INCREASES (DECREASES)
                                                   -------------------------------------------------------------
                                        BALANCE                                             NET
                                          AT       REVISION               EXTENSIONS,    PURCHASES                 BALANCE
                                       BEGINNING      OF                  DISCOVERIES    (SALES) OF                 AT END
                                          OF       PREVIOUS    IMPROVED       AND         MINERALS                    OF
                                        PERIOD     ESTIMATES   RECOVERY    ADDITIONS      IN PLACE    PRODUCTION    PERIOD
                                       ---------   ---------   --------   ------------   ----------   ----------   --------
<S>                                      <C>         <C>         <C>          <C>           <C>          <C>         <C>
PROVED RESERVES AT DECEMBER 31, 1993:
    Oil and Condensate (MMBbls)......    255.1       (10.8)      26.7          6.2           (4.7)       (24.3)      248.2
    Gas (Bcf)........................    277.5        26.7         --         55.9          (36.7)       (60.4)      263.0
    Oil Equivalent (MMBOE)...........    301.5        (6.3)      26.7         15.4          (10.9)       (34.4)      292.0
PROVED RESERVES AT DECEMBER 31, 1994:
    Oil and Condensate ((MMBbls).....    248.2        15.2       13.9          5.5           (0.5)       (24.0)      258.3
    Gas (Bcf)........................    263.0        (2.7)       0.9         36.2           (5.1)       (49.9)      242.4
    Oil Equivalent (MMBOE)...........    292.0        14.7       14.1         11.5           (1.3)       (32.3)      298.7
PROVED RESERVES AT DECEMBER 31, 1995:
    Oil and Condensate (MMBbls)......    258.3        18.2       16.1          4.4            6.3        (24.1)      279.2
    Gas (Bcf)........................    242.4         2.3        0.2         36.9           18.0        (54.7)      245.1
    Oil Equivalent (MMBOE)...........    298.7        18.5       16.2         10.7            9.3        (33.3)      320.1(a)
<CAPTION>
                                                                                                  DECEMBER 31,
                                                                                   ------------------------------------------
                                                                                      1995       1994       1993       1992
                                                                                   ---------  ---------  ---------  ---------
<S>                                                                                   <C>        <C>        <C>        <C>
PROVED DEVELOPED RESERVES (MMBOE)...............................................      253.6      224.5      225.5      248.4
</TABLE>
------------
  (a) At December 31, 1995, 3.8 MMBOE were subject to a 90% net profits
      interest held by Santa Fe Energy Trust. See "-- Santa Fe Energy Trust."

                                        3

     Historically, the Company has utilized active development and exploration
programs as well as selected acquisitions to replace its reserves depleted by
production. The Company has increased its proved reserves (net of production and
sales) by approximately 26% over the five years ended December 31, 1995. Most of
such increases are attributable to proved reserve additions from the Company's
producing oil properties in the San Joaquin Valley of California and the Permian
Basin in west Texas, proved reserves acquired in the Adobe Merger and other
purchases of oil and gas reserves.

     Ryder Scott Company ("Ryder Scott"), a firm of independent petroleum
engineers, prepared the above estimates of the Company's total proved reserves
as of December 31, 1992 through 1995.

     During 1995 the Company filed Energy Information Administration Form 23
which reported natural gas and oil reserves for the year 1994. On an equivalent
barrel basis, the reserve estimates for the year 1994 contained in such report
and those reported herein for the year 1994 do not differ by more than five
percent.

DOMESTIC DEVELOPMENT ACTIVITIES

     The Company is engaged in development activities primarily through the
application of thermal EOR techniques to its heavy oil properties in the San
Joaquin Valley, the use of secondary waterfloods and tertiary CO2 floods on its
properties in other mature fields and the development of producing properties
discovered or acquired by the Company. Thermal EOR operations involve the
injection of steam into a reservoir to raise the temperature and reduce the
viscosity of the heavy oil, facilitating the flow of the oil into producing
wellbores. The Company has operated thermal EOR projects in the San Joaquin
Valley since the mid-1960s. Similarly, the Company has extensive experience in
the use of waterfloods, which involves the injection of water into a reservoir
to drive hydrocarbons into producing wellbores. The Company has an interest in
more than 50 waterflood projects, and additional projects are planned for the
future. Following the waterflood phase, certain fields may continue to produce
in response to tertiary EOR projects, such as the injection of CO2 which mixes
miscibly with the oil and improves the displacement efficiency of the water
injection. The Company's principal CO2 floods are in the Wasson field and are
operated by affiliates of Shell Oil Company, ARCO and Amoco.

     Set forth below is a discussion of some of the Company's principal
development projects. The Company has operated in the Midway-Sunset and Wasson
fields since 1905 and 1939, respectively. The Company acquired interests in the
South Belridge field in 1987 and in January 1991 expanded its holdings in the
field with the purchase of additional properties. The Company's interests in the
Kern River and Coalinga fields were acquired in 1905 and 1977, respectively. The
Gulf of Mexico fields were discovered on leases held by the Company or acquired
as producing properties, while the southeastern New Mexico properties were
acquired as undeveloped properties.

     SAN JOAQUIN VALLEY

     MIDWAY SUNSET. The Company owns a 100% working interest (92% average net
revenue interest) in over 10,000 gross acres and 2,300 active wells in the
Midway Sunset field. Substantially all the oil produced from the Midway Sunset
field is heavy crude oil produced principally by cyclic steam and steamflood
operations from Pleistocene and Miocene reservoirs at depths less than 2,000
feet. These steam stimulation operations were initiated in the field in the
mid-1960s. During 1995 the Midway Sunset field accounted for approximately 53%
of the Company's domestic crude oil and liquids production.

     At December 31, 1995 the Midway Sunset field accounted for approximately
65% of the Company's domestic proved crude oil and liquid reserves. Reservoir
engineering studies prepared on behalf of the Company indicate significant
additions to its proved reserves in this field can continue to be made through
additional EOR and development projects. The Company has identified a
substantial number of locations that could be drilled in the field, depending in
part on future prices and economic conditions. During 1995 the Company drilled
173 development wells in the field.
                                      4

     SOUTH BELRIDGE. The South Belridge field is located 15 miles north of the
Midway-Sunset field. The Company operates three leases in the field which
produce heavy oil from the shallow Tulare sands and lighter low viscosity oil
from the deeper Diatomite reservoirs. Steamflood operations in the lower Tulare
sands are in progress on one of three leases and plans call for flooding the
remaining Tulare sands on this lease and all Tulare sands on another lease in
the coming years. Waterflood operations in the Diatomite reservoir have been
initiated on two leases and the Company expects to expand these operations to
include the rest of the developed area.

     COALINGA. The Coalinga field is located 55 miles southwest of Fresno,
California. Successful steamfloods have been conducted in the Lower Temblor
Sands on three properties in which the Company owns interests in the field.
During the next several years, the Company plans to expand steam floods in the
Upper and Lower Temblor Sands. Most of the facilities required for these
projects are already in place.

     KERN RIVER. The Company has a 100% working interest (91% average net
revenue interest) in four properties in the Kern River field which is located
near Bakersfield, California. The Company operates over 300 wells and a large
steam generation plant on the properties. The Lower Kern River Series sands have
been successfully steamflooded on three of the properties. During the past
several years the Company has conducted an ongoing infill drilling and
redevelopment program to convert the operations to expanded cyclic steaming. At
the conclusion of the cyclic steaming program, the Company will redeploy
steamflood operations into the upper sands of the Kern River Series on all four
properties.

     PERMIAN BASIN

     WASSON. The Company's interests in this field consist principally of
royalty and working interests in three units which are presently under CO2flood.
Most of the expenditures for plant, facilities, wells and equipment necessary
for such tertiary recovery projects have been made. In addition, while
expenditures relating to the purchase of CO2 for the Wasson field are expected
to continue, CO2 can be recycled and, therefore, such expenditures should
decline in the future.

     During 1995 the Wasson field accounted for approximately 8.0% of the
Company's domestic crude oil and liquids production and at December 31, 1995 the
field accounted for approximately 10.5% of the Company's domestic proved crude
oil and liquids reserves. Since initiation of CO2 flooding operations in 1984,
the field's previous production decline has been reversed. Reservoir engineering
studies prepared on behalf of the Company indicate significant additions to
proved reserves can be made through additional EOR and development projects.

     REEVES. The Company owns a 72% average net revenue interest in the Reeves
field, which is located seven miles east of the Wasson field in west Texas. The
field has been under waterflood since 1965. During 1995, 45 wells were drilled
and 20 wells were worked over as part of a program to infill drill the unit to
20-acre spacing and enhance current waterflood operations. Based on the
successes of the prior year's program, the Company plans to continue the infill
drilling and workover program in this field in 1996.

     NEW MEXICO. During 1995 the Company continued its activity in the light-oil
Delaware play in Lea and Eddy Counties of southeastern New Mexico. A total of 22
gross (6.5 net) development wells were completed in 1995 and net production from
this area in December 1995 totaled approximately 1,300 barrels of oil and 2.1
MMcf of natural gas per day. The Company plans to drill additional development
wells in 1996.

     Also in southeastern New Mexico, the Company participated in 2 gross (2
net) wells in 1995 in the light oil and gas Cisco-Canyon project and all major
facilities were completed by mid-year. The Company's net production from the
project is approximately 1,200 barrels of liquids and 8.8 MMcf of natural gas
per day from eight wells. The Company plans to continue delineation of this
project which contains approximately 47 potential development locations.

                                        5
    OFFSHORE GULF OF MEXICO

     At December 31, 1995 offshore Gulf of Mexico properties accounted for 48%
of the Company's domestic proved natural gas reserves and during 1995 these
properties accounted for approximately 57% of the Company's domestic natural gas
production.

     Year-end net offshore Gulf of Mexico deliverability was over 3,600 barrels
of oil per day and 92 MMcf of gas per day from 54 fields. The Company operates
16 producing fields on 22 blocks with three Company-operated blocks scheduled to
begin production in 1996. The Company's activities in the offshore Gulf of
Mexico are concentrated in the shallow water area (less than 400 feet of water)
where the costs of drilling, completion and operation are predictable and the
well developed pipeline infrastructure allows for relatively quick hookup of new
wells.

     During 1995 the Company participated in the drilling of 7 gross (4.6 net)
development wells, all of which resulted in successful completions. Four of
these wells commenced production in 1995 with the remainder expected to begin
production in 1996. Two of the wells are part of the development of the
Company's 100%-owned Galveston A-34 project, which resulted in a discovery in
1995. These two wells, together with the discovery well, tested at a combined
rate of over 23 MMcf of natural gas per day. Platform and pipeline construction
is underway and initial production is expected in mid-1996.

     During 1995 the Company completed platform and pipeline construction and
commenced production from its 55%-owned High Island A-442 project. Current
production is approximately 7.0 MMcf of natural gas per day and associated oil
and condensate. Additional development drilling is scheduled for mid-1996.

     In 1995 one of the Company's subsidiaries, Santa Fe Platform Management,
Inc., was designated to assist the Company in the management of the Company's
platform abandonment costs. Together with the involvement of a third party whose
primary consideration will be based on the realization of savings by the
Company, the subsidiary will attempt to find new ways to handle these costs in a
more efficient manner.

DOMESTIC EXPLORATION ACTIVITIES

     During 1995 the Company focused its domestic exploration activities in two
core areas, the Permian Basin of west Texas and southeastern New Mexico and the
offshore Gulf of Mexico. Overall the Company participated in 30 gross (14.7 net)
domestic exploratory wells in 1995, completing 22 gross (9.6 net) wells as
producers for a 65% net success rate. At year end there were 6 gross (1.7 net)
wells in various stages of drilling or completion.

     As of December 31, 1995 the Company held approximately 252,200 net
undeveloped leasehold acres in 16 states and offshore areas. The primary lease
terms expire with respect to 24% of such acreage in 1996, 15% in 1997, 7% in
1998, 15% in 1999 and the remainder thereafter. In addition, the Company owns
approximately 85,400 net acres of undeveloped fee minerals located primarily in
Texas.

     The Company also holds the oil and gas rights on approximately 8.1 million
net undeveloped acres in the western United States through direct ownership and
pursuant to lease option agreements from Santa Fe Pacific Railroad Company and
other former affiliates. These lands are located in high risk exploration areas.
Due to this risk, an agreement relating to substantially all of these oil and
gas rights has been entered into with another company. The Company will receive
a small revenue interest in the event exploration activities on lands subject to
these rights are successful.

     Set forth below is a brief discussion of some of the Company's principal
exploration programs.

    PERMIAN BASIN

     The Permian Basin continues as one of the Company's most active domestic
exploration area with the majority of the current drilling activity concentrated
in Lea and Eddy counties, New Mexico and Andrews and Martin counties, Texas.
During 1995 the Company participated in 15 gross (5.8 net) exploratory wells
with 13 gross (5.4 net) of these wells being completed for a 92% net success
rate. There were 4 gross (1.4 net) additional wells drilling or completing at
the end of the year.
                                      6

     In southeastern New Mexico, the Company's exploratory program concentrates
on multiple Permian and Pennsylvanian aged oil and gas reservoirs ranging in
depth from 1,500 to 16,000 feet. The focus in 1995 was to drill for deeper, gas
bearing objectives which also provide exposure to shallower Delaware and Bone
Springs oil reserves.

     In the first quarter of 1995 the Company completed a 260-square mile 3-D
seismic project in Midland and Andrews counties, Texas. Two wells were drilled
in 1995 and completed as oil producers. Additional drilling is planned for 1996.

    OFFSHORE GULF OF MEXICO

     The Company participated in 12 gross (5.8 net) exploratory wells in 1995,
including 9 gross (4.2 net) discovery wells, for a 72% net success rate. The
Company's offshore program is focused on prospects in shallow and moderate water
depths which display "hydrocarbon indicators" on seismic data. During 1995 an
agreement was reached with a third party which gives the Company access to 3-D
seismic data covering more than 500 blocks. The data will be used to add to the
Company's prospect inventory.

INTERNATIONAL DEVELOPMENT ACTIVITIES

     INDONESIA

     SALAWATI BASIN. The Company, through a wholly owned subsidiary, is engaged
in the production of crude oil in Indonesia through a joint venture (the
"Salawati Basin Joint Venture") formed in 1970 to explore for and develop
hydrocarbon reserves in the Salawati Basin area of Irian Jaya. At December 31,
1995, the Company held a 33 1/3% participation interest in, and acts as operator
for, the Salawati Basin Joint Venture. The Salawati Basin Joint Venture operates
under a production sharing contract (the "PSC") with the Indonesia state oil
agency ("Pertamina"), which had an initial term of 30 years and expires in the
year 2000. The Company is currently negotiating with Pertamina to extend the
contract for an additional 20 years and expects to sign the contract extension
in the first half of 1996. As of December 31, 1995 the contract covered an area
of approximately 235,000 acres. Production occurs from seven oil and three gas
condensate fields.

     The PSC entitles the Salawati Basin Joint Venture to recover all of its
expenditures related to the operation (the "cost recovery amount") before any
additional production is shared with Pertamina, which recovery is effected by
allocating to the Salawati Basin Joint Venture a portion of the crude oil
production sufficient, at the Indonesia government official crude oil price
("ICP"), to offset the cost recovery amount. The balance of production after
deducting the cost recovery amount is divided between the parties, with
approximately 66% allocated to Pertamina and 34% allocated to the Salawati Basin
Joint Venture. However, 25% of the 34% allocated to the Salawati Basin Joint
Venture (8.5% of total production) must be sold into the Indonesian domestic
market for $0.20 per barrel. The entire entitlement of the Salawati Basin Joint
Venture under the PSC, including the domestic market obligation, averaged
approximately 8.6 MBbls per day (approximately 2.9 MBbls per day net to the
Company) for the year ended December 31, 1995. The Salawati Basin Joint Venture
is required to pay Indonesian income taxes at the rate of 56%.

     SALAWATI ISLAND. The Company, through another subsidiary, has also entered
into a joint venture with Pertamina to explore the Salawati Island Block of
Irian Jaya. The effective date of this joint venture was April 23, 1990 with a
term of 30 years. At December 31, 1995 the Company held a 16 2/3% participation
interest in the block which covers approximately 1.1 million acres. The Company
and Pertamina (with its 50% interest) jointly operate the contract area. In 1991
a successful exploratory well was drilled and sales from the Matoa field began
in January of 1993. In December 1995 the Matoa field produced approximately 5.9
MBbls of oil per day (approximately 2.0 MBbls per day net to the Company) from
22 wells.

     Under the terms of the Salawati Island agreement, the joint venture
participants are allowed to recover the cost recovery amount, after an initial
20% portion (2.9% to the joint venture participants

                                      7

and 17.1% to Pertamina) has been deducted, by allocating to the joint venture
participants a portion of the crude oil production ("cost oil") sufficient to
offset the cost recovery amount. All unrecovered costs in any calendar year can
be carried forward to future years. The balance of production after allocation
of cost oil is allocated approximately 85.5% to Pertamina and 14.5% to the other
Salawati Island Joint Venture participants. However, 7.25% of the gross
production allocated to the joint venture participants must be sold into the
Indonesian domestic market for 10% of ICP.

     TUBAN. In December 1995 on the Tuban block on the island of Java, the
Company tested the Mudi No. 5, the fifth successful test of the Tuban Limestone
formation on the Mudi prospect. The well tested at combined flow rates of
approximately 10,500 barrels of 35 degree API gravity oil per day with
individual flowing tubing pressures of 225 pounds per square inch through a 1
1/4 inch choke. The tests were conducted on approximately 535 feet of
hydrocarbon bearing rock between depths of 8,365 to 8,900 feet. Tests of the
other successful wells ranged from 1,350 to 5,000 barrels of oil per day. The
Company and its partners have submitted a plan of development to Pertamina and
are prepared to begin construction of the facilities required for development as
soon as approval is received. Commercial oil sales could begin as early as
mid-1997.

     The Company has a seismic program underway to delineate the extent of the
field and to further define similar anomolies in the area. The Company holds a
12.5% interest and operates the Mudi project through a joint operating body
comprised of Pertamina and the Company.

     ARGENTINA

     EL TORDILLO. In 1991 the Company acquired an 18% non-operated working
interest (15.84% net revenue interest) in the El Tordillo field in Chubut
Province, Argentina. At that time, the field was producing approximately 10,500
barrels of oil per day. As of December 31, 1995 the Company and its partners
have completed 260 workovers and drilled 17 new wells, expanded the existing
waterflood pilots and initiated one new waterflood pilot, increasing production
to approximately 17,000 barrels of oil per day. The Company expects the drilling
and workover programs to continue through 1996 and anticipates the expansion of
the existing waterflood projects.

     The joint venture group is allowed to sell crude oil produced from this
field into the open market. There is a 12% royalty on gross production and the
joint venture is taxed at a 30% rate after deductions for capitalized costs and
expenses.

     SIERRA CHATA. In April 1993 the Company completed the Sierra Chata X-1 as a
successful natural gas and condensate exploratory test in Chihuidos Block,
Neuquen Province, Argentina. Nine additional successful wells have been drilled
and the combined deliverability of the ten wells is approximately 150 MMcf of
natural gas per day with a carbon dioxide content of approximately 6%. The
Company has a 19.9% working interest in the Block. The Company and its partners
have built a gas processing facility and a 40-mile gathering pipeline which
transports production from the field and interconnects with two main
transmission lines owned by a third party that transport gas to Buenos Aires and
other major markets. Sales of production from the Sierra Chata field commenced
in April 1995 under a gas contract for a maximum of 106 MMcf per day with
"take-or-pay" and "delivery-or-pay" obligations with MetroGas S.A., a Buenos
Aires gas distribution company. Under the terms of the contract, MetroGas is
required to take at least 90% of the contract maximum in the Argentine winter
months and at least 80% of the contract maximum in the Argentine summer months.
Natural gas produced in excess of the contract requirements is sold on the spot
market when possible. There is a 12% royalty and a 1% provincial tax on gross
production and the joint venture is taxed at a 30% rate after deductions for
capitalized costs and expenses.

     Three additional wells have been drilled to extend the producing limits
established by the ten producing wells. Testing of these wells is scheduled to
be completed in the first quarter of 1996.

                                        8
INTERNATIONAL EXPLORATION ACTIVITIES

     In 1995 the Company participated in 8 gross (2.6 net) international
exploratory wells. Five of the wells (1.8 net) were completed as discoveries for
a 67% net success rate. At December 31, 1995 the Company held exploration
contracts in four countries covering 8.7 million acres (2.3 million net acres).
The Company intends to participate in the drilling of eleven exploratory wells
in 1996, including six wells in Indonesia, two wells in Argentina, two wells in
Ecuador and one well in Gabon.

     INDONESIA

     SUMATRA.  In the first quarter of 1995 the Company completed the North
Geragai No. 1 discovery well on the Jabung Block in central Sumatra. The well
tested at combined rates of 5,100 barrels of 52 degree API gravity oil plus 30
MMcf of gas and 350 barrels of condensate per day from multiple intervals. In
December 1995 the North Geragai No. 2, which tested only oil zones plus any
gas zones not tested in the No. 1 well, tested 2,800 barrels of 52 degree API
gravity oil and 9.1 MMcf of gas per day. In February 1996 the North Geragai
No. 3 tested at a combined rate of 2,800 barrels of 52 degree API gravity oil
and 2.4 MMcf of natural gas per day from two zones which also demonstrated
hydrocarbon producing capability in the first two wells. The North Geragai No.
4 is currently drilling. Based on the results of the No. 4 well, a plan of
development will be filed with Pertamina. The Company holds a 33 1/3% interest
and is the operator of the Jabung Block under the terms of a PSC with
Pertamina.

     In August 1995 the Company tested its Northeast Betera No. 1 exploratory
well, located on the Jabung Block approximately 25 miles northeast of the North
Geragai No. 1. The well encountered approximately 130 feet of hydrocarbon
bearing sands at depths of 4,908 to 5,164 feet. Three intervals totaling
approximately 84 feet of net pay tested at combined rates of 420 barrels of
condensate and 22 MMcf of natural gas (approximately 55% carbon dioxide) per
day. The test results of the well are being analyzed and a delineation well is
planned for mid-1996.

     In addition, in 1995 the Company signed a new contract for the 956 million
acre Bangko Block in south Sumatra. Two exploratory wells are planned for 1996
based on evaluation of existing seismic data. Santa Fe is operator and holds a
33 1/3% interest in the block. The Company's share of costs through the first
two exploratory wells will be paid by its partners.

     ECUADOR

     In January 1995 the Company signed a contract covering exploration rights
on Oriente Block 11 which is located in the north central portion of the Oriente
Basin in the northeast section of the country. The contract includes an initial
exploration period of four years with optional extensions. Seismic operations
began in the fourth quarter of 1995 and are expected to be completed in the
first quarter of 1996. The first exploratory well is scheduled to be drilled in
the third quarter of 1996. The Company is the operator and holds a 35% working
interest in the block.

     GABON

     During 1995 the Company participated in the drilling of the Tchatamba
Marine No. 1 on the Kowe permit, offshore Gabon. The well tested 4,545 barrels
per day of 46 degree API gravity oil from a 74-foot interval in the Upper
Madiela formation between 6,306 to 6,380 feet. Additional seismic is planned to
delineate the Tchatamba structure and further define numerous other prospects on
the block. In addition to drilling a confirmation well offsetting the discovery,
a second exploratory well is planned on the Kowe permit during the fourth
quarter of 1996. The Company holds a 25% working interest in the 614,200-acre
permit area.
                                        9
DRILLING ACTIVITIES

     The table below sets forth, for the periods indicated, the number of wells
drilled in which Santa Fe had an economic interest. As of December 31, 1995
Santa Fe was in the process of drilling or completing 6 gross (1.7 net) domestic
exploratory wells, 18 gross (10.3 net) domestic development wells, and 7 gross
(1.5 net) foreign development wells.
<TABLE>
<CAPTION>
                                                          YEAR ENDED DECEMBER 31,
                                        ------------------------------------------------------------
                                               1995                 1994                 1993
                                        ------------------   ------------------   ------------------
                                        GROSS       NET      GROSS       NET      GROSS       NET
                                        ------   ---------   ------   ---------   ------   ---------
<S>                                       <C>        <C>       <C>        <C>       <C>        <C>
Development Wells
  Domestic
     Completed as natural gas
        wells........................      13          6.3      17          4.4      21          6.0
     Completed as oil wells..........     271        234.5     136        101.4     237        180.0
     Dry holes.......................       4          1.5       4          2.5      10          3.6
  Foreign
     Completed as natural gas
     wells...........................       3          0.9       2          0.4       4          1.0
     Completed as oil wells..........      17          3.2      14          4.3       3          0.9
     Dry holes.......................       5          1.1       2          0.6      --           --
                                        ------   ---------   ------   ---------   ------   ---------
                                          313        247.5     175        113.6     275        191.5
                                        ------   ---------   ------   ---------   ------   ---------
Exploratory Wells
  Domestic
     Completed as natural gas
        wells........................      13          6.3       3          1.5       3          0.9
     Completed as oil wells..........       9          3.3       9          3.5       7          2.7
     Dry holes.......................       8          5.1      23          8.6      12          5.4
  Foreign
     Completed as natural gas
     wells...........................       2          0.8       1          0.5       2          0.4
     Completed as oil wells..........       3          0.9       1          0.3      --           --
     Dry holes.......................       3          0.8       6          2.1       4          1.3
                                        ------   ---------   ------   ---------   ------   ---------
                                           38         17.2      43         16.5      28         10.7
                                        ------   ---------   ------   ---------   ------   ---------
                                          351        264.7     218        130.1     303        202.2
                                        ======   =========   ======   =========   ======   =========
PRODUCING WELLS
     The following table sets forth Santa Fe's ownership in producing wells at
December 31, 1995:
<CAPTION>
                                                U.S.              ARGENTINA(1)        INDONESIA(2)             TOTAL
                                        ---------------------    --------------     -----------------     ---------------
                                        GROSS(3)       NET       GROSS     NET      GROSS(4)     NET      GROSS      NET
                                        ---------   ---------    ------    ----     ---------    ----     ------    -----
<S>                                       <C>           <C>        <C>      <C>        <C>        <C>     <C>       <C>
Oil..................................     11,891        5,262      371      67         380        122     12,642    5,451
Natural gas..........................        559          167       10       2           6          2        575      171
                                        ---------   ---------    ------    ----     ---------    ----     ------    -----
                                          12,450        5,429      381      69         386        124     13,217    5,622
                                        =========   =========    ======    ====     =========    ====     ======    =====
</TABLE>
___________
  (1) At December 31, 1995 two gross gas wells were shut-in.

  (2) Includes 90 gross wells which were shut-in at December 31, 1995.

  (3) Includes 54 gross wells with multiple completions.

  (4) Includes one gross well with multiple completions.

                                       10
DOMESTIC ACREAGE

     The following table summarizes Santa Fe's developed and undeveloped fee and
leasehold acreage in the United States at December 31, 1995. Excluded from such
information is acreage in which Santa Fe's interest is limited to royalty,
overriding royalty and other similar interests.

                                           UNDEVELOPED            DEVELOPED
                                       -------------------  --------------------
                STATE                   GROSS       NET       GROSS       NET
Alabama -- Offshore..................    --         --         23,040     12,480
Alabama -- Onshore...................    --         --            824        112
Arkansas.............................       314         45        816        180
California -- Offshore...............    --         --         17,280      1,781
California -- Onshore................     5,112      5,112     20,202     19,963
Colorado.............................       381        237      5,771      5,249
Kansas...............................        84         54      3,824        865
Louisiana -- Offshore................   225,895     93,851    198,101     71,599
Louisiana -- Onshore.................     1,574        454      9,036      2,102
Mississippi..........................        21          1      3,168        554
Montana..............................     4,558      1,536        670         43
New Mexico...........................   138,054    103,975     50,745     26,792
New York.............................    --         --            189         47
North Dakota.........................     2,643        666      4,530      1,025
Oklahoma.............................     2,708      1,551     20,466      7,328
Pennsylvania.........................        20         20         25          3
Texas -- Offshore....................    31,111     24,278     58,301     27,035
Texas -- Onshore.....................   109,276     96,258    180,172    127,531
Utah.................................       886        460      3,325      1,527
Wyoming..............................    16,257      9,133     22,972     10,809
                                       --------  ---------  ---------  ---------
                                        538,894    337,631    623,457    317,025
                                       ========  =========  =========  =========
FOREIGN ACREAGE
     The following table summarizes Santa Fe's foreign acreage at December 31,
1995:
                                        UNDEVELOPED              DEVELOPED
                                  ------------------------  --------------------
                                     GROSS         NET        GROSS       NET
Argentina.......................    2,147,987      529,045     93,238     18,004
Ecuador.........................      494,200      172,970     --         --
Gabon...........................      614,200      153,550     --         --
Indonesia.......................    5,393,359    1,393,500     11,460      2,072
                                  -----------  -----------  ---------  ---------
                                    8,649,746    2,249,065    104,698     20,076
                                  ===========  ===========  =========  =========
CURRENT MARKETS FOR OIL AND GAS

     The revenues generated by the Company's operations are highly dependent
upon the prices of, and demand for, oil and gas. For the last several years,
prices of these products have reflected a worldwide surplus of supply over
demand. The price received by the Company for its crude oil and natural gas
depends upon numerous factors, the majority of which are beyond the Company's
control, including economic conditions in the United States and elsewhere, the
world political situation as it affects OPEC, the Middle East (including the
current embargo of Iraqi crude oil from worldwide markets) and other producing
countries, the actions of OPEC and governmental regulation. The fluctuation in
world oil prices continues to reflect market uncertainty regarding OPEC's
ability to
                                       11

control member country production and underlying concern about the balance of
world demand for and supply of oil and gas. Decreases in the prices of oil and
gas have had, and could have in the future, an adverse effect on the Company's
development and exploration programs, proved reserves, revenues, profitability
and cash flow. See Item 7. "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- General."

     The market for heavy crude oil produced in California differs substantially
from the remainder of the domestic crude oil market, due principally to the
transportation and refining requirements associated with heavy crude. The profit
margin realized from the sale of heavy crude oil is generally lower than that
realized from the sale of light crude oil because the costs of producing heavy
oil are generally higher, and the sales price realized for heavy crude oil is
generally lower than the comparable costs and prices paid for light crude oils.

     From time to time the Company has hedged a portion of its oil and natural
gas production to manage its exposure to volatility in prices of oil and natural
gas. See Item 7. "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- General" for a discussion of the Company's hedging
activities.

     During 1995 affiliates of Shell Oil Company and Celeron Corporation
accounted for approximately 34% and 21%, respectively, of Energy Products' crude
oil sales (which with respect to certain properties includes royalty and working
interest owners' share of production). No other individual customer accounted
for more than 10% of the Company's crude oil and liquids revenues during 1995.
Substantially all of the Company's oil production is currently sold at
market-responsive prices that approximate spot prices. Availability of a ready
market for the Company's oil production depends on numerous factors, including
the level of consumer demand, the extent of worldwide oil production, the cost
and availability of alternative fuels, the availability of refining capacity,
the cost of and proximity of pipelines and other transportation facilities,
regulation by state and federal authorities and the cost of complying with
applicable environmental regulations.

     In December 1993 the Company signed a seven-year gas sales contract with
Hadson pursuant to the terms of which Hadson markets a substantial portion of
the Company's domestic natural gas production. Pursuant to such gas contract,
Hadson is required to pay the Company for all production delivered at a price
for such gas equal to stipulated published monthly index prices. Hadson is
obligated to use its best efforts to receive gas from the Company at delivery
points so as to maximize the net price received by the Company for such
production. Payment for purchases by Hadson are made in immediately available
funds no later than the last working day of the month following the month of
production.

SANTA FE ENERGY TRUST

     In November 1992 5,725,000 Depositary Units ("Depositary Units"), each
consisting of beneficial ownership of one unit of undivided interest in the
Trust and a $20 face amount beneficial ownership interest in a $1,000 face
amount zero coupon United States Treasury obligation maturing on February 15,
2008, were sold in a public offering. The assets of the Trust consist of certain
oil and gas properties conveyed by the Company. A total of $114.5 million was
received from public investors, of which $38.7 million was used to purchase the
Treasury obligations and $5.7 million was used to pay underwriting commissions
and discounts. The Company received the remaining $70.1 million and retained
575,000 Depositary Units. A portion of the proceeds received by the Company was
used to retire $30.0 million of debt and the remainder was used for general
corporate purposes. In the first quarter of 1994 the Company sold the remaining
575,000 Depositary Units it held for $11.3 million.

     The properties conveyed to the Trust consisted of two term royalty
interests in two production units in the Wasson field in west Texas and a net
profits royalty interest in certain royalty and working interests in a
diversified portfolio of properties located in twelve states. At December 31,
1995, 3.8 MMBOE of the Company's estimated proved reserves were subject to such
net profits interest. The reserve estimates included herein reflect the
conveyance of the Wasson term royalties to the Trust.

                                       12

     For any calendar quarter ending on or prior to December 31, 2002, the Trust
will receive additional royalty payments to the extent that such payments are
required to provide distributions of $0.40 per Depositary Unit per quarter. Such
additional royalty payments, if needed, will come from the Company's remaining
royalty interest in one of the production units in the Wasson field described
above, and are non-recourse to the Company. If such additional payments are
made, certain proceeds otherwise payable to the Trust in subsequent quarters may
be reduced to recoup the amount of such additional payments. The aggregate
amount of the additional royalty payments (net of any amounts recouped) is
limited to $20.0 million on a revolving basis. The Company was required to make
additional royalty payments totalling $0.4 million, $1.1 million and $0.5
million with respect to the distributions made by the Trust for operations in
1993, 1994 and 1995, respectively. Dependent on various factors, such as sales
volumes and prices and the level of operating costs and capital expenditures
incurred, proceeds payable to the Trust with respect to operations in subsequent
quarters may not be sufficient to make distributions of $0.40 per quarter. In
such instances the Company would be required to make additional royalty
payments.

OTHER BUSINESS MATTERS

  COMPETITION

     The Company faces competition in all aspects of its business, including,
but not limited to, acquiring reserves, leases, licenses and concessions;
obtaining goods, services and labor needed to conduct its operations and manage
the Company; and marketing its oil and gas. The Company's competitors include
multinational energy companies, government-owned oil and gas companies, other
independent producers and individual producers and operators. The Company
believes that its competitive position is affected by price, its geological and
geophysical capabilities and ready access to markets for production. Many
competitors have greater financial and other resources than the Company, more
favorable exploration prospects and ready access to more favorable markets for
their production. The Company believes that the well-defined nature of the
reservoirs in its long-lived oil fields, its expertise in EOR methods in these
fields, its active development and exploration position, its financial
flexibility and its experienced management may give it a competitive advantage
over some other producers.

  REGULATION OF CRUDE OIL AND NATURAL GAS

     The petroleum industry is subject to various types of regulation throughout
the world, including regulation in the United States by state and federal
agencies. Domestic legislation affecting the oil and gas industry is under
constant review for amendment or expansion, frequently increasing the regulatory
burden. Also, numerous departments and agencies, both federal and state, are
authorized by statute to issue and have issued rules and regulations binding on
the oil and gas industry and its individual members, compliance with which is
often difficult and costly and which may carry substantial penalties for
non-compliance. Although the regulatory burden on the oil and gas industry
increases the cost of doing business and, consequently, affects profitability,
generally these burdens do not appear to affect the Company any differently or
to any greater or lesser extent than other companies in the industry with
similar types and quantities of production. While the Company is a party to
several regulatory proceedings before governmental agencies arising in the
ordinary course of business, the Company does not believe that the outcome of
such proceedings will have a material adverse affect on its operations or
financial condition. Set forth below is a general description of certain state
and federal regulations which have an effect on the Company's operations.

     STATE REGULATION. State statutes and regulations require permits for
drilling operations, drilling bonds and reports concerning operations. Most
states in which the Company operates also have statutes and regulations
governing the conservation of oil and gas and the prevention of waste, including
the unitization or pooling of oil and gas properties and rates of production
from oil and gas wells. Rates of production may be regulated through the
establishment of maximum daily production allowables on a market demand or
conservation basis or both.
                                      13

     FEDERAL REGULATION. A portion of the Company's oil and gas leases are
granted by the federal government and administered by the Bureau of Land
Management ("BLM") and the Minerals Management Service ("MMS"), both of which
are federal agencies. Such leases are issued through competitive bidding,
contain relatively standardized terms and require compliance with detailed BLM
and MMS regulations and orders (which are subject to change by the BLM and the
MMS). For offshore operations, lessees must obtain MMS approval for exploration
plans and development and production plans prior to the commencement of such
operations. In addition to permits required from other agencies (such as the
Coast Guard, Army Corps of Engineers and Environmental Protection Agency),
lessees must obtain a permit from the BLM or the MMS prior to the commencement
of drilling.

     The interstate transportation of natural gas is regulated by the Federal
Energy Regulatory Commission ("FERC") under the Natural Gas Act of 1938 and, to
a lesser extent, the Natural Gas Policy Act of 1978 (collectively, the "Acts").
Since 1991, FERC's regulatory efforts have centered largely around its generic
rulemaking proceedings, Order No. 636. Through Order No. 636 and successor
orders, FERC has undertaken to restructure the interstate pipeline industry with
the goal of providing enhanced access to, and competition among, alternative gas
suppliers. By requiring interstate pipelines to "unbundle" their sales services
and to provide their customers with direct access to any upstream pipeline
capacity held by pipelines, Order No. 636 has enabled pipeline customers to
choose the levels of transportation and storage service they require, as well as
to purchase gas directly from third-party merchants other than the pipelines.

     Even though the implementation of Order No. 636 on individual interstate
pipelines is largely complete, nearly all of these individual restructuring
proceedings, as well as Order No. 636 itself and the regulations promulgated
thereunder, are subject to pending appellate review and could possibly be
substantially modified by the courts. Thus, while Order No. 636 has generally
facilitated the transportation of gas and the direct access to end-user markets,
the ultimate impact of these regulations on marketing production cannot be
predicted at this time.

     With the completion of the Order No. 636 implementation process on the FERC
level, FERC's natural gas regulatory efforts have turned towards a number of
other important policies, all of which could significantly affect the marketing
of gas. Some of the more notable of these regulatory initiatives include (i) a
series of orders in individual pipeline proceedings articulating a policy (now
pending court review) of generally approving the divestiture of pipeline-owned
gathering facilities to pipeline affiliates, (ii) FERC's on-going efforts to
promulgate standards for pipeline electronic bulletin boards, electronic data
exchange, and, most recently, basic business and operational practices of the
pipelines, (iii) a generic policy statement involving the pricing of interstate
pipeline capacity, (iv) efforts to refine FERC's regulations controlling the
operation of the secondary market for released pipeline capacity, (v) a policy
statement regarding market and other non-cost-based rates for interstate
pipeline transmission and storage capacity and (vi) an inquiry into the
appropriate nature and extent of continuing FERC regulation of offshore
pipelines.

     Recently, with the conclusion of the implementation of FERC Order No. 636
on the interstate pipelines, numerous states have begun the process of
implementing regulatory initiatives requiring local distribution companies
("LDCs") to develop (to various degrees) unbundled transportation and related
service options and rates. Typically, these programs are designed to allow LDCs'
commercial, industrial, and, in a few cases, residential, customers to have
access to transportation service on the LDC, coupled with an ability to select
third-party city-gate gas suppliers. These developments have already led a
number of industry participants to redirect significant marketing resources to
these emerging downstream markets.

  ENVIRONMENTAL REGULATION

     Various federal, state and local laws and regulations covering the
discharge of materials into the environment, or otherwise relating to the
protection of the environment, may affect the Company's

                                       14

operations and costs. In particular, the Company's oil and gas exploration,
development, production and EOR operations, its activities in connection with
storage and transportation of liquid hydrocarbons and its use of facilities for
treating, processing, recovering or otherwise handling hydrocarbons and wastes
therefrom are subject to stringent environmental regulation by governmental
authorities. Such regulation has increased the cost of planning, designing,
drilling, installing, operating and abandoning the Company's oil and gas wells
and other facilities. The Company has expended significant resources, both
financial and managerial, to comply with environmental regulations and
permitting requirements and anticipates that it will continue to do so in the
future in order to comply with stricter industry and regulatory safety standards
such as those described below. Although the Company believes that its operations
and facilities are in general compliance with applicable environmental
regulations, risks of substantial costs and liabilities are inherent in oil and
gas operations and there can be no assurance that significant costs and
liabilities will not be incurred in the future. Moreover, it is possible that
other developments, such as increasingly strict environmental laws, regulations
and enforcement policies thereunder, and claims for damages to property,
employees, other persons and the environment resulting from the Company's
operations, could result in substantial costs and liabilities in the future.
Although the resulting costs cannot be accurately estimated at this time, these
requirements and risks typically apply to companies with types, quantities and
locations of production similar to those of the Company and to the oil and gas
industry in general.

     OFFSHORE PRODUCTION. Offshore oil and gas operations are subject to
regulations of the United States Department of the Interior, the Department of
Transportation, the United States Environmental Protection Agency ("EPA") and
certain state agencies. In particular, the Federal Water Pollution Control Act
of 1972, as amended ("FWPCA"), imposes strict controls on the discharge of oil
and its derivatives into navigable waters. The FWPCA provides for civil and
criminal penalties for any discharges of petroleum in reportable quantities and,
along with the Oil Pollution Act of 1990 and similar state laws, imposes
substantial liability for the costs of oil removal, remediation and damages.

     SOLID AND HAZARDOUS WASTE. The Company currently owns or leases, and has in
the past owned or leased, numerous properties that have been used for production
of oil and gas for many years. Although the Company has utilized operating and
disposal practices that were standard in the industry at the time, hydrocarbons
or other solid wastes may have been disposed or released on or under the
properties owned or leased by the Company. State and federal laws applicable to
oil and gas wastes and properties have gradually become more strict. Under these
new laws, the Company has been, and in the future could be, required to remove
or remediate previously disposed wastes or property contamination (including
groundwater contamination) or to perform remedial plugging operations to prevent
future contamination.

     The Company generates hazardous and nonhazardous wastes that are subject to
the federal Resource Conservation and Recovery Act and comparable state
statutes. The EPA has limited the disposal options for certain hazardous wastes
and is considering the adoption of stricter disposal standards for nonhazardous
wastes. Furthermore, it is anticipated that additional wastes (which could
include certain wastes generated by the Company's oil and gas operations) will
in the future be designated as "hazardous wastes," which are subject to more
rigorous and costly disposal requirements. In response to the changing
regulatory environment, the Company has made certain changes in its operations
and disposal practices. For example, the Company has commenced remediation of
sites or replacement of facilities where its wastes have previously been
disposed.

     SUPERFUND. The Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA"), also known as the "superfund" law, imposes liability,
without regard to fault or the legality of the original conduct, on certain
classes of persons that contributed to the release of a "hazardous substance"
into the environment. These persons include the owner or operator of a site and
companies that disposed or arranged for the disposal of the hazardous substance
found at a site. CERCLA also authorizes the EPA and, in some cases, third
parties to take actions in responses to threats to the public health or the
environment and to seek to recover from the responsible classes of

                                       15

persons the costs they incur. In the course of its operations, the Company has
generated and will generate wastes that may fall within CERCLA's definition of
"hazardous substances." The Company may be responsible under CERCLA for all or
part of the costs to clean up sites at which such wastes have been disposed.

     The Company has been identified as one of over 250 potentially responsible
parties ("PRPs") at a superfund site in Los Angeles County, California. The site
was operated by a third party as a waste disposal facility from 1948 until 1983.
The EPA is requiring the PRPs to undertake remediation of the site in several
phases, which include site monitoring and leachate control, gas control and
final remediation. In November 1988 the EPA and a group of PRPs that includes
the Company entered into a consent decree covering the site monitoring and
leachate control phases of remediation. The Company was a member of the group
Coalition Undertaking Remediation Efforts ("CURE") which was responsible for
constructing and operating the leachate treatment plant. This phase is now
complete and the Company's share of costs with respect to this phase was $1.6
million ($0.9 million after recoveries from working interest participants in the
unit in which the wastes were generated). Another consent decree provides for
the predesign, design and construction of a gas plant to harness and market
methane gas emissions. The Company is a member of the New CURE group which is
responsible for the gas plant construction and operation and landfill cover.
Currently, New CURE is in the design stage of the gas plant. The Company's share
of costs of this phase is expected to be $3.0 million (based on an agreement
with other working interest participants in the unit to assume $1.3 million of
the original settlement amount, the Company's net share of such costs is
approximately $1.7 million) and such costs have been provided for in the
financial statements. The Company cannot currently estimate the cost of any
subsequent phases of work or final remediation which may be required by the EPA.
Another consent decree is currently being executed by the PRPs and will be
logged with the court for approval. This consent decree allows for the
settlement of the pending lawsuits against the municipalities and transporters
not named by the EPA. The settlement payment by such municipalities and
transporters totals approximately $70.0 million of which approximately $55.0
million will be credited against future expenses. The Company has entered into a
Joint Defense Agreement with the other PRPs to defend against a lawsuit filed
September 7, 1994 by ninety-five homeowners alleging, among other things,
nuisance, trespass, strict liability and infliction of emotional distress. At
this stage of the lawsuit the Company is not able to estimate costs or potential
liability.

     In 1989 Adobe received requests from the EPA for information pursuant to
Section 104(e) of CERCLA with respect to the D. L. Mud and Gulf Coast Vacuum
Services superfund sites located in Abbeville, Louisiana. With respect to the
Gulf Coast Site the Company has entered into a sharing agreement with other PRPs
to participate in the final remediation of the Gulf Coast site and a design plan
has been submitted and is awaiting approval by the EPA. The Company's share of
the remediation, which has been provided for in the financial statements, is
approximately $277,000 and includes its proportionate share of those PRPs who do
not have the financial resources to provide their share of the work at the site.
A former site owner has already conducted remedial activities at the D. L. Mud
Site under a state agency agreement.

     On April 4, 1994 the Company received a request from the EPA for
information pursuant to Section 104(e) of CERCLA and a letter ordering the
Company and seven other PRPs to negotiate with the EPA regarding implementation
of a remedial plan for a site located in Santa Fe Springs, California. The
Company owned the property on which the site is located from 1921 to 1932.
During that time the property was leased to another company and in 1932 the
property was sold to that company. During the time the other company leased or
owned the property, hazardous wastes were allegedly disposed at the site. The
EPA estimates that the total past and future costs for remediation will
approximate $9.4 million. The Company filed its response to the Section 104(e)
order setting forth its position and defenses based on the fact that the other
company was the lessee and operator of the site during the time the Company was
the owner of the property. However, the Company has also given its Notice of
Intent to comply with the EPA's order to prepare a remediation design plan. Six
of the other PRPs have also notified the EPA of their intent to comply. The cost
of such a remediation design plan is estimated

                                       16

to be $1.0 million. To date there has been no agreement on how to allocate costs
among the PRPs. The Company has provided for such costs in the financial
statements, assuming that the costs will be equally divided among the PRPs.

     On March 23, 1995 the Company and twelve other companies received notice
that they have been identified as PRPs by the California Department of Toxic
Substances Control (the "DTSC") as having generated and/or transported hazardous
waste to the Environmental Protection Corporation ("EPC") Eastside Landfill
during its fourteen-year operation from 1971 to 1985. EPC has since liquidated
all assets and placed the proceeds in trust for closure and post-closure
activities. However, these monies will not be sufficient to close the site. The
PRPs have entered into an enforceable agreement with the DTSC to characterize
the contamination at the site and prepare a focused remedial investigation and
feasibility study. The DTSC has agreed to implement reasonable measures to bring
new PRPs into the agreement. The DTSC will address subsequent phases of the
cleanup, including remedial design and implementation in a separate order
agreement. The cost of the remedial investigation and feasibility study is
estimated to be $1.0 million and the Company has provided $80,000 in the
financial statements as its estimated share of such costs. The costs of
subsequent phases cannot be estimated until the remedial investigation and
feasibility study is completed.

     AIR EMISSIONS. The operations of the Company, including most of its
operations in the San Joaquin Valley, are subject to local, state and federal
regulations for the control of emissions from sources of air pollution. Legal
and regulatory requirements in this area are increasing, and there can be no
assurance that significant costs and liabilities will not be incurred in the
future as a result of new regulatory developments. In particular, the 1990 Clean
Air Act Amendments will impose additional requirements that may affect the
Company's operations, including permitting of existing sources and control of
hazardous air pollutants. However, it is impossible to predict accurately the
effects, if any, of the Clean Air Act Amendments on the Company at this time.
The Company has been and may in the future be subject to administrative
enforcement actions for failure to comply strictly with air regulations or
permits. These administrative actions are generally resolved by payment of a
monetary penalty and correction of any identified deficiencies. Alternatively,
regulatory agencies may require the Company to forego construction or operation
of certain air emission sources.

     OTHER. The Company is subject to the requirements of the federal
Occupational Safety and Health Act ("OSHA") and comparable state statutes. The
OSHA hazard communication standard, the EPA community right-to-know regulations
under Title III of the federal Superfund Amendment and Reauthorization Act and
similar state statutes (such as California Proposition 65) require the Company
to organize information about hazardous materials used or produced in its
operations. Certain of this information must be provided to employees, state and
local governmental authorities and local citizens. The Company's facilities in
California are also subject to California Proposition 65, which was adopted in
1986 to address discharges and releases of, or exposures to, toxic chemicals in
the environment. Proposition 65 makes it illegal to knowingly discharge a listed
chemical if the chemical will pass (or probably will pass) into any source of
drinking water. It also prohibits companies from knowingly and intentionally
exposing any individual to such chemicals through ingestion, inhalation or other
exposure pathways without first giving a clear and reasonable warning.

     Although generally less stringent, the Company's foreign operations are
subject to similar foreign laws respecting environmental and worker safety
matters.

  INSURANCE COVERAGE MAINTAINED WITH RESPECT TO OPERATIONS

     The Company maintains insurance policies covering its operations in amounts
and areas of coverage normal for a company of its size in the oil and gas
exploration and production industry. These coverages include, but are not
limited to, workers' compensation, employers' liability, automotive liability
and general liability. In addition, an umbrella liability and operator's extra
expense policies are maintained. All such insurance is subject to normal
deductible levels. The Company does not insure

                                       17

against all risks associated with its business either because insurance is not
available or because it has elected not to insure due to prohibitive premium
costs.

  EMPLOYEES

     As of December 31, 1995, the Company had approximately 660 employees, 189
of whom were covered by a collective bargaining agreement which expired on
January 31, 1996 and is being renegotiated. The Company believes that its
relations with its employees are satisfactory.

ITEM 3.  LEGAL PROCEEDINGS

     The Company, its subsidiaries and other related companies are named
defendants in several lawsuits and named parties in certain governmental
proceedings arising in the ordinary course of business. For a description of
certain proceedings in which the Company is involved, see Items 1 and 2 "
Business and Properties -- Other Business Matters -- Environmental Regulation"
and Note 11 to the Consolidated Financial Statements. While the outcome of
lawsuits or other proceedings against the Company cannot be predicted with
certainty, the Company does not expect these matters to have a material adverse
effect on its financial position or results of operations.

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     None.

EXECUTIVE OFFICERS OF SANTA FE

     Listed below are the names, ages (as of January 1, 1996) and positions of
all executive officers of Santa Fe (excluding executive officers who are also
directors of Santa Fe) and their business experience during the past five years.
Unless otherwise stated, all offices were held with Santa Fe Energy Company
prior to its merger with Santa Fe. Each executive officer holds office until his
successor is elected or appointed or until his earlier death, resignation or
removal.

     HUGH L BOYT, 50 Senior Vice President -- Production since March 1, 1990.
From 1989 until March 1990, Mr. Boyt served as Corporate Production Manager.

     JERRY L BRIDWELL, 52  Senior Vice President -- Exploration and Land since
1986.

     MICHAEL J. ROSINSKI, 50  Senior Vice President -- Marketing and
Environmental since January 1996. From January 1995 until January 1996 Mr.
Rosinski served as Senior Vice President -- Administration and from September
1992 until January 1995 he served as Vice President and Chief Financial
Officer. Prior to joining Santa Fe, Mr. Rosinski was with Tenneco Inc. and its
subsidiaries for 24 years. From 1990 until August 1992 he was Executive
Director of Investor Relations.

     R. GRAHAM WHALING, 41  Senior Vice President and Chief Financial Officer
since January 1995. Mr. Whaling was with First Boston Corporation from 1989
until he joined Santa Fe. While with First Boston Corporation Mr. Whaling
served in various capacities including Vice President, Corporate Finance from
1991 to 1994 and Director, Corporate Finance from 1994 to 1995.

     E. EVERETT DESCHNER, 55  Vice President -- Engineering and Evaluation
since April 1990.

     C. ED HALL, 53  Vice President -- Public Affairs since March 1991.

     CHARLES G. HAIN, JR., 49 Vice President -- Human and Data Resources since
1994. Vice President -- Employee Relations from 1988 until 1994.

     DAVID L HICKS, 46  Vice President -- Law and General Counsel since March
1991.

     JOHN R. WOMACK, 57  Vice President -- Business Development since 1987.

                                       18

                                   PART II

ITEM 5.  MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS

     Santa Fe's common stock is listed on the New York Stock Exchange and trades
under the symbol SFR. The following table sets forth information as to the last
sales price per share of Santa Fe's common stock as quoted on the Consolidated
Tape System for each calendar quarter in 1995 and 1994.

                                        LOW    HIGH
                                        ---    ----
1995
     1st Quarter.....................   8       9 3/4
     2nd Quarter.....................   9 1/8  10 1/2
     3rd Quarter.....................   9      10 5/8
     4th Quarter.....................   8 1/2   9 7/8
1994
     1st Quarter.....................   8 1/2   9 7/8
     2nd Quarter.....................   7 5/8   9 3/4
     3rd Quarter.....................   8 3/4   9 7/8
     4th Quarter.....................   7 7/8   9 1/4

     The Company has not paid dividends on its common stock since the third
quarter of 1993. The determination of the amount of future cash dividends, if
any, to be declared and paid is in the sole discretion of Santa Fe's Board of
Directors and will depend on dividend requirements with respect to the Company's
convertible preferred stock, the Company's financial condition, earnings and
funds from operations, the level of its capital and exploration expenditures,
dividend restrictions in its financing agreements, its future business prospects
and other matters as the Company's Board of Directors deems relevant. For a
discussion of certain restrictions on Santa Fe's ability to pay dividends, see
Item 7. "Management's Discussion and Analysis of Financial Condition and Results
of Operations -- Financing Activities."

     At December 31, 1995 the Company had approximately 42,300 shareholders of
record.
                                       19
ITEM 6.  SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
                                                      YEAR ENDED DECEMBER 31,
                                       ------------------------------------------------------
                                         1995       1994       1993       1992(B)     1991
                                       ---------  ---------  ---------    -------   ---------
                                             (IN MILLIONS OF DOLLARS, EXCEPT AS NOTED)
SELECTED FINANCIAL DATA
  INCOME STATEMENT DATA
<S>                                        <C>        <C>        <C>        <C>         <C>
     Revenues........................      442.0      391.4      436.9      427.5       379.8
                                       ---------  ---------  ---------    -------   ---------
     Costs and Expenses
          Production and operating...      154.9      150.0      163.8      153.4       134.6
          Oil and gas systems and
            pipelines................       --         --          4.2        3.2        --
          Exploration, including dry
            hole costs...............       23.4       20.4       31.0       25.5        18.7
          Depletion, depreciation and
            amortization.............      133.2      121.3      152.7      146.3       106.6
          Impairment of oil and gas
            properties...............       30.2       --         99.3        --         --
          General and
            administrative...........       26.9       27.3       32.3       30.9        27.8
          Taxes (other than
            income)..................       19.2       25.8       27.3       24.3        27.2
          Restructuring charges
            (a)......................       --          7.0       38.6        --         --
          Loss (gain) on disposition
            of oil and gas
            properties...............        0.3       (8.6)       0.7      (13.6)        0.5
                                       ---------  ---------  ---------    -------   ---------
                                           388.1      343.2      549.9      370.0       315.4
                                       ---------  ---------  ---------    -------   ---------
     Income (Loss) from Operations...       53.9       48.2     (113.0)      57.5        64.4
          Other income (expense).....       (1.6)      (4.0)      (4.8)     (10.0)        5.6
          Interest income............       10.7        2.8        9.1        2.3         2.3
          Interest expense...........      (32.5)     (27.5)     (45.8)     (55.6)      (47.3)
          Interest capitalized.......        5.8        3.6        4.3        4.9         7.7
                                       ---------  ---------  ---------    -------   ---------
     Income (Loss) Before Income
       Taxes.........................       36.3       23.1     (150.2)      (0.9)       32.7
          Income taxes benefit
            (expense)................       (9.7)      (6.0)      73.1       (0.5)      (14.2)
                                       ---------  ---------  ---------    -------   ---------
     Net Income (Loss)...............       26.6       17.1      (77.1)      (1.4)       18.5
     Preferred Dividend
       Requirement...................      (14.8)     (11.7)      (7.0)      (4.3)       --
                                       ---------  ---------  ---------    -------   ---------
     Earnings (Loss) Attributable to
       Common Stock..................       11.8        5.4      (84.1)      (5.7)       18.5
                                       =========  =========  =========    =======   =========
     Per share data
          Earnings (loss) to common
            stock
            (in dollars).............       0.13       0.06      (0.94)     (0.07)       0.29
          Weighted average number of
            common shares outstanding
            (in millions)............       90.2       89.9       89.7       79.0        63.8
  STATEMENT OF CASH FLOWS DATA
     Net cash provided by operating
       activities....................      174.5      124.5      160.2      141.5       128.4
     Net cash used in investing
       activities....................      160.8       57.7      121.4       15.9       117.2
  BALANCE SHEET DATA (AT PERIOD END)
     Properties and equipment, net...      889.5      843.0      832.7    1,101.8       797.4
     Total assets....................    1,064.8    1,071.4    1,076.9    1,337.2       911.9
     Long-term debt..................      344.4      350.4      405.4      492.8       440.8
     Convertible preferred stock.....       80.0       80.0       80.0       80.0        --
     Shareholders' equity............      437.7      423.3      323.6      416.6       225.1

                                       20

SELECTED OPERATING DATA
  DAILY AVERAGE PRODUCTION(C)
     Crude oil and liquids
        (MBbls/day)
           Domestic..................       58.5       57.6       60.2       58.3       54.9
           Argentina.................        2.6        2.4        2.4        2.4        0.6
           Indonesia.................        5.2        5.7        4.1        1.8       --
                                       ---------  ---------  ---------  ---------  ---------
                                            66.3       65.7       66.7       62.5       55.5
                                       =========  =========  =========    =======   =========
     Natural gas (MMcf/day)..........      150.0      136.6      165.4      126.3       95.2
     Total production (MBOE/day).....       91.3       88.5       94.3       83.6       71.4
  AVERAGE SALES PRICES
     Crude oil and liquids ($/Bbl)
           Unhedged
                Domestic.............      13.84      12.11      12.70      14.38      14.07
                Argentina............      14.72      13.23      14.07      15.99      16.24
                Indonesia............      16.10      15.09      15.50      17.51       --
                Total................      14.05      12.41      12.93      14.54      14.09
           Hedged....................      14.15      12.41      12.93      14.96      16.16
     Natural Gas ($/Mcf)
           Unhedged..................       1.44       1.75       2.03       1.71       1.49
           Hedged....................       1.43       1.73       1.89       1.70       1.49
  PROVED RESERVES AT YEAR END(D)
     Crude oil, condensate and
        natural gas
        liquids (MMBbls).............      279.2      258.3      248.2      255.1      229.2
     Natural gas (Bcf)...............      245.1      242.4      263.0      277.5      170.8
     Proved reserves (MMBOE).........      320.1      298.7      292.0      301.5      257.7
     Proved developed reserves
        (MMBOE)......................      253.6      224.5      225.5      248.4      210.3
  PRESENT VALUE OF PROVED RESERVES AT
     YEAR-END
     Before income taxes.............    1,257.2      970.8      567.8      915.2      602.6
     After income taxes..............      930.2      739.9      502.4      733.5      463.6
  PRODUCTION COSTS PER BOE (including
     related production, severance
     and ad valorem taxes)
     (in dollars)....................       5.15       5.30       5.39       5.66       6.06
</TABLE>
------------
(a) 1993 amount includes losses on property dispositions of $27.8 million,
    long-term debt repayment penalties of $8.6 million and accruals of certain
    personnel benefits and related costs of $2.2 million.

(b) On May 19, 1992 Adobe was merged with and into the Company.

(c) Includes production attributable to properties sold during 1993 of 4.1 MBbls
    of oil and 21.7 MMcf of natural gas per day (7.7 MBOE per day).

(d) The amounts set forth in this table for 1993 give effect to the sale by the
    Company of approximately 8.0 MMBOE of proved reserves.

                                       21

ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
         RESULTS OF OPERATIONS

GENERAL
     As an independent oil and gas producer, the Company's results of operations
are dependent upon the difference between the prices received for oil and gas
and the costs of finding and producing such resources. A material portion of the
Company's crude oil production is from long-lived fields in the San Joaquin
Valley of California where EOR methods are being utilized. The market price of
the heavy (i.e., low gravity, high viscosity) and sour (i.e., high sulfur
content) crude oils produced in these fields is lower than sweeter, light (i.e.,
low sulfur and low viscosity) crude oils, reflecting higher transportation and
refining costs. In addition, the lifting costs of heavy crude oils are generally
higher than the lifting costs of light crude oils. As a result of these narrower
margins, even relatively modest changes in crude oil prices may significantly
affect the Company's revenues, results of operations, cash flows and proved
reserves. In addition, prolonged periods of high or low oil prices may have a
material effect on the Company's financial position.

     The lower price received for the Company's domestic heavy and sour crude
oil is reflected in the average sales price of the Company's domestic crude oil
and liquids (excluding the effect of hedging transactions) for 1995 of $13.84
per barrel, compared to $16.76 per barrel for West Texas Intermediate ("WTI")
crude oil (an industry posted price generally indicative of prices for sweeter
light crude oil). In 1995 the Company's average sales price for California heavy
crude oil was $13.35 per barrel, approximately 80% of the annual average posted
price for WTI.

     Crude oil prices are subject to significant changes in response to
fluctuations in the domestic and world supply and demand and other market
conditions as well as the world political situation as it affects OPEC, the
Middle East and other producing countries. During 1994 and 1995 the actual
average sales price (unhedged) received by the Company ranged from a high of
$14.97 per barrel in the second quarter of 1995 to a low of $10.00 per barrel
for the first quarter of 1994. Based on operating results for the year 1995, the
Company estimates that a $1.00 per barrel increase or decrease in its average
domestic crude oil sales prices would result in a corresponding $21.0 million
change in income from operations and a $15.8 million change in cash flow from
operating activities. The foregoing estimates do not give effect to changes in
any other factors, such as the effect of the Company's hedging program or
depreciation and depletion, that would result from a change in oil prices.

     The price of natural gas fluctuates due to weather conditions, the level of
natural gas in storage, the relative balance between supply and demand and other
economic factors. The actual average sales price (unhedged) received by the
Company in 1995 for its natural gas ranged from a high of $1.66 per Mcf in the
fourth quarter to a low of $1.31 per Mcf in the first quarter. Based on
operating results for the year 1995, the Company estimates that a $0.10 per Mcf
increase or decrease in its average domestic natural gas sales price would
result in a corresponding $3.2 million change in income from operations and a
$2.4 million change in cash flow from operating activities. The foregoing
estimates do not give effect to changes in any other factors, such as the effect
of the Company's hedging program or depletion and depreciation, that would
result from a change in natural gas prices.

     From time to time the Company hedges a portion of its oil and gas sales to
provide a certain minimum level of cash flow from its sales of oil and gas.
While the hedges are generally intended to reduce the Company's exposure to
declines in market price, the Company's gain from increases in market price may
be limited. The Company uses various financial instruments whereby monthly
settlements are based on differences between the prices specified in the
instruments and the settlement prices of certain futures contracts quoted on the
New York Mercantile Exchange ("NYMEX") or certain other indices. Generally, in
instances where the applicable settlement price is less than the price specified
in the contract, the Company receives a settlement based on the difference; in
instances where the applicable settlement price is higher than the specified
price, the Company pays an amount based on the difference. The instruments
utilized by the Company differ from futures contracts in that

                                       22

there is no contractual obligation which requires or allows for the future
delivery of the product. Gains or losses on hedging activities are recognized in
oil and gas revenues in the period in which the hedged production is sold.

     At December 31, 1995 the Company had open crude hedges on (i) an average of
15,000 barrels per day for the period January to April 1996 at an average NYMEX
WTI price of $18.52 per barrel and (ii) provided that the NYMEX WTI price is
greater than $16.80 per barrel, up to an additional 15,000 barrels per day for
the period January through March 1996 at an average NYMEX WTI price of $18.65
per barrel. The "approximate break-even price" (the average of the settlement
prices which result in no settlement being due to or from the Company) with
respect to all such contracts is approximately $18.56 per barrel. The following
table reflects estimated amounts due to or from the Company assuming the stated
settlement prices are in effect for the entire period the aforementioned hedges
are in effect.

                                  SETTLEMENT PRICE       DUE TO (FROM) COMPANY
                                (DOLLARS PER BARREL)     (MILLIONS OF DOLLARS)
                                --------------------     ---------------------
                                        20.00                     (5.4)
                                        19.00                     (1.6)
                                        18.00                      1.8
                                        17.00                      3.6
                                        16.00                      4.6

During 1995 crude oil hedges resulted in a $2.4 million increase in revenues.

     Subsequent to year-end the Company hedged an additional 2,000 barrels per
day for the second quarter of 1996 and, provided that the settlement price is
above $17.00, up to an additional 8,000 barrels per day for the second quarter
of 1996 and 2,000 barrels per day for the third quarter of 1996. The approximate
break-even price is $18.54 per barrel for the second quarter hedges and $18.60
per barrel for the third quarter hedges.

     At December 31, 1995 the Company had open natural gas hedges on (i) an
average of approximately 55.0 MMcf per day of its Gulf Coast production for the
entire year of 1996 at an approximate break-even price of $1.82 per Mcf and (ii)
an average of approximately 30.0 MMcf per day of its Permian Basin production
for the entire year of 1996 at an approximate break-even price of $1.53 per Mcf.
Due to its location, Permian Basin gas sells at a discount to Gulf Coast gas.
Natural gas hedges resulted in decreases in revenues of $0.3 million in 1995 and
$1.0 million in 1994.

     With respect to the Gulf Coast production hedges, a $0.10 per Mcf decrease
or increase in the average settlement price for a month results in a $168,000
increase or decrease in revenues, respectively. With respect to the Permian
Basin production hedges, a $0.10 per Mcf decrease or increase in the average
settlement price for a month results in a $92,000 increase or decrease in
revenues, respectively.

     In addition to its oil and gas sales hedges for the first six months of
1996 the Company has hedged 20.0 MMcf per day of the natural gas it purchases
for use in its steam generation operations in the San Joaquin Valley of
California. Monthly settlements are based on the difference between the
settlement price quoted on the NYMEX and the index price for San Juan Basin
natural gas. Gains or losses are recognized in production and operating costs in
the period in which the hedged gas is consumed in operations.

     In instances where the difference between the NYMEX price and the San Juan
Basin index price is greater than $0.53, the Company pays an amount based on the
difference and in instances where the difference is less than $0.53, the Company
receives a payment based on the difference. Each $0.10 per Mcf change in the
spread between the NYMEX price and the San Juan Basin index price results in a
monthly increase or decrease in revenues of $60,000.

                                      23
RESULTS OF OPERATIONS

  REVENUES

     The following table reflects the components of the Company's crude oil and
liquids and natural gas revenues:

                                           YEAR ENDED DECEMBER 31,
                                       -------------------------------
                                         1995       1994       1993
                                       ---------  ---------  ---------
CRUDE OIL AND LIQUIDS
  REVENUES ($ MILLIONS)
     Sales
       Domestic
          California Heavy...........      189.5      158.2      151.7
          Other......................      105.8       96.4      127.4
                                       ---------  ---------  ---------
                                           295.3      254.6      279.1
       Argentina.....................       13.8       11.6       12.5
       Indonesia.....................       30.8       31.3       23.1
     Hedging.........................        2.4       --         --
     Net Profits Payments............       (4.4)      (3.8)      (7.4)
                                       ---------  ---------  ---------
                                           337.9      293.7      307.3
                                       =========  =========  =========
   VOLUMES (MBBLS/DAY)
     Domestic
       California Heavy..............       38.9       38.3       37.0
       Other.........................       19.6       19.3       23.2
                                       ---------  ---------  ---------
                                            58.5       57.6       60.2
     Argentina.......................        2.6        2.4        2.4
     Indonesia.......................        5.2        5.7        4.1
                                       ---------  ---------  ---------
                                            66.3       65.7       66.7
                                       =========  =========  =========
  SALES PRICES ($/BBL)
     Domestic
       California Heavy..............      13.35      11.31      11.24
       Other.........................      14.82      13.72      15.03
       Total.........................      13.84      12.11      12.70
     Argentina.......................      14.72      13.23      14.07
     Indonesia.......................      16.10      15.09      15.50
     Total...........................      14.05      12.41      12.93
     Total Hedged....................      14.15      12.41      12.93
NATURAL GAS
  REVENUES ($ MILLIONS)
     Sales
       Domestic......................       73.3       87.2      122.3
       Foreign.......................        5.5        0.1       --
                                       ---------  ---------  ---------
                                            78.8       87.3      122.3
     Hedging.........................       (0.3)      (1.0)      (8.2)
     Net Profits Payments............       (1.4)      (2.9)      (6.3)
                                       ---------  ---------  ---------
                                            77.1       83.4      107.8
                                       =========  =========  =========
  VOLUMES (MMCF/DAY)
     Domestic........................      137.7      136.3      165.1
     Foreign.........................       12.3        0.3        0.3
                                       ---------  ---------  ---------
                                           150.0      136.6      165.4
                                       =========  =========  =========
  SALES PRICES ($/MCF)
     Unhedged
       Domestic......................       1.46       1.75       2.03
       Foreign.......................       1.22       0.99       0.96
       Total.........................       1.44       1.75       2.03
     Hedged..........................       1.43       1.73       1.89

                                      24

     Total revenues increased 13% from $391.4 million in 1994 to $442.0 million
in 1995. Crude oil and liquids revenues increased $44.2 million, primarily
reflecting the effect of increased sales prices ($39.3 million) and increased
volumes ($4.3 million). Natural gas revenues declined $6.3 million primarily due
to the effect of lower sales prices ($14.6 million) which was partially offset
by the effect of higher sales volumes ($8.6 million). The increase in natural
gas sales volumes is principally due to sales from the Company's Sierra Chata
field in Argentina, which commenced production in April 1995. Other revenues for
1995 includes $10.2 million related to the favorable settlement of a disputed
natural gas sales contract.

     Total revenues declined 10% from $436.9 million in 1993 to $391.4 million
in 1994. Crude oil and liquids revenues declined $13.6 million. The sale of
certain domestic properties in the fourth quarter of 1993 and the second quarter
of 1994 resulted in a decrease in oil revenues of approximately $20.4 million.
The effect of increased volumes of California heavy and Indonesian crude,
approximately $14.5 million, and lower net profits payments were partially
offset by the effect of lower sales prices. Daily average oil production in 1994
decreased 1,000 barrels per day from 1993. The 3,800 barrel per day decrease in
oil production resulting from the sale of properties was partially offset by a
1,300 barrel per day increase in California heavy crude and a 1,600 barrel per
day increase in Indonesian production.

     Natural gas revenues declined from $107.8 million in 1993 to $83.4 million
in 1994. The sales of properties to Vintage and Bridge resulted in a decrease in
natural gas revenues of approximately $13.1 million and lower sales prices
resulted in a reduction in revenues of approximately $7.6 million. In addition,
revenues for 1993 included a positive adjustment of $3.2 million related to
production in prior periods from certain nonoperated properties. Net profits
payments in 1994 were $3.3 million lower than in 1993. Natural gas sales volumes
decreased from 165.4 MMcf per day in 1993 to 136.6 MMcf per day in 1994 with the
property sales accounting for approximately 18.6 MMcf per day of the decrease.
The Company's curtailment program (see -- General) resulted in a reduction of
approximately 5.1 MMcf per day and the prior period adjustment included in 1993
represented volumes of approximately 4.0 MMcf per day.

     Total revenues increased approximately 2% from $427.5 million in 1992 to
$436.9 million in 1993. Crude oil and liquids revenues decreased from $333.6
million in 1992 to $307.3 million in 1993 as the effect of lower sales prices
more than offset the effect of increased sales volumes. In addition, revenues
for 1992 included gains on hedging transactions of $9.7 million. Crude oil and
liquids sales volumes increased from 62.5 MBbls per day in 1992 to 66.7 MBbls
per day in 1993, reflecting increased sales of California heavy crude as well as
a full year of volumes from the properties acquired in the Adobe Merger (the
"Adobe Properties"). Natural gas revenues increased from $74.8 million in 1992
to $107.8 million in 1993. Sales volumes increased from 126.3 MMcf per day in
1992 to 165.4 MMcf per day in 1993, primarily reflecting a full year of volumes
from the Adobe Properties. In addition, natural gas revenues for 1993 were
reduced by losses on hedging transactions of $8.2 million compared to losses of
$0.5 million in 1992.

  COSTS AND EXPENSES

     The following table sets forth, on a per barrel of oil equivalent ("BOE")
produced basis, certain of the Company's costs and expenses (in dollars):

                                            1995       1994       1993
                                         ---------  ---------  ---------
Production and operating (a).........       4.65       4.65       4.76
Exploration, including dry hole
  costs..............................       0.70       0.63       0.90
Depletion, depreciation and
  amortization (b)...................       3.96       3.76       4.44
General and administrative...........       0.81       0.85       0.94
Taxes other than income (c)..........       0.58       0.80       0.79
Interest, net (d)(e).................       0.93       1.08       1.30

                                       25
___________
  (a) Excluding related production, severance and ad valorem taxes.

  (b) Excludes effect of unproved property writedown of $0.03 per BOE in 1995.

  (c) Includes production, severance and ad valorem taxes.

  (d) Reflects interest expense less amounts capitalized and interest income.

  (e) Excludes effects of (i) benefit of federal income tax audit refund of
      $0.25 per BOE in 1995; (ii) benefit of an adjustment to certain financing
      costs recorded in a prior period of $0.05 per BOE in 1995; (iii) benefit
      of adjustments to provisions for potential state income tax obligations of
      $0.15 per BOE in 1995 and $0.36 per BOE in 1994; (iv) benefit of
      adjustment to provisions made in prior periods with respect to interest on
      certain federal income tax audit adjustments of $0.07 per BOE in 1994; and
      (v) benefit of Federal income tax audit refund and revised tax sharing
      agreement with the Company's former parent of $0.36 per BOE in 1993.

     Costs and expenses totalled $388.1 million in 1995 compared to $343.2
million in 1994. Depletion, depreciation and amortization expense ("DD&A")
increased $11.9 million primarily reflecting such expense associated with new
production from the Company's Sierra Chata field in Argentina and increased
expense associated with certain of the Company's Gulf Coast and Permian Basin
properties principally due to the recent high level of capital expenditures. In
1995 the Company recognized $30.2 million in impairment of oil and gas
properties associated with the adoption of a new accounting standard with
respect to the impairment of certain assets. Taxes other than income are $6.6
million lower in 1995, primarily reflecting lower ad valorem taxes and a $0.7
million benefit reflecting adjustments to amounts accrued in prior periods due
to the favorable settlement of a dispute with respect to certain sales and use
taxes.

     Costs and expenses for 1994 totalled $343.2 million compared to $549.9
million for 1993. Costs and expenses for 1993 included impairments of oil and
gas properties of $99.3 million and restructuring charges of $38.6 million.
Costs and expenses for 1994 included restructuring charges of $7.0 million (see
-- Liquidity and Capital Resources). Property sales in the fourth quarter of
1993 and the second quarter of 1994 resulted in reductions in production and
operating costs and DD&A of $12.4 million and $11.5 million, respectively. The
remainder of the decrease in DD&A is primarily attributable to the effect of the
property impairments taken in the fourth quarter of 1993. Exploration expenses
were down $10.6 million primarily reflecting lower geological and geophysical
costs with respect to foreign operations and lower overhead. General and
administrative expenses were $5.0 million lower, primarily reflecting the effect
of the corporate restructuring program.

     Costs and expenses increased from $370.0 million in 1992 to $549.9 million
in 1993. Costs and expenses for 1993 included impairments of oil and gas
properties of $99.3 million and restructuring charges of $38.6 million (see --
Liquidity and Capital Resources). The increase in 1993 in production and
operating costs and taxes (other than income) primarily reflects a full year's
costs for the Adobe Properties. Exploration costs were $5.5 million higher,
primarily reflecting higher geological and geophysical and dry hole costs. DD&A
increased $6.4 million reflecting a full year's costs for the Adobe Properties,
partially offset by reduced amortization rates with respect to certain unproved
properties. General and administrative costs for 1993 include a $1.8 million
charge related to the adoption of Statement of Financial Accounting Standards
No. 112 -- "Employer's Accounting for Postemployment Benefits".

     Interest income for 1995 includes $7.4 million related to a $12.0 million
refund with respect to the audit of the Company's federal income tax returns for
1981 through 1985 and $0.8 million related to a $1.3 million refund with respect
to the audit of Adobe's federal income tax returns for 1984 and 1985. Interest
income for 1993 includes $6.8 million related to a $10.0 million refund received
as a result of the completion of the audit of the Company's federal income tax
returns for 1971 through 1980.

     Interest expense for 1995 includes a $5.0 million benefit reflecting
adjustments to provisions made in prior periods for potential state income tax
obligations. Interest expense for 1994 includes a benefit of $2.4 million
reflecting adjustments to provisions made in prior periods with respect to
interest on certain potential federal income tax audit adjustments and a benefit
of $11.5 million reflecting adjustments to provisions made in prior periods for
potential state income tax obligations.

                                       26

Interest expense for 1993 includes a benefit of $5.7 million related to a
revision to a tax sharing agreement with the Company's former parent.

     Other income (expense) for 1995 includes a $2.5 million gain on the sale of
Cherokee Resources Incorporated, a privately-held oil and gas company, and a
$1.8 million loss on the sale of the Company's investment in Hadson. Other
income (expense) for 1994 includes (i) a $2.4 million gain on the sale of the
Company's interest in a company which was acquired in the Adobe merger in 1992;
(ii) a net $1.6 million charge with respect to the Company's investment in
Hadson; and (iii) a $5.0 million charge with respect to certain litigation.
Other income (expense) for 1993 includes a $4.0 million charge related to the
accrual of a contingent loss with respect to a former affiliate of Adobe.

     Income taxes for 1995 include a $5.0 million benefit related to the
previously discussed federal tax audit refunds and a $1.3 million benefit
related to adjustments to provisions in prior periods for potential state income
tax obligations. Income taxes for 1994 include a $3.0 million credit reflecting
the benefit of adjustments to provisions made in prior periods with respect to
certain potential federal income tax audit adjustments and a $2.6 million credit
reflecting the benefit of adjustments to provisions made in prior periods for
potential state income tax obligations. Income taxes for 1993 includes (i) a
$2.6 million charge to reflect the increase in the Company's deferred income tax
liability as a result of the increase in the federal income tax rate; (ii) a
$3.2 million benefit related to the previously discussed federal tax audit
refund; (iii) a $1.8 million benefit related to the previously discussed
revision to a tax sharing agreement with the Company's former parent; and (iv) a
$1.0 million benefit relating to prior periods resulting from the restructuring
of certain of the Company's foreign operations which were conducted through
foreign incorporated subsidiaries.

     The increase in the Company's preferred dividend requirement reflects the
issuance of 10.7 million shares of $0.732 Series A Convertible Preferred Stock
in the second quarter of 1994.

     In October 1995 the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 123 "Accounting for Stock-Based
Compensation" ("FAS 123"), which established financial accounting and reporting
standards for stock-based employee compensation plans. FAS 123 encourages
companies to adopt a fair value based method of accounting for such plans but
continues to allow the use of the intrinsic value based method prescribed by
Accounting Principles Board Opinion No. 25 "Accounting for Stock Issued to
Employees" ("Opinion 25"). Companies electing to continue accounting in
accordance with Opinion 25 must make pro forma disclosures of net income and
earnings per share as if the fair value based method defined in FAS 123 had been
applied. The Company will continue to account for stock-based compensation in
accordance with Opinion 25 and will make pro forma disclosures in accordance
with the provisions of FAS 123 beginning in its 1996 financial statements.

LIQUIDITY AND CAPITAL RESOURCES

     The Company's cash flow from operating activities is a function of the
volumes of oil and gas produced from the Company's properties and the sales
prices received therefor. Since crude oil and natural gas are depleting assets,
unless the Company replaces the oil and gas produced from its properties, the
Company's assets will be depleted over time and its ability to incur debt at
constant or declining prices will be reduced. The Company increased its proved
reserves (net of production and sales) by approximately 26% over the five years
ended December 31, 1995; however, no assurances can be given that such increase
will occur in the future. Historically, the Company has generally funded
development and exploration expenditures and working capital requirements from
cash provided by operating activities. Depending upon the future levels of
operating cash flows, which are significantly affected by oil and gas prices,
the restrictions on additional borrowings included in certain of the Company's
debt agreements, together with debt service requirements and dividends, may
limit the cash available for future exploration, development and acquisition
activities. Net cash provided by operating activities and net proceeds from
sales of properties (including $55.2 million from the sale of Hadson) totalled
$236.9 million in 1995; net cash used for capital expenditures and producing
property acquisitions in such period totalled $223.2 million.

                                       27

     The increase in accounts receivable from $76.2 million at December 31, 1994
to $89.0 million at December 31, 1995 primarily reflects a $12.0 million
receivable at December 31, 1995 related to a refund with respect to the audit of
the Company's federal income tax returns for 1981 through 1985. The decrease in
amounts payable from $84.1 million at December 31, 1994 to $73.1 million at
December 31, 1995 primarily reflects lower amounts payable with respect to
capital projects in progress.

     The decrease in accounts receivable from $87.4 million at December 31, 1993
to $76.2 million at December 31, 1994 primarily reflects lower receivables with
respect to natural gas sales due to lower prices and an acceleration of the
collection of such receivables resulting from the marketing arrangement with
Hadson and the collection of certain amounts with respect to the property sale
to Vintage which had been held in escrow, partially offset by an increase in
receivables for oil sales, primarily due to higher sales prices.

     The Company's 1995 capital program totalled approximately $204.6 million, a
level which allowed the Company to more than replace its 1995 production. The
Company expects to expend approximately $200.5 million on its 1996 program.
However, the actual amount expended by the Company in 1996 will be based upon
numerous factors, the majority of which are outside its control, including,
without limitation, prevailing oil and natural gas prices and the outlook
therefor and the availability of funds.

     Effective April 1, 1995 the Company entered into the Second Amended and
Restated Revolving Credit Agreement (the "Credit Agreement"), an unsecured
revolving credit agreement which matures December 31, 1998. The maximum
borrowing limits under the Credit Agreement are initially $125.0 million, $105.0
million beginning February 28, 1996, $65.0 million beginning February 28, 1997
and $30.0 million beginning February 28, 1998. Interest rates under the Credit
Agreement are tied to LIBOR or the bank's prime rate with the actual interest
rate based upon certain ratios and the value and projected timing of production
of the Company's oil and gas reserves. At December 31, 1995, $6.4 million in
letters of credit were outstanding under the terms of the Credit Agreement.

     The Company has three short-term uncommitted lines of credit totalling
$50.0 million which are used to meet short-term cash needs. Interest rates on
borrowings under these lines of credit are typically lower than rates paid under
the Bank Facility. At December 31, 1995 no amounts were outstanding under these
lines of credit.

     Certain of the Company's credit agreements and the indenture for the
Debentures include covenants that restrict the Company's ability to take certain
actions, including the ability to incur additional indebtedness and to pay
dividends on capital stock. Under the most restrictive of these covenants, at
December 31, 1995 the Company could incur up to $191.0 million of additional
indebtedness and pay dividends of up to $114.2 million on its aggregate capital
stock (including its common stock, 7% Convertible Preferred Stock and Series A
Preferred) with the amount payable on its common stock limited to $52.0 million.

ENVIRONMENTAL MATTERS

     Almost all phases of the Company's oil and gas operations are subject to
stringent environmental regulation by governmental authorities. Such regulation
has increased the costs of planning, designing, drilling, installing, operating
and abandoning oil and gas wells and other facilities. The Company has expended
significant financial and managerial resources to comply with such regulations.
Although the Company believes its operations and facilities are in general
compliance with applicable environmental regulations, risks of substantial costs
and liabilities are inherent in oil and gas operations. It is possible that
other developments, such as increasingly strict environmental laws, regulations
and enforcement policies or claims for damages to property, employees, other
persons and the environment resulting from the Company's operations, could
result in significant costs and liabilities in the future. As it has done in the
past, the Company intends to fund its cost of environmental compliance from
operating cash flows. See Items 1 and 2. "Business and Properties -- Other
Business Matters -- Environmental Regulation" and Note 11 to the Consolidated
Financial Statements.

                                       28
DIVIDENDS

     Dividends on the Company's 7% Convertible Preferred Stock and Series A
Preferred Stock are cumulative at an annual rate of $1.40 per share and $0.732
per share, respectively. No dividends may be declared or paid with respect to
the Company's common stock if any dividends with respect to the 7% Convertible
Preferred Stock or Series A Preferred Stock are in arrears. None of the
dividends with respect to the Company's 7% Convertible Preferred Stock and
Series A Preferred Stock are in arrears. The determination of the amount of
future cash dividends, if any, to be declared and paid on the Company's common
stock is in the sole discretion of the Company's Board of Directors and will
depend on dividend requirements with respect to the preferred stock, the
Company's financial condition, earnings and funds from operations, the level of
capital and exploration expenditures, dividend restrictions in financing
agreements, future business prospects and other matters the Board of Directors
deems relevant.

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                                           PAGE
                                           ----
Audited Financial Statements
           Report of Independent
            Accountants.................    31
           Consolidated Statement of
            Operations for the years
            ended December 31, 1995,
            1994 and 1993...............    32
           Consolidated Balance Sheet
            -- December 31, 1995 and
            1994........................    33
           Consolidated Statement of
            Cash Flows for the years
            ended December 31, 1995,
            1994 and 1993...............    34
           Consolidated Statement of
            Shareholders' Equity for
            the years ended December
            31, 1995, 1994 and 1993.....    35
           Notes to Consolidated
            Financial Statements........    36

Unaudited Financial Information
           Supplemental Information
            to Consolidated Financial
            Statements..................    58

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
         FINANCIAL DISCLOSURE

           None.
                                       29

                                    PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

ITEM 11.  EXECUTIVE COMPENSATION

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     Except for the portion of Item 10 relating to Executive Officers of the
Registrant which is included in Part I of this Report, the information called
for by Items 10 through 13 is incorporated by reference from the Company's
Notice of Annual Meeting and Proxy Statement dated March 21, 1996, which meeting
involves the election of directors, in accordance with General Instruction G to
the Annual Report on Form 10-K.

                                     PART IV

ITEM 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.

     (a)  The following documents are filed as a part of this report:

                                                               PAGE
                                                               ----
           1.  Financial Statements:
                Report of Independent Accountants.............. 31
                Consolidated Statement of Operations
                  for the years ended December 31,
                  1995, 1994 and 1993.......................... 32
                Consolidated Balance Sheet-- December 31,
                  1995 and 1994................................ 33
                Consolidated Statement of Cash Flows
                  for the years ended December 31,
                  1995, 1994 and 1993.......................... 34
                Consolidated Statement of Shareholders'
                  Equity for the years ended December 31,
                  1995, 1994 and 1993.......................... 35
                Notes to Consolidated Financial Statements..... 36

           2.  Financial Statement Schedules:
                Schedule VIII -- Valuation and Qualifying
                  Accounts..................................... 68
                All other schedules have been omitted because they
                are not applicable or the required information is
                presented in the financial statements or the notes
                to financial statements.

           3.  Exhibits:

                See Index to Exhibits on page 69 for a description
                of the exhibits filed as a part of this report.

     (b)  Reports on Form 8-K
                February 6, 1996
                                       30

                        REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Shareholders of
Santa Fe Energy Resources, Inc.

In our opinion, the consolidated financial statements listed in the index
appearing under Item 14(a)(1) and (2) on page 30 present fairly, in all material
respects, the financial position of Santa Fe Energy Resources, Inc. and its
subsidiaries at December 31, 1995 and 1994, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 1995, in conformity with generally accepted accounting principles. 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 of these statements in accordance with
generally accepted auditing standards which 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,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for the opinion expressed
above.

As discussed in Note 1 to the consolidated financial statements, the Company
changed its method of accounting for the impairment of long-lived assets in 1995
to comply with the provisions of Statement of Financial Accounting Standards No.
121.

PRICE WATERHOUSE LLP

Houston, Texas
February 23, 1996
                                       31

                       SANTA FE ENERGY RESOURCES, INC.
                     CONSOLIDATED STATEMENT OF OPERATIONS
               (IN MILLIONS OF DOLLARS, EXCEPT PER SHARE DATA)

                                           YEAR ENDED DECEMBER 31,
                                       -------------------------------
                                          1995       1994       1993
                                       ---------  ---------  ---------
Revenues
     Crude oil and liquids...........  $   337.9  $   293.7  $   307.3
     Natural gas.....................       77.1       83.4      107.8
     Natural gas systems.............        --         --         8.2
     Crude oil marketing and
       trading.......................       14.4       11.3        9.9
     Other...........................       12.6        3.0        3.7
                                       ---------  ---------  ---------
                                           442.0      391.4      436.9
                                       ---------  ---------  ---------
Costs and Expenses
     Production and operating........      154.9      150.0      163.8
     Oil and gas systems and
       pipelines.....................        --         --         4.2
     Exploration, including dry hole
       costs.........................       23.4       20.4       31.0
     Depletion, depreciation and
       amortization..................      133.2      121.3      152.7
     Impairment of oil and gas
       properties....................       30.2        --        99.3
     General and administrative......       26.9       27.3       32.3
     Taxes (other than income).......       19.2       25.8       27.3
     Restructuring charges...........        --         7.0       38.6
     Loss (gain) on disposition of
       assets........................        0.3       (8.6)       0.7
                                       ---------  ---------  ---------
                                           388.1      343.2      549.9
                                       ---------  ---------  ---------
Income (Loss) from Operations........       53.9       48.2     (113.0)
     Interest income.................       10.7        2.8        9.1
     Interest expense................      (32.5)     (27.5)     (45.8)
     Interest capitalized............        5.8        3.6        4.3
     Other income (expense)..........       (1.6)      (4.0)      (4.8)
                                       ---------  ---------  ---------
Income (Loss) Before Income Taxes....       36.3       23.1     (150.2)
     Income taxes....................       (9.7)      (6.0)      73.1
                                       ---------  ---------  ---------
Net Income (Loss)....................       26.6       17.1      (77.1)
Preferred dividend requirement.......      (14.8)     (11.7)      (7.0)
                                       ---------  ---------  ---------
Earnings (Loss) Attributable to
  Common Shares......................  $    11.8  $     5.4  $   (84.1)
                                       =========  =========  =========
Earnings (Loss) Attributable to
  Common Shares Per Share............  $    0.13  $    0.06  $   (0.94)
                                       =========  =========  =========
Weighted Average Number of Common
  Shares Outstanding
  (in millions)......................       90.2       89.9       89.7
                                       =========  =========  =========
  The accompanying notes are an integral part of these financial statements.

                                      32

                       SANTA FE ENERGY RESOURCES, INC.
                          CONSOLIDATED BALANCE SHEET
                           (IN MILLIONS OF DOLLARS)

                                             DECEMBER 31,
                                       ------------------------
                                           1995         1994
                                       -----------  -----------
               ASSETS
Current Assets
     Cash and cash equivalents.......  $      42.6  $      53.7
     Accounts receivable.............         89.0         76.2
     Inventories.....................         10.5          9.2
     Other current assets............         17.2         18.1
                                       -----------  -----------
                                             159.3        157.2
                                       -----------  -----------
Investment in Hadson Corporation.....        --            57.0
                                       -----------  -----------
Properties and Equipment, at cost
     Oil and gas (on the basis of
       successful efforts
       accounting)...................      2,336.3      2,145.9
     Other...........................         35.6         32.7
                                       -----------  -----------
                                           2,371.9      2,178.6
     Accumulated depletion,
       depreciation, amortization and
       impairment....................     (1,482.4)    (1,335.6)
                                       -----------  -----------
                                             889.5        843.0
                                       -----------  -----------
Other Assets
     Receivable under gas balancing
       arrangements..................          5.8          4.6
     Other...........................         10.2          9.6
                                       -----------  -----------
                                              16.0         14.2
                                       -----------  -----------
                                       $   1,064.8  $   1,071.4
                                       ===========  ===========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
     Accounts payable................  $      73.1  $      84.1
     Interest payable................          7.9          8.5
     Current portion of long-term
       debt..........................         --            3.9
     Other current liabilities.......         28.6         29.5
                                       -----------  -----------
                                             109.6        126.0
                                       -----------  -----------
Long-Term Debt.......................        344.4        350.4
                                       -----------  -----------
Deferred Revenues....................          4.9          7.4
                                       -----------  -----------
Other Long-Term Obligations..........         24.2         28.0
                                       -----------  -----------
Deferred Income Taxes................         64.0         56.3
                                       -----------  -----------
Commitments and Contingencies (Note
  11)................................         --           --
                                       -----------  -----------
Convertible Preferred Stock, $0.01
  par value, 5.0 million shares
  authorized, issued and
  outstanding........................         80.0         80.0
                                       -----------  -----------
Shareholders' Equity
     Preferred stock, $0.01 par
       value, 34.3 million shares
       authorized, none issued.......         --           --
     $.732 Series A preferred stock,
       $0.01 par value, 10.7 million
       shares authorized, issued and
       outstanding...................         91.4         91.4
     Common stock, $0.01 par value,
       200.0 million shares
       authorized....................          0.9          0.9
     Paid-in capital.................        501.4        498.9
     Accumulated deficit.............       (155.7)      (167.5)
     Foreign currency translation
       adjustment....................         (0.3)        (0.4)
                                       -----------  -----------
                                             437.7        423.3
                                       -----------  -----------
                                       $   1,064.8  $   1,071.4
                                       ===========  ===========
   The accompanying notes are an integral part of these financial statements.

                                      33

                         SANTA FE ENERGY RESOURCES, INC.
                      CONSOLIDATED STATEMENT OF CASH FLOWS
                            (IN MILLIONS OF DOLLARS)

                                           YEAR ENDED DECEMBER 31,
                                       -------------------------------
                                          1995       1994       1993
                                       ---------  ---------  ---------
Operating Activities:
     Net income (loss)...............  $    26.6  $    17.1  $   (77.1)
     Adjustments to reconcile net
       income (loss) to net cash
       provided by operating
       activities:
          Depletion, depreciation and
            amortization.............      133.2      121.3      152.7
          Impairment of oil and gas
            properties...............       30.2         --       99.3
          Restructuring charges......         --        1.0       27.8
          Deferred income taxes......        7.7       11.3      (71.9)
          Loss (gain) on disposition
            of assets................        0.3       (8.6)       0.7
          Exploratory dry hole
            costs....................        5.5        6.5        8.9
          Equity in losses and
            adjustment to valuation
            of investment in Hadson
            Corporation..............         --        6.1         --
          Hadson Corporation
            preferred dividends
            received in-kind.........         --       (4.5)        --
          Other......................        2.4        3.0        4.2
     Changes in operating assets and liabilities:
          Decrease (increase) in
            accounts receivable......      (12.8)       1.3       12.4
          Decrease (increase) in
            inventories..............       (1.3)      (0.5)      (3.8)
          Increase (decrease) in
            accounts payable.........       (4.5)      (8.6)      (2.6)
          Increase (decrease) in
            interest payable.........       (0.6)      (1.7)      (0.8)
          Increase (decrease) in
            income taxes payable.....        1.5        0.2       (0.6)
          Net change in other assets
            and liabilities..........      (13.7)     (19.4)      11.0
                                       ---------  ---------  ---------
Net Cash Provided by Operating
  Activities.........................      174.5      124.5      160.2
                                       ---------  ---------  ---------
Investing Activities:
     Capital expenditures, including
       exploratory dry hole costs....     (189.4)    (136.6)    (127.0)
     Acquisitions of producing
       properties, net of related
       debt..........................      (33.8)      (2.2)      (4.4)
     Acquisition of Santa Fe Energy
       Partners, L.P.................         --         --      (28.3)
     Proceeds from sale of investment
       in Hadson Corporation.........       55.2         --         --
     Net proceeds from sales of
       properties....................        7.2       81.1       39.9
     Increase in partnership interest
       due to reinvestment...........         --         --       (1.6)
                                       ---------  ---------  ---------
Net Cash Used in Investing
  Activities.........................     (160.8)     (57.7)    (121.4)
                                       ---------  ---------  ---------
Financing Activities:
     Net proceeds from issuance of
       11% senior subordinated
       debentures due 2004...........         --       96.1         --
     Net proceeds from issuance of
       $.732 Series A convertible
       preferred stock...............         --       91.4         --
     Principal payments on long-term
       borrowings....................      (10.0)    (144.7)     (41.5)
     Net change in revolving credit
       agreement.....................         --      (50.0)     (55.0)
     Cash dividends paid.............      (14.8)     (10.7)     (21.3)
                                       ---------  ---------  ---------
Net Cash Used in Financing
  Activities.........................      (24.8)     (17.9)    (117.8)
                                       ---------  ---------  ---------
Net Increase (Decrease) in Cash and
  Cash Equivalents...................      (11.1)      48.9      (79.0)
Cash and Cash Equivalents at
  Beginning of Year..................       53.7        4.8       83.8
                                       ---------  ---------  ---------
Cash and Cash Equivalents at End of
  Year...............................  $    42.6  $    53.7  $     4.8
                                       =========  =========  =========
   The accompanying notes are an integral part of these financial statements.

                                      34

                         SANTA FE ENERGY RESOURCES, INC.
                 CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
                        (SHARES AND DOLLARS IN MILLIONS)
<TABLE>
<CAPTION>
                                            $.732
                                          SERIES A
                                         CONVERTIBLE                                 UNAMORTIZED                  FOREIGN
                                       PREFERRED STOCK    COMMON STOCK               RESTRICTED                   CURRENCY
                                       ---------------   ---------------   PAID-IN      STOCK      ACCUMULATED   TRANSLATION
                                       SHARES   AMOUNT   SHARES   AMOUNT   CAPITAL     AWARDS        DEFICIT     ADJUSTMENT
                                       ------   ------   ------   ------   -------   -----------   -----------   ----------
<S>                                     <C>     <C>       <C>      <C>     <C>          <C>          <C>           <C>
Balance at December 31, 1992.........   --      $--       89.5     $0.9    $ 494.3      $(0.4)       $ (78.0)      $ (0.2)
  Issuance of common stock
     Employee stock compensation and
      savings plans..................   --       --        0.3     --          2.6       (0.1)        --            --
  Amortization of restricted
    stock awards.....................   --       --       --       --        --           0.4         --            --
  Pension liability adjustment.......   --       --       --       --        --         --              (0.9)       --
  Foreign currency transaction
    adjustments......................   --       --       --       --        --         --            --             (0.1)
  Net loss...........................   --       --       --       --        --         --             (77.1)       --
  Dividends declared.................   --       --       --       --        --         --             (17.8)       --
                                       ------   ------   ------   ------   -------   -----------   -----------   ----------
Balance at December 31, 1993.........   --       --       89.8      0.9      496.9       (0.1)        (173.8)        (0.3)
  Issuance of common stock
     Employee stock compensation and
      savings plans..................   --       --        0.2     --          2.0      --            --            --
  Issuance of preferred stock........   10.7     91.4     --       --        --         --            --            --
  Amortization of restricted stock
    awards...........................   --       --       --       --        --           0.1         --            --
  Pension liability adjustment.......   --       --       --       --        --         --               0.9        --
  Foreign currency transaction
    adjustments......................   --       --       --       --        --         --            --             (0.1)
  Net income.........................   --       --       --       --        --         --              17.1        --
  Dividends declared.................   --       --       --       --        --         --             (11.7)       --
                                       ------   ------   ------   ------   -------   -----------   -----------   ----------
Balance at December 31, 1994.........   10.7     91.4     90.0      0.9      498.9      --            (167.5)        (0.4)
  Issuance of common stock
     Employee stock compensation and
      savings plans..................   --       --        0.3     --          2.5      --            --            --
  Foreign currency translation
    adjustments......................   --       --       --       --        --         --            --              0.1
  Net income.........................   --       --       --       --        --         --              26.6        --
  Dividends declared.................   --       --       --       --        --         --             (14.8)       --
                                       ------   ------   ------   ------   -------   -----------   -----------   ----------
Balance at December 31, 1995.........   10.7    $91.4     90.3     $0.9    $ 501.4      $--          $(155.7)      $ (0.3)
                                       ======   ======   ======   ======   ========  ===========   ===========   ==========
<CAPTION>
                                           TOTAL
                                       SHAREHOLDERS'
                                           EQUITY
                                       --------------
<S>                                        <C>
Balance at December 31, 1992.........      $416.6
  Issuance of common stock
     Employee stock compensation and
      savings plans..................         2.5
  Amortization of restricted
    stock awards.....................         0.4
  Pension liability adjustment.......        (0.9)
  Foreign currency transaction
    adjustments......................        (0.1)
  Net loss...........................       (77.1)
  Dividends declared.................       (17.8)
                                       --------------
Balance at December 31, 1993.........       323.6
  Issuance of common stock
     Employee stock compensation and
      savings plans..................         2.0
  Issuance of preferred stock........        91.4
  Amortization of restricted stock
    awards...........................         0.1
  Pension liability adjustment.......         0.9
  Foreign currency transaction
    adjustments......................        (0.1)
  Net income.........................        17.1
  Dividends declared.................       (11.7)
                                       --------------
Balance at December 31, 1994.........       423.3
  Issuance of common stock
     Employee stock compensation and
      savings plans..................         2.5
  Foreign currency translation
    adjustments......................         0.1
  Net income.........................        26.6
  Dividends declared.................       (14.8)
                                       --------------
Balance at December 31, 1995.........      $437.7
                                       ==============
</TABLE>
  The accompanying notes are an integral part of these financial statements.

                                       35

                         SANTA FE ENERGY RESOURCES, INC.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)  ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

  PRINCIPLES OF CONSOLIDATION

     The consolidated financial statements of Santa Fe Energy Resources, Inc.
("Santa Fe" or the "Company") and its subsidiaries include the accounts of all
wholly owned subsidiaries. The accounts of Santa Fe Energy Partners, L.P., (the
"Partnership") are included on a proportional basis until September 1993 when
Santa Fe purchased all the Partnership's outstanding Depositary Units and
undeposited LP Units other than those units held by Santa Fe and its affiliates.

     On September 27, 1993 the Company exercised its right under the Agreement
of Limited Partnership to purchase all of the Partnership's outstanding
Depositary Units and undeposited LP Units, other than those units held by the
Company and its affiliates, at a redemption price of $4.9225 per unit.
Consideration for the 5,749,500 outstanding units totalled $28.3 million. The
acquisition of the units was accounted for as a purchase and the results of
operations of the Partnership attributable to the units acquired are included in
the Company's results of operations with effect from October 1, 1993. The
purchase price was allocated primarily to oil and gas properties.

     References herein to the "Company" or "Santa Fe" relate to Santa Fe Energy
Resources, Inc., individually or together with its consolidated subsidiaries;
references to the "Partnership" relate to Santa Fe Energy Partners, L.P.

     All significant intercompany accounts and transactions have been
eliminated. Certain prior period amounts have been reclassified to conform to
current presentation.

  OIL AND GAS OPERATIONS

     The Company follows the successful efforts method of accounting for its oil
and gas exploration and production activities. Costs (both tangible and
intangible) of productive wells and development dry holes, as well as the cost
of prospective acreage, are capitalized. The costs of drilling and equipping
exploratory wells which do not find proved reserves are expensed upon
determination that the well does not justify commercial development. Other
exploratory costs, including geological and geophysical costs and delay rentals,
are charged to expense as incurred.

     Depletion and depreciation of proved properties are computed on an
individual field basis using the unit-of-production method based upon proved oil
and gas reserves attributable to the field. Certain other oil and gas properties
are depreciated or amortized on a straight-line basis.

     In the fourth quarter of 1995 the Company changed its impairment policy to
conform to the provisions of Statement of Financial Accounting Standards No. 121
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of" ("FAS 121"). In accordance with the provisions of FAS 121
individual proved properties are reviewed periodically to determine if the
carrying value of the property exceeds the expected undiscounted future net
revenues from the operation of the property. Based on this review and the
continuing evaluation of development plans, economics and other factors, as
appropriate, the Company records impairment (additional depletion and
depreciation) to the extent that the carrying value of the property exceeds the
present value of such expected future net revenues. The Company recorded
impairments of $30.2 million in 1995 and $99.3 million in 1993. With respect to
the impairments recorded in 1995, approximately $22.1 million was due to the
adoption of FAS 121.

     The Company provides for future abandonment and site restoration costs with
respect to certain of its oil and gas properties. The Company estimates that
with respect to these properties such future costs total approximately $34.2
million and such amount is being accrued over the expected life of the
properties. At December 31, 1995 and 1994 Accumulated Depletion, Depreciation,
Amortization and Impairment includes $15.5 million and $15.0 million,
respectively, with respect to such costs.

                                      36

                         SANTA FE ENERGY RESOURCES, INC.
          NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     The value of undeveloped acreage is aggregated and the portion of such
costs estimated to be nonproductive, based on historical experience, is
amortized to expense over the average holding period. Additional amortization
may be recognized based upon periodic assessment of prospect evaluation results.
The cost of properties determined to be productive is transferred to proved
properties; the cost of properties determined to be nonproductive is charged to
accumulated amortization.

     Maintenance and repairs are expensed as incurred; major renewals and
improvements are capitalized. Gains and losses arising from sales of properties
are included in income currently.

  REVENUE RECOGNITION

     Revenues from the sale of crude oil and liquids produced are generally
recognized upon the passage of title, net of royalties and net profits
interests.

     Revenues from natural gas production are generally recorded using the
entitlement method, net of royalties and net profits interests. Sales proceeds
in excess of the Company's entitlement are included in Deferred Revenues and the
Company's share of sales taken by others is included in Other Assets. At
December 31, 1995 the Company's deferred revenues for sales proceeds received in
excess of the Company's entitlement was $4.7 million with respect to 3.4 MMcf
and the asset related to the Company's share of sales taken by others was $5.8
million with respect to 4.1 MMcf.

     The Company hedges a portion of its oil and gas sales. See Note 11 --
Commitments and Contingencies -- Oil and Gas Hedging.

     Revenues from crude oil marketing and trading represent the gross margin
resulting from such activities. Revenues from such activities are net of costs
of sales of $225.9 million in 1993, $204.7 million in 1994 and $251.1 million in
1995.

     Revenues from natural gas systems are net of the cost of natural gas
purchased and resold. Such costs totalled $49.9 million in 1993.

  EARNINGS PER SHARE

     Earnings per share are based on the weighted average number of common
shares outstanding during the year.

  ACCOUNTS RECEIVABLE

     Accounts Receivable relates primarily to sales of oil and gas and amounts
due from joint interest partners for expenditures made by the Company on behalf
of such partners. The Company reviews the financial condition of potential
purchasers and partners prior to signing sales or joint interest agreements. At
December 31, 1995 and 1994 the Company's allowance for doubtful accounts
receivable, which is reflected in the consolidated balance sheet as a reduction
in accounts receivable, totalled $2.0 million and $3.1 million, respectively.
Accounts receivable totalling $1.1 million, $3.8 million and $0.1 million were
written off as uncollectible in 1995, 1994 and 1993, respectively.

  INVENTORIES

     Inventories are valued at the lower of cost (average price or first-in,
first-out) or market. Crude oil inventories at December 31, 1995 and 1994 were
$2.7 million and $1.6 million, respectively, and materials and supplies
inventories at such dates were $7.8 million and $7.6 million, respectively.

  ENVIRONMENTAL EXPENDITURES

     Environmental expenditures relating to current operations are expensed or
capitalized, as appropriate, depending on whether such expenditures provide
future economic benefits. Liabilities are

                                       37

                         SANTA FE ENERGY RESOURCES, INC.
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

recognized when the expenditures are considered probable and can be reasonably
estimated. Measurement of liabilities is based on currently enacted laws and
regulations, existing technology and undiscounted site-specific costs.
Generally, such recognition coincides with the Company's commitment to a formal
plan of action.

  INCOME TAXES

     The Company follows the asset and liability approach to accounting for
income taxes. Deferred tax assets and liabilities are determined using the tax
rate for the period in which those amounts are expected to be received or paid,
based on a scheduling of temporary differences between the tax bases of assets
and liabilities and their reported amounts. Under this method of accounting for
income taxes, any future changes in income tax rates will affect deferred income
tax balances and financial results.

  USE OF ESTIMATES

     The preparation of the Company's financial statements in conformity with
generally accepted accounting principles requires the Company to make certain
estimates and assumptions that affect the reported amounts of assets and
liabilities and the disclosure of contingent assets and liabilities and the
periods in which certain items of revenue and expense are included. Actual
results may differ from such estimates.

(2) CORPORATE RESTRUCTURING PROGRAM

     In the fourth quarter of 1993 the Company adopted a corporate restructuring
program which included (i) the concentration of capital spending in the
Company's core operating areas; (ii) the disposition of non-core assets; (iii)
the elimination of the $0.04 per share quarterly common stock dividend; and (iv)
an evaluation of the Company's capital and cost structures.

     The Company's non-core asset disposition program included the sale of its
natural gas gathering and processing assets to Hadson Corporation ("Hadson")
(see Note 3), the sale to Vintage Petroleum, Inc. ("Vintage") of certain
southern California and Gulf Coast oil and gas producing properties and the sale
to Bridge Oil (U.S.A.) Inc. ("Bridge") of certain mid-Continent and Rocky
Mountain oil and gas producing properties and undeveloped acreage. Based on the
evaluation of its capital and cost structures, the Company (i) implemented a
cost reduction program which included the reduction of its salaried work force
by approximately 20%, an improvement in the efficiency of its information
systems and reductions in other general and administrative and production and
operating costs and (ii) issued $100 million of 11% Senior Subordinated
Debentures and 10,700,000 shares of $.732 Series A Convertible Preferred Stock
(the "Series A Preferred") and used a portion of the proceeds to retire certain
of its long-term debt (see Note 6).

     In implementing the corporate restructuring program, in 1993 the Company
recorded restructuring charges of $38.6 million comprised of (i) losses on
property dispositions of $27.8 million; (ii) long-term debt repayment penalties
and interest of $8.6 million; and (iii) accruals for certain personnel benefits
and related costs of $2.2 million. In the first quarter of 1994 the Company
recorded additional restructuring charges of $7.0 million comprised of
severance, benefits and relocation expenses associated with the cost reduction
program.

     SALE TO VINTAGE. In November 1993 the Company completed the sale of certain
southern California and Gulf Coast producing properties for net proceeds
totalling $42.0 million in cash, $31.5 million of which was collected in 1993.
The Company's income from operations for 1993 includes $2.7 million attributable
to the assets sold to Vintage.

     SALE TO BRIDGE.  In April 1994 the Company completed the sale to Bridge
of certain Mid-Continent and Rocky Mountain producing and nonproducing oil and
gas properties for net proceeds

                                       38

                         SANTA FE ENERGY RESOURCES, INC.
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

totalling $46.7 million in cash. The net book value of these assets was included
in Assets Held for Sale at December 31, 1993. The Company's income from
operations for 1994 and 1993 includes $2.2 million and $5.8 million,
respectively, attributable to the assets sold to Bridge.

     OTHER DISPOSITIONS.  In the first quarter of 1994 the Company sold its
interest in certain other oil and gas properties, in which it had no remaining
basis, for $8.3 million.

     DEBT EXTINGUISHMENT. In April 1995 the Securities and Exchange Commission
issued Staff Accounting Bulletin No. 94, "Recognition of a Gain or Loss on Early
Extinguishment of Debt" ("SAB 94") which changes in some respects the accounting
which has evolved in practice for gains or losses on anticipated debt
extinguishments. Among other things, SAB 94 precludes the recognition of a gain
or loss from debt extinguishment in a period other than the period in which the
debt is considered extinguished, including circumstances in which a company
announces prior to a period end the intention to retire debt in a subsequent
period. Had SAB 94 been in effect in 1993, the $8.6 million in long-term debt
repayment penalties and interest which was included in the Company's 1993
results of operations would have been included in the Company's 1994 results of
operations. The following table reflects, on a proforma basis, the Company's
results of operations assuming SAB 94 was in effect in 1993 (in millions of
dollars, except per share data):
<TABLE>
<CAPTION>

                             YEAR ENDED DECEMBER 31,
                                        ------------------------------------------------------
                                                  1994                         1993
                                        -------------------------    -------------------------
                                        HISTORICAL     PROFORMA      HISTORICAL     PROFORMA
                                        ----------    -----------    ----------    -----------
                                                      (UNAUDITED)                  (UNAUDITED)
<S>                                        <C>            <C>          <C>            <C>
Income (Loss) from Operations........      48.2           48.2         (113.0)        (104.4)
Income (Loss) Before Extraordinary
  Item...............................      17.1           15.1          (77.1)         (71.8)
Extraordinary Item -- Loss on
  Extinguishment of Debt.............       --            (3.3)           --            --
Net Income (Loss)....................      17.1           11.8          (77.1)         (71.8)
Earnings (Loss) Attributable to
  Common Shares......................       5.4            0.1          (84.1)         (78.8)
Earnings (Loss) Per Share
     Extraordinary Item..............       --           (0.04)           --            --
     Attributable to Common Shares...      0.06            --           (0.94)         (0.88)
</TABLE>
(3)  INVESTMENT IN HADSON

     In December 1993 the Company completed a transaction with Hadson under the
terms of which the Company sold the common stock of Adobe Gas Pipeline Company
("AGPC"), a wholly-owned subsidiary which held the Company's natural gas
gathering and processing assets, to Hadson in exchange for Hadson 11.25%
preferred stock with a face value of $52.0 million and 40% of Hadson's common
stock. The Company accounted for the sale as a non-monetary transaction and the
investment in Hadson was valued at $56.2 million, the carrying value of the
Company's investment in AGPC. The Company's investment in Hadson is accounted
for on the equity basis. The Company's income from operations for 1993 includes
$1.6 million attributable to the assets sold to Hadson.

     Also in December 1993 the Company signed a seven-year gas sales contract
with Hadson under the terms of which Hadson markets a substantial portion of the
Company's domestic natural gas production at market prices as defined by
published monthly indices for relevant production locations.

     In November 1994 the Company and Hadson settled a lawsuit related to
certain of the assets sold to Hadson by the Company in December 1993. The
settlement totalled $5.7 million and the Company's share, approximately $3.3
million, is included in Other Income (Expense) in the income statement. The
Company paid the full amount of the settlement and Hadson gave the Company a
$2.4 million ten-year
                                      39

                       SANTA FE ENERGY RESOURCES, INC.
          NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
note for its share. The note bore interest at 9%, payable annually, with the
principal amount due at maturity. The note was retired as part of the sales
transaction discussed below.

     In 1995 the Company sold its holdings in Hadson for $55.2 million. Other
Income (Expense) for 1995 includes a $1.8 million charge with respect to the
Company's loss on the sale.

     The following table summarizes the Company's investment in Hadson and the
changes in such investment during 1994 and 1995 (in millions of dollars):

Investment at December 31, 1993......    56.2
Preferred dividends, paid in-kind....     4.5
Equity in losses and valuation
  adjustments........................    (6.1)
Note receivable......................     2.4
                                        -----
Investment at December 31, 1994......    57.0
Proceeds from sale...................   (55.2)
                                        -----
Loss on sale.........................     1.8
                                        =====
(4)  SANTA FE ENERGY TRUST

     In November 1992 5,725,000 Depository Units ("Trust Units"), each
consisting of beneficial ownership of one unit of undivided beneficial interest
in the Santa Fe Energy Trust (the "Trust") and a $20 face amount beneficial
ownership interest in a $1,000 face amount zero coupon United States Treasury
obligation maturing on or about February 15, 2008, were sold in a public
offering. The Trust consists of certain oil and gas properties conveyed by Santa
Fe.

     In the first quarter of 1994, the Company sold 575,000 Trust Units which it
held for $11.3 million. The gain on the sale of $0.8 million is included in
Other Income (Expense).

     For any calendar quarter ending on or prior to December 31, 2002, the Trust
will receive additional royalty payments to the extent that it needs such
payments to distribute $0.40 per Depository Unit per quarter. The source of such
additional royalty payments, if needed, will be limited to the Company's
remaining royalty interest in certain of the properties conveyed to the Trust.
If such additional payments are made, certain proceeds otherwise payable to the
Trust in subsequent quarters may be reduced to recoup the amount of such
additional payments. The aggregate amount of the additional royalty payments
(net of any amounts recouped) will be limited to $20.0 million on a revolving
basis. The Company has been required to make additional royalty payments
totalling $0.4 million in 1993, $1.1 million in 1994 and $0.5 million in 1995.

     At December 31, 1995 and 1994, Accounts Payable included $2.6 million and
$2.7 million, respectively, due to the Trust.

                                      40

                         SANTA FE ENERGY RESOURCES, INC.
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(5)  CASH FLOWS

     The Company considers all highly liquid investments with a maturity of
three months or less when purchased to be cash equivalents.

     The Company made interest payments of $48.0 million, $47.9 million and
$37.6 million in 1993, 1994 and 1995, respectively. In 1993, 1994 and 1995, the
Company made tax payments of $5.0 million, $1.8 million and $1.6 million,
respectively, and in 1993 and 1995 received tax refunds of $4.1 million and $1.3
million, respectively, primarily related to the audit of prior years' returns.

(6)  FINANCING AND DEBT

     Long-term debt at December 31, 1995 and 1994 consisted of (in millions of
dollars):

                                                     DECEMBER 31,
                                    --------------------------------------------
                                            1995                    1994
                                    --------------------    --------------------
                                    CURRENT    LONG-TERM    CURRENT    LONG-TERM
                                    -------    ---------    -------    ---------
Senior Notes........................  --         245.0        --         245.0
11% Senior Subordinated Debentures..  --          99.4        --          99.3
Notes Payable to Bank...............  --          --           3.9         6.1
                                    -------    ---------    -------    ---------
                                      --         344.4         3.9       350.4
                                    =======    =========    =======    =========
     Aggregate total maturities of long-term debt during the next five years are
as follows: 1996 -- none; 1997 -- $35.0 million; 1998 -- $35.0 million; 1999 --
$25.0 million; and 2000 -- $25.0 million.

     Effective April 1, 1995 the Company entered into the Second Amended and
Restated Revolving Credit Agreement (the "Credit Agreement"), an unsecured
revolving credit agreement which matures December 31, 1998. The maximum
borrowing limits under the Credit Agreement are initially $125.0 million, $105.0
million beginning February 28, 1996, $65.0 million beginning February 28, 1997
and $30.0 million beginning February 28, 1998. Interest rates under the Credit
Agreement are tied to LIBOR or the bank's prime rate with the actual interest
rate based upon certain ratios and the value and projected timing of production
of the Company's oil and gas reserves. These and other similar ratios will also
affect the Company's ability to borrow under the Credit Agreement and the timing
and amount of any required repayments and corresponding commitment reductions.
At December 31, 1995, $6.4 million in letters of credit were outstanding under
the terms of the Credit Agreement.

     In a public offering in May 1994 the Company issued $100.0 million of 11%
Senior Subordinated Debentures due 2004 (the "Debentures"). The Debentures were
issued for 99.266% of face value and the Company received proceeds of $96.1
million, after deducting related costs and expenses of $3.2 million. The
Debentures, which mature May 15, 2004, are not redeemable prior to May 15, 1999
and may be redeemed after such date at the option of the Company at prices set
forth in the indenture for the Debentures. Under certain circumstances, the
Company may be required to redeem the Debentures for 101% of the principal
amount. The Debentures are general unsecured subordinated obligations of the
Company.

     The Company used the proceeds from the issuance of the Debentures, together
with a portion of the proceeds from the issuance of the Series A Preferred (see
Note 9), to retire certain of its then outstanding long-term debt. The Company
retired $65.0 million of Senior Notes, the $12.3 million outstanding balance of
a term loan agreement which the Company had executed in 1991 in connection with
the purchase of certain producing properties, the $30.0 million outstanding
balance of the Partnership's credit agreement and the $25.0 million outstanding
balance of the Bank Facility.

                                       41

                         SANTA FE ENERGY RESOURCES, INC.
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     On April 11, 1990 the Company issued $365.0 million of serial unsecured
Senior Notes with interest rates averaging 10.35%. At December 31, 1995, $245.0
million in Senior Notes were outstanding and are to be repaid, $35.0 million in
1997 and 1998 and $25.0 million per year in 1999 through 2005.

     In the first quarter of 1995 the Company retired the $10.0 million balance
of a loan from an Argentine bank. The loan, which related to the Company's
purchase of an interest in a producing oil field in Argentina in 1991, bore
interest at 13% at the time it was retired.

     The Company has three short-term uncommitted lines of credit totalling
$50.0 million which are used to meet short-term cash needs. Interest rates on
borrowings under these lines of credit are typically lower than rates paid under
the Bank Facility. At December 31, 1995 no amounts were outstanding under these
lines of credit.

     Certain of the Company's credit agreements and the indenture for the
Debentures include covenants that restrict the Company's ability to take certain
actions, including the ability to incur additional indebtedness and to pay
dividends on capital stock. Under the most restrictive of these covenants, at
December 31, 1995 the Company could incur up to $191.0 million of additional
indebtedness and pay dividends of up to $114.2 million on its aggregate capital
stock (including its common stock, 7% Convertible Preferred Stock and Series A
Preferred) with the amount payable on its common stock limited to $52.0 million.

                                       42

                         SANTA FE ENERGY RESOURCES, INC.
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(7)  SEGMENT INFORMATION

     The principal business of the Company consists of the acquisition,
exploration and development of oil and gas properties and the production and
sale of crude oil and liquids and natural gas. Pertinent information with
respect to the Company's oil and gas business is presented in the following
table (in millions of dollars):
<TABLE>
<CAPTION>
                                                      OIL AND GAS
                                       ------------------------------------------
                                                                           OTHER     GENERAL
                                         U.S.     ARGENTINA   INDONESIA   FOREIGN   CORPORATE     TOTAL
                                       ---------  ---------   ---------   -------   ---------   ---------
<S>                                        <C>       <C>         <C>        <C>       <C>           <C>
1995
  Revenues...........................      391.2     19.2        31.6       --        --            442.0
  Income (Loss) from Operations......       87.9      3.6         0.8       (6.5)     (31.9)         53.9
  Depletion, Depreciation,
     Amortization and Impairment.....      143.3      7.0        10.0        0.5        2.6         163.4
  Additions to Property and
     Equipment.......................      175.4     14.4        16.7        3.8        6.5         216.8
  Identifiable Assets at December
     31..............................      806.7     73.0        84.8        9.5       90.8       1,064.8
1994
  Revenues...........................      346.7     12.9        31.8       --        --            391.4
  Income (Loss) from Operations......       88.9      3.1         6.1      (10.3)     (39.6)         48.2
  Depletion, Depreciation,
     Amortization and Impairment.....       99.9      3.8         9.7        6.3        1.6         121.3
  Additions to Property and
     Equipment.......................       98.2     13.6        16.3        4.4        5.4         137.9
  Identifiable Assets at December
     31..............................      817.6     57.8       103.1        6.5       86.4       1,071.4
1993
  Revenues...........................      401.2     12.5        23.2         --         --         436.9
  Income (Loss) from Operations......      (33.6)     3.0       (13.4)     (18.4)     (50.6)       (113.0)
  Depletion, Depreciation,
     Amortization and Impairment.....      218.8      3.6        21.2        6.7        1.7         252.0
  Additions to Property and
     Equipment.......................      116.1      7.3        16.8        6.1        4.4         150.7
  Identifiable Assets at December
     31..............................      862.0     48.2        65.3        2.8       98.6       1,076.9
</TABLE>
     Crude oil and liquids and natural gas accounted for more than 93% of
revenues in 1993, 1994 and 1995. The following table (which with respect to
certain properties includes royalty and working interest owners' share of
production) reflects sales to crude oil purchasers who accounted for more than
10% of the Company's crude oil and liquids revenues (in millions of dollars):

                                          YEAR ENDED DECEMBER 31,
                                          ------------------------
                                          1995     1994       1993
                                          -----    -----      ----
Celeron Corporation..................      62.1     58.7      56.8
Shell Oil Company....................     100.4     94.5      86.3

     None of the Company's purchasers of natural gas accounted for more than 10%
of natural gas revenues in 1993. In 1995 and 1994 the only purchaser of the
Company's natural gas to account for more than 10% of natural gas revenues was
Hadson (see Note 3 with respect to the Company's gas sales contract with
Hadson).

(8)  CONVERTIBLE PREFERRED STOCK

     The convertible preferred stock issued in connection with the Company's
merger with Adobe Resources Corporation ("Adobe") in 1992 is non-voting and
entitled to receive cumulative cash

                                      43

                       SANTA FE ENERGY RESOURCES, INC.
          NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
dividends at an annual rate equivalent to $1.40 per share. The holders of the
convertible preferred shares may, at their option, convert any or all such
shares into 1.3913 shares of the Company's common stock. The Company may, at any
time after the fifth anniversary of the effective date of the Merger and upon
the occurrence of a "Special Conversion Event", convert all outstanding shares
of convertible preferred stock into common stock at the initial conversion rate
of 1.3913 shares of common stock, subject to certain adjustments, plus
additional shares in respect to accrued and unpaid dividends. A Special
Conversion Event is deemed to have occurred when the average daily closing price
for a share of the Company's common stock for 20 of 30 consecutive trading days
equals or exceeds 125% of the quotient of $20.00 divided by the then applicable
conversion rate (approximately $18.00 per share at a conversion rate of 1.3913).

     Upon the occurrence of the "First Ownership Change" of Santa Fe, each
holder of shares of convertible preferred stock shall have the right, at the
holder's option, to elect to have all of such holder's shares redeemed for
$20.00 per share plus accrued and unpaid interest and dividends. The First
Ownership Change shall be deemed to have occurred when any person or group,
together with any affiliates or associates, becomes the beneficial owner of 50%
or more of the outstanding common stock of Santa Fe.

(9)  SHAREHOLDERS' EQUITY

  COMMON STOCK

     In 1993, 1994 and 1995 the Company issued a total of 0.8 million previously
unissued shares of common stock in connection with certain employee benefit and
compensation plans.

     The Company declared dividends to common shares of $0.12 per share in 1993.
No dividends were declared in 1994 or 1995 (see Note 2).

  $.732 SERIES A CONVERTIBLE PREFERRED STOCK

     In a public offering in May 1994 the Company issued 10,700,000 shares of
$.732 Series A Convertible Preferred Stock. The Series A Preferred was issued at
$8.875 per share and the Company received total proceeds of $91.4 million after
deducting related costs and expenses of $3.6 million. Each share of Series A
Preferred mandatorily converts into one share of common stock on May 15, 1998
and the Company has the option to redeem the shares, in whole or in part, on or
after May 15, 1997 and prior to May 15, 1998 at prices set forth in the
certificate of designation for the Series A Preferred, payable in common stock.
Each share of Series A Preferred is convertible at the option of the holder into
0.8474 shares of common stock at any time prior to May 15, 1998.

     The Series A Preferred ranks prior to common stock both as to payment of
dividends and distribution of assets upon liquidation. The holders of Series A
Preferred are entitled to receive cumulative preferential dividends, accruing at
the rate per share of $0.732 per annum ($0.183 per quarter) payable quarterly in
arrears.

  PREFERRED STOCK

     The Board of Directors of the Company is empowered, without approval of the
shareholders, to cause shares of preferred stock to be issued in one or more
series, and to determine the number of shares in each series and the rights,
preferences and limitations of each series. Among the specific matters which may
be determined by the Board of Directors are: the annual rate of dividends; the
redemption price, if any; the terms of a sinking or purchase fund, if any; the
amount payable in the event of any voluntary liquidation, dissolution or winding
up of the affairs of the Company; conversion rights, if any; and voting powers,
if any.

                                      44

                       SANTA FE ENERGY RESOURCES, INC.
          NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

  1990 INCENTIVE STOCK COMPENSATION PLAN

     Under the terms of the Santa Fe Energy Resources 1990 Incentive Stock
Compensation Plan (the "Plan") the Company may grant options and awards with
respect to no more than 7,500,000 shares of common stock to officers, directors
and key employees.

     Options granted in 1991 and prior are fully vested and expire in 2000.
Options granted in 1992 are fully vested and expire in 2002. The options granted
in 1993 have a ten year term and vest as to 50 percent 5 years after grant, as
to a cumulative 75 percent 6 years after grant and as to the entire amount 7
years after grant. The options are exercisable on an accelerated basis beginning
one year and ending three years after grant in certain circumstances. If the
market value per share of the Company's common stock (sustained in all events
for at least 60 days) exceeds $15, 25 percent of the options shall become
exercisable; in the event the market value per share exceeds $20, 50 percent of
the options shall become exercisable; and in the event the market value exceeds
$25, 100 percent shall become exercisable. The options granted in 1995 have a
ten year term. With respect to 250,000 of such options, vesting occurs 50
percent six months after grant, as to a cumulative 75 percent one year after
grant and as to the entire amount two years after grant. The remainder of the
options granted in 1995 vest as to 33.33 percent one year after grant, as to a
cumulative 66.67 percent two years after grant and as to the entire amount three
years after grant.

     The following table reflects activity with respect to Non-Qualified Stock
Options during 1993 through 1995:

                                          OPTION
                                       OPTIONS PRICE
                                        OUTSTANDING          PER SHARE
                                        ------------    -------------------
Outstanding at January 1, 1993.......    2,811,928      $9.5625 to $ 24.24
Grants...............................      800,000      $9.5625
Cancellations........................      (95,398)     $9.5625 to $ 24.24
Exercises............................       (6,945)     $9.5625
                                        ------------
Outstanding at December 31, 1993.....    3,509,585      $9.5625 to $ 24.24
Cancellations........................     (206,063)     $9.5625 to $ 24.24
                                        ------------
Outstanding at December 31, 1994.....    3,303,522      $9.5625 to $ 24.24
Grants...............................      985,500      $7.875 to $  8.00
Cancellations........................      (61,280)     $7.875 to $ 24.24
Exercises............................       (9,444)     $7.875 to $9.5625
                                        ------------
Outstanding at December 31, 1995.....    4,218,298      $7.875 to $ 24.24
                                         ===========

     At December 31, 1995 options on 2,243,644 shares were available for future
grants.

     In 1995 and 1994 the Company issued 217,566 and 101,423 common shares,
respectively, in accordance with the terms of certain employee compensation
plans.

     In December 1995 the Company granted 104,542 "Phantom Units" to certain
executive officers. The Phantom Units are to be earned over a three-year period
commencing January 1, 1996. The number of Phantom Units earned is dependent upon
the Company achieving certain goals with respect to cash flows, production
volumes and stock price. Ultimate payment, if any, will be made in an

                                       45

                         SANTA FE ENERGY RESOURCES, INC.
          NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

equivalent number of shares of the Company's common stock. Compensation expense
will be recognized over the period the Phantom Units are earned based on the
market price of the Company's common stock.

  1995 INCENTIVE STOCK COMPENSATION PLAN

     Under the terms of the Santa Fe Energy Resources 1995 Incentive Stock
Compensation Plan for Nonexecutive Employees the Company may grant options and
awards with respect to not more than 1,000,000 shares of common stock per year
to employees other than executive officers and directors. During 1995 the
Company granted options on 218,750 shares (8,500 of which were subsequently
cancelled) at $9.625 per share. The grants, which were made at the market price
of the Company's common stock at the time of grant, vest one year from the date
of grant. During 1995 the Company also issued 2,000 restricted shares in
accordance with the terms of the plan. At December 31, 1995 options on 212,250
shares were outstanding.

(10)  PENSION AND OTHER EMPLOYEE BENEFIT PLANS

  PENSION PLANS

     The Company has a defined benefit retirement plan (the "SFER Plan")
covering substantially all salaried employees not covered by collective
bargaining agreements and a nonqualified supplemental retirement plan (the
"Supplemental Plan"). The Supplemental Plan will pay benefits to participants in
the SFER Plan in those instances where the SFER Plan formula produces a benefit
in excess of limits established by ERISA and the Tax Reform Act of 1986.
Benefits payable under the SFER Plan are based on years of service and
compensation during the five highest paid years of service during the ten years
immediately preceding retirement. The Company's funding policy is to contribute
annually not less than the minimum required by ERISA and not more than the
maximum amount deductible for income tax purposes.

                                      46

                         SANTA FE ENERGY RESOURCES, INC.
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     The following table sets forth the funded status of the SFER Plan and the
Supplemental Plan at December 31, 1995 and 1994 (in millions of dollars):

                                            SFER PLAN         SUPPLEMENTAL PLAN
                                       --------------------  ------------------
                                         1995       1994       1995     1994
                                       ---------  ---------  ---------  -------
Plan assets at fair value, primarily invested in common stocks and U.S.
  and corporate bonds................       32.5       29.1         --       --
Actuarial present value of projected
  benefit obligations:
     Accumulated benefit obligations
           Vested....................      (30.4)     (26.4)      (0.7)    (0.8)
           Nonvested.................       (1.3)      (1.3)        --       --
     Effect of projected future
        salary
        increases....................       (7.3)      (5.3)      (1.3)    (4.0)
                                        ---------  ---------  ---------  -------
Excess of projected benefit
  obligations over plan assets.......       (6.5)      (3.9)      (2.0)    (4.8)
Unrecognized net loss from past
  experience different from that
  assumed and effects of changes in
  assumptions........................        3.0        1.7       (2.1)     1.6
Unrecognized prior service cost......       (2.0)      (2.1)       2.0      2.1
Unrecognized net (asset) obligation
  being recognized over plan's
  average remaining
  service life.......................       (0.9)      (1.0)       0.2      0.2
                                        ---------  ---------  ---------  -------
Accrued pension liability............       (6.4)      (5.3)      (1.9)    (0.9)
                                        =========  =========  =========  =======

Major assumptions at year-end
     Discount rate...................       7.50%      8.25%      7.50%    8.25%
     Long-term asset yield...........       9.50%      9.50%      9.50%    9.50%
     Rate of increase in future
        compensation.................       5.25%      5.25%      5.25%    5.25%

     The following table sets forth the components of pension expense for the
SFER Plan and Supplemental Plan for 1995, 1994 and 1993 (in millions of
dollars):
<TABLE>
<CAPTION>
                                              SFER PLAN                 SUPPLEMENTAL PLAN
                                        ----------------------        ----------------------
                                        1995     1994     1993        1995     1994     1993
                                        ----     ----     ----        ----     ----     ----
<S>                                      <C>      <C>      <C>        <C>      <C>      <C>
Service cost.........................    1.3      1.7      1.4        0.4       --       --
Interest cost........................    2.7      2.8      2.6        0.4      0.1      0.1
Return on plan assets................   (5.5)     0.5     (1.4)        --       --       --
Net amortization and deferral........    2.5     (3.3)    (1.3)       0.3       --       --
                                        ----     ----     ----        ----     ----     ----
                                         1.0      1.7      1.3        1.1      0.1      0.1
                                        ====     ====     ====        ====     ====     ====
</TABLE>
     The Company sponsors a pension plan covering certain hourly-rated employees
in California (the "Hourly Plan"). The Hourly Plan provides benefits that are
based on a stated amount for each year of service. The Company annually
contributes amounts which are actuarially determined to provide the Hourly Plan
with sufficient assets to meet future benefit payment requirements.

                                      47

                         SANTA FE ENERGY RESOURCES, INC.
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     The following table sets forth the funded status of the Hourly Plan at
December 31, 1995 and 1994 (in millions of dollars):

                                         1995       1994
                                       ---------  ---------
Plan assets at fair value, primarily
invested in fixed-rate securities....        8.7        7.5
Actuarial present value of projected
benefit obligations
     Accumulated benefit obligations
           Vested....................      (10.4)      (9.3)
           Nonvested.................       (0.4)      (0.3)
                                       ---------  ---------
Excess of projected benefit
  obligation over plan assets........       (2.1)      (2.1)
Unrecognized net (gain) loss from
  past experience different from that
  assumed and effects of changes in
  assumptions........................       (0.3)      (0.4)
Unrecognized prior service cost......        0.4        0.5
Unrecognized net obligation..........        1.2        1.3
Additional minimum liability.........       (1.3)      (1.3)
                                       ---------  ---------
     Accrued pension liability.......       (2.1)      (2.0)
                                       =========  =========
Major assumptions at year-end
     Discount rate...................       7.50%      8.25%
     Expected long-term rate of
       return on plan assets.........       8.50%      8.50%

The following table sets forth the components of pension expense for the Hourly
Plan for 1995, 1994 and 1993 (in millions of dollars):

                                           YEAR ENDED DECEMBER 31,
                                       -------------------------------
                                         1995       1994       1993
                                       ---------  ---------  ---------
     Service cost....................        0.2        0.2        0.2
     Interest cost...................        0.8        0.8        0.7
     Return on plan assets...........       (1.4)      (0.4)      (0.8)
     Net amortization and deferral...        0.9         --        0.4
                                       ---------  ---------  ---------
                                             0.5        0.6        0.5
                                       =========  =========  =========

     In the fourth quarter of 1993 the Company established a pension plan for
certain persons employed in foreign locations (the "Foreign Plan"). The
following table sets forth the funded status of the Foreign Plan at December 31,
1995 and 1994 (in millions of dollars):

                                         1995       1994
                                       ---------  ---------
Plan assets..........................     --         --
Actuarial present value of projected
  benefit obligations:
     Accumulated benefit
        obligations -- nonvested.....       (0.2)      (0.1)
     Effect of projected future
        salary increases.............      --         --
                                       ---------  ---------
Excess of projected benefit
  obligations over plan assets.......       (0.2)      (0.1)
Unrecognized prior service costs.....        0.1        0.1
                                       ---------  ---------
Accrued pension liability............       (0.1)     --
                                       =========  =========
Major assumptions at year-end:
     Discount rate...................       7.50%      8.25%
     Rate of increase in future
        compensation.................       5.25%      5.25%

                                      48

                         SANTA FE ENERGY RESOURCES, INC.
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     The following table sets forth the components of pension expense for the
Foreign Plan for 1995 and 1994 (in millions of dollars):

                                       YEAR ENDED DECEMBER
                                               31,
                                       --------------------
                                         1995       1994
                                       ---------  ---------
Service cost.........................        0.1     --
Interest cost........................     --         --
Net amortization and deferral........     --         --
                                       ---------  ---------
                                             0.1     --
                                       =========  =========

  POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

     The Company provides health care and life insurance benefits for
substantially all employees who retire under the provisions of a
Company-sponsored retirement plan and their dependents. Participation in the
plans is voluntary and requires a monthly contribution by the employee.
Effective January 1, 1993 the Company adopted the provisions of SFAS No. 106 --
"Employers" Accounting for Postretirement Benefits Other Than Pensions'. The
Statement requires the accrual, during the years the employee renders service,
of the expected cost of providing postretirement benefits to the employee and
the employee's beneficiaries and covered dependents. The following table sets
forth the plan's funded status at December 31, 1995 and 1994 (in millions of
dollars):

                                           DECEMBER 31,
                                       --------------------
                                         1995       1994
                                       ---------  ---------
Plan assets, at fair value...........     --         --
Accumulated postretirement benefit
  obligation
  Retirees...........................       (4.6)      (4.2)
  Eligible active participants.......       (1.4)      (0.9)
  Other active participants..........       (1.2)      (0.9)
                                       ---------  ---------
Accumulated postretirement benefit
  obligation in excess of plan
  assets.............................       (7.2)      (6.0)
Unrecognized transition obligation...        3.8        4.1
Unrecognized net loss (gain) from
  past experience different from that
  assumed and from changes in
  assumptions........................        0.3       (0.4)
                                       ---------  ---------
Accrued postretirement benefit
  cost...............................       (3.1)      (2.3)
                                       =========  =========

Assumed discount rate................       7.75%      8.50%
Assumed rate of compensation
  increase...........................       5.25%      5.25%

     The Company's net periodic postretirement benefit cost for 1995, 1994 and
1993 includes the following components (in millions of dollars):

                                        YEAR ENDED DECEMBER 31,
                                        ------------------------
                                        1995      1994      1993
                                        ----      ----      ----
Service costs........................   0.3       0.4       0.3
Interest costs.......................   0.5       0.5       0.4
Amortization of unrecognized
  transition obligation..............   0.3       0.3       0.3
                                        ----      ----      ----
                                        1.1       1.2       1.0
                                        ====      ====      ====

     Estimated costs and liabilities have been developed assuming trend rates
for growth in future health care costs beginning with 8.0% for 1995 graded to
6.0% (5.5% for post age 65) by the year 2000

                                      49

                         SANTA FE ENERGY RESOURCES, INC.
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

and remaining constant thereafter. Increasing the assumed health care cost trend
rate by one percent each year would increase the accumulated postretirement
benefit obligation as of December 31, 1995 by $0.7 million and the aggregate of
the service cost and interest cost components of the net periodic postretirement
benefit cost for 1996 by $0.1 million.

  SAVINGS PLAN

     The Company has a savings plan available to substantially all salaried
employees and intended to qualify as a deferred compensation plan under Section
401(k) of the Internal Revenue Code (the "401(k) Plan"). The Company will match
employee contributions for an amount up to 4% of each employee's base salary. In
addition, if at the end of each fiscal year the Company's performance for such
year has exceeded certain predetermined criteria, each participant will receive
an additional matching contribution equal to 50% of the regular matching
contribution. The Company's contributions to the 401(k) Plan, which are charged
to expense, totalled $1.5 million in 1993, $1.2 million in 1994 and $1.3 million
in 1995.

     In the fourth quarter of 1993 the Company established a new savings plan
with respect to certain personnel employed in foreign locations. The plan is an
unsecured creditor of the Company and at December 31, 1995 and 1994 the
Company's liability with respect to the plan totalled $0.1 million and $0.1
million, respectively.

  OTHER POSTEMPLOYMENT BENEFITS

     In the fourth quarter of 1993 the Company adopted SFAS No. 112 --
"Employers" Accounting for Postemployment Benefits'. The Statement requires the
accrual of the estimated costs of benefits provided by an employer to former or
inactive employees after employment but before retirement. Such benefits include
salary continuation, supplemental unemployment benefits, severance benefits,
disability-related benefits, job training and counseling and continuation of
benefits such as health care and life insurance coverage. The adoption of SFAS
No. 112 resulted in a charge to earnings of $1.8 million in 1993.

(11)  COMMITMENTS AND CONTINGENCIES

  OIL AND GAS HEDGING

     The Company hedges a portion of its oil and gas sales to provide a certain
minimum level of cash flow from its sales of oil and gas. While the hedges are
generally intended to reduce the Company's exposure to declines in market price,
the Company's gain from increases in market price may be limited. The Company
uses various financial instruments whereby monthly settlements are based on
differences between the prices specified in the instruments and the settlement
prices of certain futures contracts quoted on the New York Mercantile Exchange
("NYMEX") or certain other indices. Generally, in instances where the applicable
settlement price is less than the price specified in the contract, the Company
receives a settlement based on the difference; in instances where the applicable
settlement price is higher than the specified price, the Company pays an amount
based on the difference. The instruments utilized by the Company differ from
futures contracts in that there is no contractual obligation which requires or
allows for the future delivery of the product. Gains or losses on hedging
activities are recognized in oil and gas revenues in the period in which the
hedged production is sold.

     At December 31, 1995 the Company had open crude hedges on (i) an average of
15,000 barrels per day for the period January to April 1996 at an average NYMEX
WTI price of $18.52 per barrel and (ii) provided that the NYMEX WTI price is
greater than $16.80 per barrel, up to an additional 15,000 barrels per day for
the period January through March 1996 at an average NYMEX WTI price of $18.65
per barrel. The "approximate break-even price" (the average of the daily
settlement prices which

                                      50

                         SANTA FE ENERGY RESOURCES, INC.
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

result in no settlement being due to or from the Company) with respect to all
such contracts is approximately $18.56 per barrel. During 1995 crude oil hedges
resulted in a $2.4 million increase in revenues.

     Subsequent to year-end the Company hedged an additional 2,000 barrels per
day for the second quarter of 1996 and, provided that the settlement price is
above $17.00, up to an additional 8,000 barrels per day for the second quarter
of 1996 and 2,000 barrels per day for the third quarter of 1996. The approximate
break-even price is $18.54 per barrel for the second quarter hedges and $18.60
per barrel for the third quarter hedges.

     At December 31, 1995 the Company had open natural gas hedges on (i) an
average of approximately 55 MMcf per day of its Gulf Coast production for the
entire year of 1996 at an approximate break-even price of $1.82 per Mcf and (ii)
an average of approximately 30 MMcf per day of its Permian Basin production for
the entire year of 1996 at an approximate break-even price of $1.53 per Mcf. Due
to its location, Permian Basin gas sells at a discount to Gulf Coast gas.
Natural gas hedges resulted in a decrease in revenues of $0.3 million in 1995
and $1.0 million in 1994.

     In addition to its oil and gas sales hedges, for the first six months of
1996 the Company has hedged 20 MMcf per day of the natural gas it purchases for
use in its steam generation operations in the San Joaquin Valley of California.
Monthly settlements are based on the difference between the settlement price
quoted on the NYMEX and the index price for San Juan Basin natural gas. Gains or
losses are recognized in production and operating costs in the period in which
the hedged gas is consumed in operations.

     In instances where the difference between the NYMEX price and the San Juan
Basin index price is greater than $0.53, the Company pays an amount based on the
difference and in instances where the difference is less than $0.53, the Company
receives a payment based on the difference. Each $0.10 per Mcf change in the
spread between the NYMEX price and the San Juan Basin index price results in a
monthly increase or decrease in revenues of $60,000.

  INDEMNITY AGREEMENT WITH SANTA FE PACIFIC CORPORATION ("SFP")

     In December 1990 SFP distributed all of the shares of the Company it held
to its shareholders (the "Spin-Off"). At the time of the Spin-Off, the Company
and SFP entered into an agreement to protect SFP from federal and state income
taxes, penalties and interest that would be incurred by SFP if the Spin-off were
determined to be a taxable event resulting primarily from actions taken by the
Company during a one-year period that ended December 4, 1991. If the Company
were required to make payments pursuant to the agreement, such payments could
have a material adverse effect on its financial condition; however, the Company
does not believe that it took any actions during such one-year period that would
have such an effect on the Spin-Off.

  ENVIRONMENTAL REGULATION

     Federal, state and local laws and regulations relating to environmental
quality control affect the Company in all of its oil and gas operations.

     The Company has been identified as one of over 250 potentially responsible
parties ("PRPs") at a superfund site in Los Angeles County, California. The site
was operated by a third party as a waste disposal facility from 1948 until 1983.
The Environmental Protection Agency ("EPA") is requiring the PRPs to undertake
remediation of the site in several phases, which include site monitoring and
leachate control, gas control and final remediation. In November 1988 the EPA
and a group of PRPs that includes the Company entered into a consent decree
covering the site monitoring and leachate control phases of remediation. The
Company was a member of the group Coalition Undertaking Remediation Efforts
("CURE") which was responsible for constructing and operating the leachate

                                      51

                         SANTA FE ENERGY RESOURCES, INC.
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

treatment plant. This phase is now complete and the Company's share of costs
with respect to this phase was $1.6 million ($0.9 million after recoveries from
working interest participants in the unit in which the wastes were generated).
Another consent decree provides for the predesign, design and construction of a
gas plant to harness and market methane gas emissions. The Company is a member
of the New CURE group which is responsible for the gas plant construction and
operation and landfill cover. Currently, New CURE is in the design stage of the
gas plant. The Company's share of costs of this phase is expected to be $3.0
million (based on an agremeent with the other working interest participants in
the unit to assume $1.3 million of the original settlement amount, the Company's
net share of such costs is $1.7 million and such costs have been provided for in
the financial statements. The Company cannot currently estimate the cost of any
subsequent phases of work or final remediation which may be required by the EPA.
Another consent decree is currently being executed by the PRPs and will be
logged with the court for approval. This consent decree allows for the
settlement of the pending lawsuits against the municipalities and transporters
not named by the EPA. The settlement payment by such municipalities and
transporters totals approximately $70.0 million of which approximately $55.0
million will be credited against future expenses. The Company has entered into a
Joint Defense Agreement with the other PRPs to defend against a lawsuit filed
September 7, 1994 by ninety-five homeowners alleging, among other things,
nuisance, trespass, strict liability and infliction of emotional distress. At
this stage of the lawsuit the Company is not able to estimate costs or potential
liability.

     In 1989 Adobe received requests from the EPA for information pursuant to
Section 104(e) of the Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA") with respect to the D. L. Mud and Gulf Coast Vacuum
Services superfund sites located in Abbeville, Louisiana. With respect to the
Gulf Coast Site the Company has entered into a sharing agreement with other PRPs
to participate in the final remediation of the Gulf Coast site and a design plan
has been submitted and is awaiting approval by the EPA. The Company's share of
the remediation, which has been provided for in the financial statements, is
$277,000 and includes its proportionate share of those PRPs who do not have the
financial resources to provide their share of the work at the site. A former
site owner has already conducted remedial activities at the D. L. Mud Site under
a state agency agreement.

     On April 4, 1994 the Company received a request from the EPA for
information pursuant to Section 104(e) of CERCLA and a letter ordering the
Company and seven other PRPs to negotiate with the EPA regarding implementation
of a remedial plan for a site located in Santa Fe Springs, California. The
Company owned the property on which the site is located from 1921 to 1932.
During that time the property was leased to another company and in 1932 the
property was sold to that company. During the time the other company leased or
owned the property, hazardous wastes were allegedly disposed at the site. The
EPA estimates that the total past and future costs for remediation will
approximate $9.4 million. The Company filed its response to the Section 104(e)
order setting forth its position and defenses based on the fact that the other
company was the lessee and operator of the site during the time the Company was
the owner of the property. However, the Company has also given its Notice of
Intent to comply with the EPA's order to prepare a remediation design plan. Six
of the other PRPs have also notified the EPA of their intent to comply. The cost
of such a remediation design plan is estimated to be $1.0 million. To date there
has been no agreement on how to allocate costs among the PRPs. The Company has
provided for such costs in the financial statements, assuming that the costs
will be equally divided among the PRPs.

     On March 23, 1995 the Company and twelve other companies received notice
that they have been identified as PRPs by the California Department of Toxic
Substances Control (the "DTSC") as having generated and/or transported hazardous
waste to the Environmental Protection Corporation ("EPC") Eastside Landfill
during its fourteen-year operation from 1971 to 1985. EPC has since liquidated
all

                                      52

                         SANTA FE ENERGY RESOURCES, INC.
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

assets and placed the proceeds in trust for closure and post-closure activities.
However, these monies will not be sufficient to close the site. The PRPs have
entered into an enforceable agreement with the DTSC to characterize the
contamination at the site and prepare a focused remedial investigation and
feasibility study. The DTSC has agreed to implement reasonable measures to bring
new PRPs into the agreement. The DTSC will address subsequent phases of the
cleanup, including remedial design and implementation in a separate order
agreement. The cost of the remedial investigation and feasibility study is
estimated to be $1.0 million and the Company has provided $80,000 in the
financial statements as its estimated share of such costs. The costs of
subsequent phases cannot be estimated until the remedial investigation and
feasibility study is completed.

     There are certain other environmental matters pending, with respect to
which the Company is unable to estimate its exposure at this time.

  EMPLOYMENT AGREEMENTS

     The Company has entered into employment agreements with eight key
employees. The initial term of seven of the agreements expired on December 31,
1990 and, on January 1, 1991 and beginning on each January 1 thereafter, is
automatically extended for one-year periods, unless by September 30 of any year
the Company gives notice that the agreement will not be extended. The term of
the agreements is automatically extended for a minimum of 24 months following a
change of control. The consummation of the the Company's merger with Adobe in
1992 constituted a change of control as defined in the agreements. The initial
term of the other agreement will expire December 31, 1996 and beginning on each
January 1 thereafter, is automatically extended for one-year periods, unless by
September 30 of any year the Company gives notice that the agreement will not be
extended. The agreement is automatically extended for a minimum of 24 months
following a change of control.

     In the event that following a change of control employment is terminated
for reasons specified in the agreements, the employee would receive: (i) a lump
sum payment equal to two years' base salary; (ii) the maximum possible bonus
under the terms of the Company's incentive compensation plan; (iii) a lapse of
restrictions on any outstanding restricted stock grants and full payout of any
outstanding Phantom Units; (iv) cash payment for each outstanding stock option
equal to the amount by which the fair market value of the common stock exceeds
the exercise price of the option; and, (v) life, disability and health benefits
for a period of up to two years. In addition, payments and benefits under
certain employment agreements are subject to further limitations based on
certain provisions of the Internal Revenue Code.

  INTEREST RATE SWAPS

     The Company was a party to an interest rate swap with a bank with a
notional principal amount of $20.0 million which expired in April 1994. The
amount due the bank in accordance with the terms of the swap totalled $0.9
million and $0.2 million in 1993 and 1994, respectively.

  OPERATING LEASES

     The Company has noncancellable agreements with terms ranging from one to
ten years to lease office space and equipment. Minimum rental payments due under
the terms of these agreements are: 1996 -- $5.2 million, 1997 -- $4.9 million,
1998 -- $4.6 million, 1999 -- $2.8 million, 2000 -- $1.1 million and $0.8
million thereafter. Rental payments made under the terms of noncancellable
agreements totaled $5.5 million in 1993, $6.2 million in 1994 and $6.1 million
in 1995.

  OTHER MATTERS

     The Company has certain long-term contracts ranging up to twelve years for
the supply and transportation of approximately 20 million cubic feet per day of
natural gas to the Company's

                                      53

                         SANTA FE ENERGY RESOURCES, INC.
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

operations in Kern County, California. In the aggregate, these contracts involve
a minimum commitment on the part of the Company of approximately $10.2 million
per year (based on prices and transportation charges in effect for December
1995). In connection with the development of a gas field in Argentina in which
the Company has a 19.9% working interest, a gas contract for 106 million cubic
feet of gas per day with "take-or-pay" and "delivery-or-pay" obligations was
executed in 1994 with a gas distribution company.

     There are other claims and actions, including certain other environmental
matters, pending against the Company. In the opinion of management, the amounts,
if any, which may be awarded in connection with any of these claims and actions
could be significant to the results of operations of any period but would not be
material to the Company's consolidated financial position.

(12)  INCOME TAXES

     Through the date of the Spin-Off the taxable income or loss of the Company
was included in the consolidated federal income tax return filed by SFP. The
consolidated federal income tax returns of SFP have been examined through 1990
and all years prior to 1986 are closed. Issues relating to the open years are
being contested through various stages of administrative appeal. Accounts
Receivable at December 31, 1995 includes $12.0 million with respect to a refund
related to the audit of the years 1981 through 1985. The Company has filed
separate consolidated federal income tax returns for periods subsequent to the
Spin-Off. The consolidated returns of the Company through 1991 have been audited
and are closed.

     During 1989, the Company received a notice of deficiency for certain state
franchise tax returns filed for the years 1978 through 1983 as part of the
consolidated tax returns of SFP. The matter was contested by the Company and
resolved in 1994. The years 1984 through 1992 are currently being audited.

     With the Merger of Adobe the Company succeeded to a net operating loss
carryforward that is subject to Internal Revenue Code Section 382 limitations
which annually limit taxable income that can be offset by such losses. Certain
changes in the Company's shareholders in 1995 resulted in a second Section 382
limitation, the imposition of which is not expected to result in a limitation of
the Company's ability to use its net operating losses. Losses carrying forward
of $156.2 million will expire beginning in 1998.

     Pretax income from continuing operations for the years ended December 31,
1995, 1994 and 1993 was taxed under the following jurisdictions (in millions of
dollars):

                                         1995       1994       1993
                                       ---------  ---------  ---------
Domestic.............................       40.5       22.0     (120.9)
Foreign..............................       (4.2)       1.1      (29.3)
                                       ---------  ---------  ---------
                                            36.3       23.1     (150.2)
                                       ---------  ---------  ---------
                                       ---------  ---------  ---------

                                      54

                         SANTA FE ENERGY RESOURCES, INC.
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     The Company's income tax expense (benefit) for the years ended December 31,
1995, 1994 and 1993 consisted of (in millions of dollars):

                                         1995       1994       1993
                                       ---------  ---------  ---------
Current
     U.S. federal....................        1.5       (3.5)      (1.3)
     State...........................       (2.1)      (3.2)      (1.2)
     Foreign.........................        2.6        1.4        1.3
                                       ---------  ---------  ---------
                                             2.0       (5.3)      (1.2)
                                       ---------  ---------  ---------
Deferred
     U.S. federal....................       13.3        8.6      (65.6)
     U.S. federal tax rate change....     --         --            2.6
     State...........................       (0.6)       2.4       (8.0)
     Foreign.........................       (5.0)       0.3       (0.9)
                                       ---------  ---------  ---------
                                             7.7       11.3      (71.9)
                                       ---------  ---------  ---------
                                             9.7        6.0      (73.1)
                                       ---------  ---------  ---------
                                       ---------  ---------  ---------

     The Company's deferred income tax liabilities (assets) at December 31, 1995
and 1994 are composed of the following differences between financial and tax
reporting (in millions of dollars):

                                         1995       1994
                                       ---------  ---------
Capitalized costs and write-offs.....      138.5      113.8
Differences in Partnership basis.....     --            3.9
State deferred liability.............        7.6        8.2
Foreign deferred liability...........        9.1       14.1
                                       ---------  ---------
Gross deferred liabilities...........      155.2      140.0
                                       ---------  ---------
Accruals not currently deductible for
  tax purposes.......................      (16.7)     (14.1)
Alternative minimum tax
  carryforwards......................      (12.7)     (11.7)
Net operating loss carryforwards.....      (54.7)     (57.4)
Other................................       (7.1)      (0.5)
                                       ---------  ---------
Gross deferred assets................      (91.2)     (83.7)
                                       ---------  ---------
Deferred tax liability...............       64.0       56.3
                                       =========  =========

                                      55

                         SANTA FE ENERGY RESOURCES, INC.
          NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     A reconciliation of the Company's U.S. income tax expense (benefit)
computed by applying the statutory U.S. federal income tax rate to the Company's
income (loss) before income taxes for the years ended December 31, 1995, 1994
and 1993 is presented in the following table (in millions of dollars):

                                         1995       1994       1993
                                       ---------  ---------  ---------
U.S. federal income taxes (benefit)
  at statutory rate..................       12.7        8.1      (52.6)
Increase (reduction) resulting from:
  State income taxes, net of federal
     effect..........................        0.6        0.9       (1.0)
  Foreign income taxes in excess of
     (less than) U.S. rate...........       (0.9)       1.4       (0.8)
  U.S. tax on foreign reinvested
     earnings........................        0.8        1.2     --
  Effect of increase in statutory
     rate on deferred taxes..........     --         --            2.6
  Benefit of tax losses..............       (0.3)      (4.3)     (11.2)
  Prior period adjustments...........       (2.7)      (1.6)      (9.9)
  Other..............................       (0.5)       0.3       (0.2)
                                       ---------  ---------  ---------
                                             9.7        6.0      (73.1)
                                       =========  =========  =========


     The Company increased its deferred tax liability in 1993 as a result of
legislation enacted during 1993 increasing the corporate tax rate from 34% to
35% commencing in 1993.

(13)  FAIR VALUE OF FINANCIAL INSTRUMENTS

     SFAS No. 107 "Disclosure About Fair Value of Financial Instruments"
requires the disclosure, to the extent practicable, of the fair value of
financial instruments which are recognized or unrecognized in the balance sheet.
The fair value of the financial instruments disclosed herein is not
representative of the amount that could be realized or settled, nor does the
fair value amount consider the tax consequences, if any, of realization or
settlement. The following table reflects the financial instruments for which the
fair value differs from the carrying amount of such financial instrument in the
Company's December 31, 1995 and 1994 balance sheets (in millions of dollars):

                                             1995                   1994
                                      -------------------    -------------------
                                      CARRYING      FAIR     CARRYING      FAIR
                                       AMOUNT       VALUE     AMOUNT       VALUE
                                      --------      -----    --------      -----
Assets
     Note receivable from Hadson.....   --           --          2.4         2.4
Liabilities
     Long-Term Debt (including
        current
        portion).....................   344.4       378.5      354.3       355.6
     Convertible Preferred Stock.....    80.0        95.6       80.0        80.6
Shareholders' Equity
     $.732 Series A Convertible
        Preferred Stock..............    91.4       105.7       91.4        92.3

     The fair value of the Convertible Preferred Stock and the $.732 Series A
Convertible Preferred Stock is based on market prices. The fair value of the
Company's fixed-rate long-term debt is based on current borrowing rates
available for financings with similar terms and maturities. With respect to the
Company's floating-rate debt and the note receivable from Hadson, the carrying
amount approximates fair value.

                                       56

                         SANTA FE ENERGY RESOURCES, INC.
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     At December 31, 1995 the Company had open hedging contracts on both oil and
natural gas (see Note 11. Based on the year-end 1995 settlement prices of the
applicable NYMEX futures contracts or the estimated prices with respect to
certain other indices, the loss to the Company in 1996 with respect to such
hedges would be approximately $8.1 million. The actual gains or losses realized
by the Company from these hedges may vary significantly from the foregoing
amount due to the volatility of the futures markets and other indices.

                                       57

                         SANTA FE ENERGY RESOURCES, INC.
                           SUPPLEMENTAL INFORMATION TO
                  CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

OIL AND GAS RESERVES AND RELATED FINANCIAL DATA

     Information with respect to the Company's oil and gas producing activities
is presented in the following tables. Reserve quantities as well as certain
information regarding future production and discounted cash flows were
determined by independent petroleum consultants, Ryder Scott Company.

  OIL AND GAS RESERVES

     The following table sets forth the Company's net proved oil and gas
reserves at December 31, 1992, 1993, 1994 and 1995 and the changes in net proved
oil and gas reserves for the years ended December 31, 1993, 1994 and 1995.
<TABLE>
<CAPTION>
                                            CRUDE OIL AND LIQUIDS (MMBBLS)                      NATURAL GAS (BCF)
                                       ----------------------------------------   ---------------------------------------------
                                         U.S.     ARGENTINA   INDONESIA   TOTAL     U.S.     ARGENTINA   INDONESIA      TOTAL
                                       ---------  ---------   ---------   -----   ---------  ---------   ----------   ---------
Proved reserves at
<S>                                        <C>       <C>         <C>      <C>         <C>       <C>         <C>           <C>
 December 31, 1992...................      240.0      8.7         6.4     255.1       276.9       --         0.6          277.5
  Revisions to previous estimates....      (11.9)     0.5         0.6     (10.8)       26.6       --         0.1           26.7
  Improved recovery techniques.......       26.7       --          --      26.7          --       --          --             --
  Extensions, discoveries and other
    additions........................        3.4      0.5         2.3       6.2        29.5     26.4          --           55.9
  Purchases of minerals-in-place.....        3.3       --         0.7       4.0        10.6       --         0.1           10.7
  Sales of minerals in place.........       (8.7)      --          --      (8.7)      (47.4)      --          --          (47.4)
  Production.........................      (21.9)    (0.9)       (1.5)    (24.3)      (60.3)      --        (0.1)         (60.4)
                                       ---------  ---------   ---------   -----   ---------  ---------     -----      ---------
Proved reserves at
 December 31, 1993...................      230.9      8.8         8.5     248.2       235.9     26.4         0.7          263.0
  Revisions of previous estimates....       13.3      0.6         1.3      15.2        (2.7)      --          --           (2.7)
  Improved recovery techniques.......       13.9       --          --      13.9         0.9       --          --            0.9
  Extensions, discoveries and other
    additions........................        3.6      0.8         1.1       5.5        22.5     13.7          --           36.2
  Purchases of minerals-in-place.....        0.2       --          --       0.2         0.5       --          --            0.5
  Sales of minerals-in-place.........       (0.7)      --          --      (0.7)       (2.5)    (3.1)         --           (5.6)
  Production.........................      (21.0)    (0.9)       (2.1)    (24.0)      (49.8)      --        (0.1)         (49.9)
                                       ---------  ---------   ---------   -----   ---------  ---------     -----      ---------
Proved reserves at
 December 31, 1994...................      240.2      9.3         8.8     258.3       204.8     37.0         0.6          242.4
  Revisions of previous estimates....       16.4      1.4         0.4      18.2         1.0      1.3       --               2.3
  Improved recovery techniques.......       15.3      0.8       --         16.1      --          0.2       --               0.2
  Extensions, discoveries and other
    additions........................        1.7      2.2         0.5       4.4        36.4      0.5       --              36.9
  Purchases of minerals-in-place.....        6.3    --          --          6.3        18.0    --          --              18.0
  Production.........................      (21.3)    (0.9)       (1.9)    (24.1)      (50.3)    (4.3)       (0.1)         (54.7)
                                       ---------  ---------   ---------   -----   ---------  ---------     -----      ---------
Proved reserves at
 December 31, 1995...................      258.6     12.8         7.8     279.2       209.9     34.7         0.5          245.1
                                       =========  =========   =========   =====   =========  =========    ======      =========
</TABLE>

                                       58

                         SANTA FE ENERGY RESOURCES, INC.
                           SUPPLEMENTAL INFORMATION TO
          CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)

<TABLE>
<CAPTION>
                                            CRUDE OIL AND LIQUIDS (MMBBLS)                      NATURAL GAS (BCF)
                                       ----------------------------------------   ---------------------------------------------
                                         U.S.     ARGENTINA   INDONESIA   TOTAL     U.S.     ARGENTINA   INDONESIA      TOTAL
                                       ---------  ---------   ---------   -----   ---------  ---------   ----------   ---------
<S>                                        <C>        <C>         <C>     <C>         <C>       <C>          <C>          <C>
Proved developed reserves at
  December 31
     1992............................      194.6      5.6         6.4     206.6       250.2       --         0.6          250.8
     1993............................      178.8      5.5         6.7     191.0       206.0       --         0.7          206.7
     1994............................      181.3      6.1         7.1     194.5       178.2      1.3         0.6          180.1
     1995............................      206.5      7.1         6.0     219.6       170.2     33.3         0.5          204.0
</TABLE>

     Proved reserves are estimated quantities of crude oil and natural gas which
geological and engineering data indicate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are proved reserves which can be
expected to be recovered through existing wells with existing equipment and
operating methods.

     Indonesian reserves represent an entitlement to gross reserves in
accordance with a production sharing contract. These reserves include estimated
quantities allocable to the Company for recovery of operating costs as well as
quantities related to the Company's net equity share after recovery of costs.
Accordingly, these quantities are subject to fluctuations with an inverse
relationship to the price of oil. If oil prices increase, the reserve quantities
attributable to the recovery of operating costs decline. Although this reduction
would be offset partially by an increase in the net equity share, the overall
effect would be a reduction of reserves attributable to the Company. At December
31, 1995, the quantities include 0.4 million barrels which the Company is
contractually obligated to sell for $.20 per barrel.

     At December 31, 1993 the Company's reserves were 6.9 million barrels of
crude oil and liquids and 14.5 Bcf of natural gas lower than at December 31,
1992, reflecting the sale in 1993 of properties with reserves totalling 8.7
million barrels of crude oil and liquids and 47.4 Bcf of natural gas.

     The Company has certain commitments with respect to the delivery of natural
gas (see Note 11) which the Company believes it can fulfill from its proved
reserves and supply contracts with other companies.

     At December 31, 1995, 1.7 million barrels of crude oil reserves and 12.8
billion cubic feet of natural gas reserves were subject to a 90% net profits
interest held by Santa Fe Energy Trust.

                                       59

                         SANTA FE ENERGY RESOURCES, INC.
                           SUPPLEMENTAL INFORMATION TO
          CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)

  ESTIMATED PRESENT VALUE OF FUTURE NET CASH FLOWS

     Estimated future net cash flows from the Company's proved oil and gas
reserves at December 31, 1995, 1994 and 1993 are presented in the following
table (in millions of dollars, except as noted):
<TABLE>
<CAPTION>
                                          U.S.      ARGENTINA    INDONESIA     TOTAL
                                       ----------   ---------    ---------   ----------
<S>                                      <C>          <C>          <C>         <C>
1995
     Future cash inflows.............     4,191.2      244.7       137.4        4,573.3
     Future production costs.........    (1,852.8)    (103.0)      (63.0)      (2,018.8)
     Future development costs........      (282.8)     (36.1)       (6.1)        (325.0)
     Future income tax expenses......      (541.7)     (11.8)      (25.1)        (578.6)
                                       ----------   ---------    ---------   ----------
           Net future cash flows.....     1,513.9       93.8        43.2        1,650.9
     Discount at 10% for timing of
        cash flows...................      (672.0)     (35.7)      (13.0)        (720.7)
                                       ----------   ---------    ---------   ----------
     Present value of future net cash
        flows from
        proved reserves..............       841.9       58.1        30.2          930.2
                                       ==========   =========    =========   ==========
     Present value of pretax future
        net cash flows from proved
        reserves.....................     1,143.1       65.4        48.7        1,257.2
                                       ==========   =========    =========   ==========
     Average sales prices
           Oil ($/Barrel)............       14.75      15.66       17.51
           Natural gas ($/Mcf).......        1.88       1.27        1.03
1994
     Future cash inflows.............     3,488.8      176.9       134.9        3,800.6
     Future production costs.........    (1,614.6)     (89.6)      (69.4)      (1,773.6)
     Future development costs........      (263.7)     (32.3)       (6.2)        (302.2)
     Future income tax expenses......      (385.2)      (3.7)      (20.0)        (408.9)
                                       ----------   ---------    ---------   ----------
           Net future cash flows.....     1,225.3       51.3        39.3        1,315.9
     Discount at 10% for timing of
        cash flows...................      (544.9)     (20.1)      (11.0)        (576.0)
                                       ----------   ---------    ---------   ----------
     Present value of future net cash
        flows from
        proved reserves..............       680.4       31.2        28.3          739.9
                                       ==========   =========    =========   ==========
     Present value of pretax future
        net cash flows from proved
        reserves.....................       894.3       33.5        43.0          970.8
                                       ==========   =========    =========   ==========
     Average sales prices
           Oil ($/Barrel)............       13.18      14.06       15.21
           Natural gas ($/Mcf).......        1.63       1.25        0.97
1993
     Future cash inflows.............     2,654.9      117.9       115.6        2,888.4
     Future production costs.........    (1,547.2)     (65.9)      (78.7)      (1,691.8)
     Future development costs........      (216.7)     (32.4)       (8.9)        (258.0)
     Future income tax expenses......      (100.5)     --           (6.9)        (107.4)
                                       ----------   ---------    ---------   ----------
           Net future cash flows.....       790.5       19.6        21.1          831.2
     Discount at 10% for timing of
        cash flows...................      (308.5)     (12.1)       (8.2)        (328.8)
                                       ----------   ---------    ---------   ----------
     Present value of future net cash
        flows from
        proved reserves..............       482.0        7.5        12.9          502.4
                                       ==========   =========    =========   ==========
     Present value of pretax future
        net cash flows from proved
        reserves.....................       543.2        7.5        17.1          567.8
                                       ==========   =========    =========   ==========
     Average sales prices
           Oil ($/Barrel)............         9.10       9.74       13.50
           Natural gas ($/Mcf).......         2.28       1.23        0.97

                                       60
1995
  Balance at beginning of year.......       680.4       31.2        28.3          739.9
                                       ----------   ---------    ---------   ----------
  Increase (decrease) due to:
     Sales of oil and gas, net of
        production costs of $171.7
        million......................      (244.7)      (11.8)        (13.2)    (269.7)
     Net changes in prices and
        production costs.............       178.2        13.9           9.1      201.2
     Extensions, discoveries and
        improved recovery............       110.3         4.6           4.2      119.1
     Purchases of
        minerals-in-place............        56.6        --            --         56.6
     Development costs incurred......       145.4        13.7          11.3      170.4
     Changes in estimated volumes....        19.9         9.6           0.3       29.8
     Changes in estimated development
        costs........................      (105.6)       (2.4)        (10.2)    (118.2)
     Interest factor -- accretion of
        discount.....................        88.7         4.4           4.2       97.3
     Income taxes....................       (87.3)       (5.1)         (3.8)     (96.2)
                                       ----------   ---------     ---------  ----------
                                            161.5        26.9           1.9      190.3
                                       ----------   ---------     ---------  ----------
                                            841.9        58.1          30.2      930.2
                                       ==========   =========     =========  ==========
1994
  Balance at beginning of year.......       482.0         7.5          12.9      502.4
                                       ----------   ---------    ---------   ----------
  Increase (decrease) due to:
     Sales of oil and gas, net of
        production costs of $170.9
        million......................      (196.0)       (7.3)        (17.2)    (220.5)
     Net changes in prices and
        production costs.............       389.0        21.1          19.6      429.7
     Extensions, discoveries and
        improved recovery............        78.8         7.4          10.4       96.6
     Purchases of
        minerals-in-place............         1.2         --            --         1.2
     Sales of minerals-in-place......        (8.9)       (0.4)          --        (9.3)
     Development costs incurred......        81.7        13.0           9.3      104.0
     Changes in estimated volumes....        18.5        (2.6)          8.3       24.2
     Changes in estimated development
        costs........................       (66.6)       (7.3)         (6.5)     (80.4)
     Interest factor -- accretion of
        discount.....................        53.3         2.0           2.0       57.3
     Income taxes....................      (152.6)       (2.2)        (10.5)    (165.3)
                                       ----------   ---------    ---------   ----------
                                            198.4        23.7          15.4      237.5
                                       ----------   ---------    ---------   ----------
                                            680.4        31.2          28.3      739.9
                                       ==========   =========    =========   ==========

                                       61
1993
  Balance at beginning of year.......       697.6        22.3          13.6      733.5
                                       ----------   ---------    ---------   ----------
  Increase (decrease) due to:
     Sales of oil and gas, net of
        production costs of $189.5
        million......................      (230.1)       (7.3)        (10.0)    (247.4)
     Net changes in prices and
        production costs.............      (325.1)       (7.7)          1.7     (331.1)
     Extensions, discoveries and
        improved recovery............        94.8        14.8           7.0      116.6
     Purchases of
        minerals-in-place............        21.6         --            2.1       23.7
     Sales of minerals-in-place......       (84.7)        --            --       (84.7)
     Development costs incurred......        50.0         5.1           --        55.1
     Changes in estimated volumes....        28.3         1.5           1.8       31.6
     Changes in estimated development
        costs........................        25.6       (24.1)         (8.9)      (7.4)
     Interest factor -- accretion of
        discount.....................        87.1         2.3           2.1       91.5
     Income taxes....................       112.0         0.6           3.5      116.1
     Other...........................         4.9         --            --         4.9
                                       ----------   ---------     ---------   ----------
                                           (215.6)      (14.8)         (0.7)    (231.1)
                                       ----------   ---------     ---------   ----------
                                            482.0         7.5          12.9      502.4
                                       ==========   =========     =========   ==========
</TABLE>

     Estimated future cash flows represent an estimate of future net cash flows
from the production of proved reserves using estimated sales prices and
estimates of the production costs, ad valorem and production taxes, and future
development costs necessary to produce such reserves. No deduction has been made
for depletion, depreciation or any indirect costs such as general corporate
overhead or interest expense.

     The sales prices used in the calculation of estimated future net cash flows
are based on the prices in effect at year end. Such prices have been held
constant except for known and determinable escalations.

     Operating costs and ad valorem and production taxes are estimated based on
current costs with respect to producing oil and gas properties. Future
development costs are based on the best estimate of such costs assuming current
economic and operating conditions.

     Income tax expense is computed based on applying the appropriate statutory
tax rate to the excess of future cash inflows less future production and
development costs over the current tax basis of the properties involved. While
applicable investment tax credits and other permanent differences are considered
in computing taxes, no recognition is given to tax benefits applicable to future
exploration costs or the activities of the Company that are unrelated to oil and
gas producing activities.

     The information presented with respect to estimated future net revenues and
cash flows and the present value thereof is not intended to represent the fair
value of oil and gas reserves. Actual future sales prices and production and
development costs may vary significantly from those in effect at year-end and
actual future production may not occur in the periods or amounts projected. This
information is presented to allow a reasonable comparison of reserve values
prepared using standardized measurement criteria and should be used only for
that purpose.

                                       62


                       SANTA FE ENERGY RESOURCES, INC.
                         SUPPLEMENTAL INFORMATION TO
          CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)

  COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES

     The following table includes all costs incurred, whether capitalized or
charged to expense at the time incurred (in millions of dollars):
<TABLE>
<CAPTION>
                                                                                 OTHER
                                         U.S.       ARGENTINA     INDONESIA     FOREIGN      TOTAL
                                       ----------   ---------    ---------   ----------   ----------
1995
  Property acquisition costs
<S>                                         <C>       <C>            <C>          <C>         <C>
     Unproved........................       13.0      --              0.7          0.1         13.8
     Proved..........................       33.8      --            --            --           33.8
  Exploration costs..................       27.7        1.2           7.7          7.2         43.8
  Development costs..................      111.5       13.7          11.3          0.5        137.0
                                       ----------   ---------    ---------   ----------   ----------
                                           186.0       14.9          19.7          7.8        228.4
                                       ==========   =========    =========   ==========   ==========
1994
  Property acquisition costs
     Unproved........................        4.5        0.1           0.6          0.2          5.4
     Proved..........................        1.8        0.3         --            --            2.1
  Exploration costs..................       19.3        1.2           7.5          6.8         34.8
  Development costs..................       81.7       13.0           9.3          0.1        104.1
                                       ----------   ---------    ---------   ----------    ----------
                                           107.3       14.6          17.4          7.1        146.4
                                       ==========   =========    =========   ==========    ----------
1993
  Property acquisition costs
     Unproved........................        6.4      --              1.8          3.8         12.0
     Proved..........................       29.7      --              2.9         --           32.6
     Other...........................        0.8      --            --            --            0.8
  Exploration costs..................       20.9        0.7           5.2         11.7         38.5
  Development costs..................       85.3        7.3           7.6         --          100.2
                                       ----------   ---------    ---------   ----------   ----------
                                           143.1        8.0          17.5         15.5        184.1
                                       ==========   =========    =========   ==========   ==========

</TABLE>
                                      63

                         SANTA FE ENERGY RESOURCES, INC.
                           SUPPLEMENTAL INFORMATION TO
          CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)

  CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES

     The following table sets forth information concerning capitalized costs at
December 31, 1995 and 1994 related to the Company's oil and gas operations (in
millions of dollars):
<TABLE>
<CAPTION>
                                                                  1995                                      1994
                                       ----------------------------------------------------------   --------------------
                                                                               OTHER
                                         U.S.      ARGENTINA     INDONESIA    FOREIGN     TOTAL      U.S.      ARGENTINA
                                       ---------   ----------    ---------    -------   ---------   -------    ---------
<S>                                     <C>           <C>          <C>          <C>      <C>        <C>          <C>
Oil and gas properties
    Unproved.........................       41.7        4.5         12.0         3.0         61.2      41.0        0.3
    Proved...........................    2,090.6       70.8         99.1         1.8      2,262.3   1,924.5       61.4
    Other............................       12.8      --           --           --           12.8      12.7      --
Accumulated amortization of unproved
  properties.........................      (12.8)      (2.4)        (3.8)       (1.8)       (20.8)    (12.7)      (0.3)
Accumulated depletion, depreciation
  and impairment of proved
  properties.........................   (1,385.9)     (15.9)       (39.7)       --       (1,441.5)  (1,247.4)    (11.4)
Accumulated depreciation of other oil
  and gas properties                        (5.3)     --           --           --           (5.3)     (4.3)      (0.4)
                                       ---------      -----      ---------    -------   ---------   -------    ---------
                                           741.1       57.0         67.6         3.0        868.7     713.8       49.6
                                       =========      =====      =========    =======   =========   =======    =========

                                                     OTHER
                                       INDONESIA    FOREIGN     TOTAL
                                       ---------    -------   ---------
Oil and gas properties
    Unproved.........................     11.3         9.7         62.3
    Proved...........................     83.2         1.9      2,071.0
    Other............................    --           --           12.7
Accumulated amortization of unproved
  properties.........................     (2.6)       (9.7)       (25.3)
Accumulated depletion, depreciation
  and impairment of proved
  properties.........................    (30.9)       (0.3)    (1,290.0)
Accumulated depreciation of other oil
  and gas properties                     --           (0.1)        (4.8)
                                       ---------    -------   ---------
                                          61.0         1.5        825.9
                                       =========    =======   =========
</TABLE>

                                      64

                         SANTA FE ENERGY RESOURCES, INC.
                           SUPPLEMENTAL INFORMATION TO
          CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)

  RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES

     The following table sets forth the Company's results of operations from oil
and gas producing activities for the years ended December 31, 1995, 1994 and
1993 (in millions of dollars):

<TABLE>
<CAPTION>
                                                                             OTHER
                                         U.S.     ARGENTINA    INDONESIA    FOREIGN     TOTAL
                                        ------    ---------    ---------    -------   ---------
1995
<S>                                      <C>         <C>          <C>         <C>         <C>
  Revenues...........................    391.2       19.2         31.6        --          442.0
  Production costs
     Production and operating
        costs........................   (129.7)      (7.1)       (17.7)       (0.4)      (154.9)
     Taxes (other than income).......    (16.5)      (0.3)       --           --          (16.8)
  Exploration, including dry hole
     costs...........................    (13.6)      (1.2)        (3.1)       (5.5)       (23.4)
  Depletion, depreciation,
     amortization and impairments....   (143.3)      (7.0)       (10.0)       (0.5)      (160.8)
  Gain (loss) on disposition of
     properties......................     (0.2)     --           --           (0.1)        (0.3)
                                        ------    ---------    ---------    -------   ---------
                                          87.9        3.6          0.8        (6.5)        85.8
  Income taxes.......................    (34.8)      (1.1)        (1.2)       --          (37.1)
                                        ------    ---------    ---------    -------   ---------
                                          53.1        2.5         (0.4)       (6.5)        48.7
                                        ======    =========    =========    =======   =========
1994
  Revenues...........................    346.7       12.9         31.8          --        391.4
  Production costs
     Production and operating
        costs........................   (129.7)      (5.5)       (14.6)       (0.2)      (150.0)
     Taxes (other than income).......    (21.0)      (0.1)       --           --          (21.1)
  Exploration, including dry hole
     costs...........................    (14.0)      (1.2)        (1.4)       (3.8)       (20.4)
  Depletion, depreciation,
     amortization and impairments....    (99.9)      (3.8)        (9.7)       (6.3)      (119.7)
  Gain (loss) on disposition of
     properties......................      6.8        0.8           --          --          7.6
                                        ------    ---------    ---------    -------   ---------
                                          88.9        3.1          6.1       (10.3)        87.8
  Income taxes.......................    (31.0)      (0.9)        (2.6)         --        (34.5)
                                        ------    ---------    ---------    -------   ---------
                                          57.9        2.2          3.5       (10.3)        53.3
                                        ======    =========    =========    =======   =========
1993
  Revenues...........................    401.2       12.5         23.2        --          436.9
  Production costs
     Production and operating
        costs........................   (145.5)      (5.1)       (13.2)       --         (163.8)
     Taxes (other than income).......    (21.4)      (0.1)       --           --          (21.5)
  Oil and gas systems and
     pipelines.......................     (4.2)     --           --           --           (4.2)
  Exploration, including dry hole
     costs...........................    (16.4)      (0.7)        (2.2)      (11.7)       (31.0)
  Depletion, depreciation,
     amortization and impairments....   (218.8)      (3.6)       (21.2)       (6.7)      (250.3)
  Restructuring charges..............    (27.8)     --           --           --          (27.8)
  Gain (loss) on disposition of
     properties......................     (0.7)     --           --           --           (0.7)
                                        ------    ---------    ---------    -------   ---------
                                         (33.6)       3.0        (13.4)      (18.4)       (62.4)
  Income taxes.......................     24.1       (0.9)         1.9        --           25.1
                                        ------    ---------    ---------    -------   ---------
                                          (9.5)       2.1        (11.5)      (18.4)       (37.3)
                                        ======    =========    =========    =======   =========
</TABLE>
     Income taxes are computed by applying the appropriate statutory rate to the
results of operations before income taxes. Applicable tax credits and allowances
related to oil and gas producing activities have been taken into account in
computing income tax expenses. No deduction has been made for indirect cost such
as corporate overhead or interest expense.

                                      65

                       SANTA FE ENERGY RESOURCES, INC.
                         SUPPLEMENTAL INFORMATION TO
          CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)

SUMMARIZED QUARTERLY FINANCIAL DATA
<TABLE>
<CAPTION>
                                        1 QTR      2 QTR      3 QTR      4 QTR      YEAR
                                        ------     ------     ------     ------     -----
                 (IN MILLIONS OF DOLLARS EXCEPT PER SHARE DATA)
  1995
<S>                                       <C>       <C>        <C>        <C>       <C>
     Revenues........................     98.6      109.7      111.1      122.6     442.0
     Gross profit (a)................     18.4       29.4       26.9        6.1      80.8
     Income (loss) from operations...     12.5       22.5       19.8       (0.9)(b)  53.9(b)
     Net income (loss)...............      3.6        7.6        7.0        8.4      26.6
     Earnings (loss) attributable to
       common shares.................     (0.1)       3.9        3.3        4.7      11.8
     Earnings (loss) attributable to
       common shares per share.......     --         0.04       0.04       0.05      0.13
     Average shares outstanding
       (millions)....................     90.1       90.3       90.3       90.3      90.2

  1994
     Revenues........................     90.3       99.7      103.6       97.8     391.4
     Gross profit (a)................      7.6       19.7       25.6       22.6      75.5
     Income (loss) from operations...     --         12.8       19.1       16.3      48.2
     Net income (loss)...............     (2.5)       4.1       11.0        4.5      17.1
     Earnings (loss) attributable to
       common shares.................     (4.3)       1.6        7.3        0.8       5.4
     Earnings (loss) attributable to
       common shares per share.......    (0.05)      0.02       0.08       0.01      0.06
     Average shares outstanding
       (millions)....................     89.9       90.0       90.0       90.0      89.9
</TABLE>

------------
  (a) Revenues less operating expenses other than general and administrative.

  (b) Includes charges of $30.2 million for impairment of oil and gas
      properties.

                                       66

                                  SIGNATURES

     PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.

                                          SANTA FE ENERGY RESOURCES, INC.

                                          By ____/s/__R. GRAHAM WHALING_______
                                          ------------------------------------
                                                    R. GRAHAM WHALING
                                                SENIOR VICE PRESIDENT AND
                                                 CHIEF FINANCIAL OFFICER
                                                 (PRINCIPAL FINANCIAL AND
                                                   ACCOUNTING OFFICER)

Dated:  February 29, 1996

     PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT
AND IN THE CAPACITIES AND ON THE DATE INDICATED.

                 SIGNATURE AND TITLE
                 -------------------
               JAMES L. PAYNE, Chairman
             of the Board, President and
         Chief Executive Officer and Director
            (PRINCIPAL EXECUTIVE OFFICER)

              R. GRAHAM WHALING, Senior
                    Vice President
             and Chief Financial Officer
     (PRINCIPAL FINANCIAL AND ACCOUNTING OFFICER)

               DIRECTORS
               ---------
          William E. Greehey
           Melvyn N. Klein
           Robert D. Krebs
           Allan V. Martini
          Michael A. Morphy                         By: /s/R. GRAHAM WHALING
          Reuben F. Richards                           R. GRAHAM WHALING
           Marc J. Shapiro                         SENIOR VICE PRESIDENT AND
            Robert F. Vagt                          CHIEF FINANCIAL OFFICER
          Kathryn D. Wriston                           ATTORNEY IN FACT

Dated:  February 29, 1996

                                       67

                         SANTA FE ENERGY RESOURCES, INC.
               SCHEDULE VIII -- VALUATION AND QUALIFYING ACCOUNTS
                       THREE YEARS ENDED DECEMBER 31, 1995
                            (IN MILLIONS OF DOLLARS)
================================================================================
                                        1995       1994       1993
--------------------------------------------------------------------------------
Accounts receivable
     Balance at the beginning of
       period........................     3.1        6.3        5.0
           Charge (credit) to
             income..................     --         0.6        --
           Net amounts written off...    (1.1)      (3.8)      (0.1)
           Other(a)..................     --         --         1.4
                                        -----      -----      -----
     Balance at the end of period....     2.0        3.1        6.3
                                        =====      =====      =====
------------
  (a) Represents valuation accounts related to accounts receivable acquired in
      merger with Adobe Resources Corporation in 1992.

                                       68

                              INDEX OF EXHIBITS

A.  EXHIBITS

   EXHIBIT
    NUMBER                                                  DESCRIPTION

     3(a)      Restated Certificate of Incorporation (incorporated by
               reference to Exhibit 3.1 of the Form S-2 Registration Statement
               of Santa Fe Energy Resources, Inc. ("SFER, Inc.") Commission File
               No. 33-32831).

     3(b)      Bylaws, as amended (incorporated by reference to Exhibit 3(b)
               to SFER, Inc.'s Annual Report on Form 10-K for the year ended
               December 31, 1992).

     4(a)      Form of Certificate of Designation, Rights and Preferences of
               the 7% Convertible Preferred Stock of Santa Fe Energy Resources,
               Inc. (incorporated by reference to Exhibit 3(b) of the Form S-4
               Registration Statement of SFER, Inc., Commission File No.
               33-45043).

     4(b)      Note Agreement dated as of March 31, 1990, by and among Santa
               Fe Energy Resources, Inc. and various institutional investors
               relating to the issuance of $365,000,000 of Senior Notes maturing
               1993-2005, as amended (incorporated by reference to Exhibit 4(b)
               to SFER, Inc.'s Annual Report on Form 10-K for the year ended
               December 31, 1990).

     4(c)      Amendment dated as of November 1, 1992, to Note Agreement
               dated as of March 30, 1990, by and among Santa Fe Energy
               Resources, Inc. and various institutional investors, relating to
               the issuance of $365,000,000 of Senior Notes maturing 1993 to
               2005, as amended (incorporated by reference to Exhibit 4(c) to
               SFER, Inc.'s Annual Report on Form 10-K for the year ended
               December 31, 1992).

     4(d)      Amendment dated as of December 31, 1993, to Note Agreement
               dated as of March 30, 1990, by and among Santa Fe Energy
               Resources, Inc. and various institutional investors, relating to
               the issuance of $365,000,000 of Senior Notes maturing 1993 to
               2005, as amended (incorporated by reference to Exhibit 4(d) to
               SFER Inc.'s Annual Report on Form 10-K for the year ended
               December 31, 1993).

     4(e)      Form of Certificate of Designation of the Dividend Enhanced
               Convertible Stock, $.732 Series A Convertible Preferred Stock of
               Santa Fe Energy Resources, Inc. (incorporated by reference to
               Exhibit 4.3 of the Form S-3 Registration Statement of SFER, Inc.,
               Commission File No. 33-52849).

     4(f)      Form of Indenture dated as of May 25, 1994 and Form of Debenture
               relating to Santa Fe Energy Resources, Inc. 11% Senior
               Subordinated Debentures Due 2004 (incorporated by reference to
               Exhibit 4.1 of the Form S-3 Registration Statement of SFER, Inc.,
               Commission File No. 33-52849).

     10(a)     Agreement for the Allocation of the Consolidated Federal Income
               Tax Liability Among the Members of the Santa Fe Pacific
               Corporation ("SFP") Affiliated Group, as amended, dated December
               23, 1983 (incorporated by reference to Exhibit 10.8 of the Form
               S-2 Registration Statement of SFER, Inc. Commission File No.
               33-32831).

     *10(b)    Santa Fe Energy Resources, Inc. Incentive Compensation Plan, as
               amended.

     *10(c)    Santa Fe Energy Resources, Inc. 1990 Incentive Stock Compensation
               Plan, Second Amendment and Restatement.

     10(d)     Example of employment agreements entered into with executive
               officers of SFER, Inc (incorporated by reference to Exhibit 10(f)
               to SFER, Inc.'s Annual Report on Form 10-K for the year ended
               December 31, 1990).

     10(e)     Example of Indemnification Agreement with SFER, Inc. directors
               and officers (incorporated by reference to Exhibit 10(g) to SFER,
               Inc.'s Annual Report on Form 10-K for the year ended December 31,
               1990).

     10(f)     Spin Off Tax Indemnification Agreement between SFER, Inc. and SFP
               (incorporated by reference to Exhibit 10(h) to SFER, Inc.'s
               Annual Report on Form 10-K for the year ended December 31, 1990).

                                       69

     10(g)     Agreement Concerning Taxes among the Company, certain
               subsidiaries of the Company and SFP (incorporated by reference to
               Exhibit 10(i) to SFER, Inc.'s Annual Report on Form 10-K for the
               year ended December 31, 1990).

     10(h)     Santa Fe Energy Resources Supplemental Retirement Plan, effective
               as of December 4, 1990 (incorporated by reference to Exhibit
               10(l) to SFER, Inc.'s Annual Report on Form 10-K for the year
               ended December 31, 1990).

     10(i)     Santa Fe Energy Resources, Inc. Deferred Compensation Plan,
               effective as of January 1, 1991 as amended and restated,
               effective February 1, 1994 (incorporated by reference to Exhibit
               10(p) to SFER Inc.'s Annual Report on Form 10-K for the year
               ended December 31, 1993).

     10(j)     Stock Ownership and Registration Rights Agreement dated December
               10, 1991, by, between and among SFER, Inc., Minorco, and Minorco
               (U.S.A.) Inc. (incorporated by reference to Exhibit 10(r) of the
               Form S-4 Registration Statement of SFER, Inc., Commission File
               No. 33-45043).

     10(k)     Gas Marketing Agreement, dated as of December 14, 1993, between
               Santa Fe Energy Resources, Inc., Santa Fe Energy Operating
               Partners, L.P. and Adobe Gas Pipeline Company (incorporated by
               reference to Exhibit 10(t) to SFER Inc.'s Annual Report on Form
               10-K for the year ended December 31, 1993).

     10(l)     Second Amended and Restated Revolving Credit Agreement dated as
               of April 1, 1995 among Santa Fe Energy Resources, Inc., the banks
               signatory thereto, and Texas Commerce Bank National Association
               as Co-Agent and Administrative Agent and NationsBank of Texas,
               N.A. as Co-Agent (incorporated by reference to Exhibit 10(a) to
               SFER Inc.'s Quarterly Report on Form 10-Q for the quarter ended
               March 31, 1995).

     10(m)     Letter of Credit Agreement dated as of April 1, 1995 among Santa
               Fe Energy Resources, Inc., the banks signatory thereto, and Texas
               Commerce Bank National Association as Co-Agent and Administrative
               Agent and NationsBank of Texas, N.A. as Co-Agent (incorporated by
               reference to Exhibit 10(b) to SFER Inc.'s Quarterly Report on
               Form 10-Q for the quarter ended March 31, 1995).

     10(n)     Securities Purchase Agreement among Santa Fe Energy Resources,
               Inc., as Seller, and LG&E Energy Corp. and Carousel Acquisition
               Corporation, as Buyers, dated February 10, 1995.

     *10(o)    Agreement Regarding Shelf Registration Statement dated March 24,
               1995 between Santa Fe Energy Resources, Inc. and HC Associates,
               GKH Partners, L.P., GKH Investments, L.P., Ernest H. Cockrell
               Texas Testamentary Trust and Carol Cockrell Jennings Texas
               Testamentary Trust.

     *21       Subsidiaries of the registrant.

     *23(a)    Consent of Independent Accountants with respect to Registration
               Statements on Form S-8 (Nos. 33-37175, 33-44541, 33-44542,
               33-58613, 33-59253 and 33-59255) and Form S-3 (No. 333-00753).

     *23(b)    Consent of Ryder Scott Company with respect to Registration
               Statements on Form S-8 (Nos. 33-37175, 33-44541 33-44542,
               33-58613, 33-59253 and 33-59255) and Form S-3 (No. 333-00753).

     *24       Powers of Attorney

------------
* Included in this report.

     B.  REPORTS ON FORM 8-K.
         February 6, 1996
                                       70