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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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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, 1996

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

COMMISSION FILE NUMBER 1-7667
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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
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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 3, 1997 was approximately $1,357,000,000.

Shares of Common Stock outstanding at February 3, 1997 -- 91,068,871.

DOCUMENTS INCORPORATED BY REFERENCE:

NONE

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TABLE OF CONTENTS

PAGE
PART I
Items 1 and 2. Business and Properties .................................... 1
General ................................................................... 1
Santa Fe Excluding Monterey ............................................... 2
Reserves .................................................................. 3
Production and Development Activities ..................................... 3
Exploration Activities .................................................... 7
Drilling Activities ....................................................... 10
Producing Wells ........................................................... 10
Domestic Acreage .......................................................... 11
Foreign Acreage ........................................................... 11
Selected Financial and Operating Data ..................................... 12
Santa Fe Energy Trust ..................................................... 14
Monterey Resources, Inc. .................................................. 14
Reserves .................................................................. 15
Development Activities .................................................... 16
Selected Financial and Operating Data ..................................... 18
Santa Fe Consolidated ..................................................... 19
Reserves .................................................................. 20
Drilling Activities ....................................................... 21
Producing Wells ........................................................... 21
Domestic Acreage .......................................................... 22
Foreign Acreage ........................................................... 22
Current Markets for Oil and Gas ........................................... 22
Other Business Matters .................................................... 23

Item 3. Legal Proceedings ................................................. 28

Item 4. Submission of Matters to Vote of Security Holders ................. 28

PART II

Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters ....................................................... 29

Item 6. Selected Financial Data ........................................... 30

Item 7. Management's Discussion and Analysis of Financial
Condition and Results Of Operations ....................................... 32

Item 8. Financial Statements and Supplementary Data ....................... 42

Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure .................................... 42

PART III

Item 10. Directors and Executive Officers of the Registrant ............... 42

Item 11. Executive Compensation ........................................... 42

Item 12. Security Ownership of Certain Beneficial Owners
and Management ............................................................ 42

Item 13. Certain Relationships and Related Transactions ................... 42

PART IV

Item 14. Exhibits, Financial Statement Schedules and

Reports on Form 8-K ....................................................... 62

Signatures ................................................................ 99

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") is engaged in the
exploration, development and production of crude oil and natural gas in the
continental and offshore United States and in certain international areas. In
September 1996, Santa Fe announced its intention to separate its heavy oil
operations in California (the "Western Division") from its other domestic and
international operations located in the central United States, the Gulf of
Mexico and abroad. The initial phase of the separation was completed by the end
of November 1996 and involved: (i) the contribution of substantially all of the
assets and operations of the Western Division, which include Santa Fe's
interests in the Midway-Sunset, South Belridge, Coalinga and Kern River oil
fields, to Monterey Resources, Inc. ("Monterey"), a newly-formed subsidiary,
and the assumption by Monterey of all the liabilities and obligations associated
with the Western Division, including $245 million of senior indebtedness; and
(ii) the initial public offering of approximately 17% of the common stock of
Monterey.

At December 31, 1996, Santa Fe owned approximately 83% of the Monterey's
outstanding common stock. As the final phase of the separation, Santa Fe intends
to distribute pro rata to its common shareholders all of these shares of
Monterey's common stock by means of a tax-free distribution (the "Proposed Spin
Off"). Santa Fe's final determination to proceed will require approval of the
Proposed Spin Off by Santa Fe's Board of Directors. Such declaration is not
expected to be made until certain conditions, many of which are beyond the
control of Santa Fe, are satisfied, including: (i) receipt by Santa Fe of a
ruling from the Internal Revenue Service as to the tax-free nature of the
Proposed Spin Off; (ii) approval of the Proposed Spin Off by Santa Fe's
shareholders; and (iii) the absence of any future change in market or economic
conditions (including developments in the capital markets) or Santa Fe's or
Monterey's business and financial condition that causes Santa Fe's Board of
Directors to conclude that the Proposed Spin Off is not in the best interests of
Santa Fe's shareholders. It is not anticipated that the Proposed Spin Off will
occur prior to July 1997.

Following the Proposed Spin Off, Santa Fe's domestic activities will be
focused in the Permian Basin in Texas and New Mexico and in the Gulf of Mexico,
and its international operations will be focused primarily in Southeast Asia,
South America and West Africa. Monterey's operations are focused in the San
Joaquin Valley of California. Following is a description of the business and
properties of (i) Santa Fe excluding Monterey; (ii) Monterey; and (iii) Santa Fe
consolidated with Monterey.

SANTA FE EXCLUDING MONTEREY

After the Proposed Spin Off Santa Fe will have a balanced base of reserves
with significant development potential, an active exploration program in the
Gulf of Mexico and internationally and a capital structure with low leverage.
The company's production will be approximately one-half light oil and one-half
natural gas. Domestically, the Central Division will focus on long-lived
enhanced recovery properties in the Permian Basin of west Texas and light oil
and natural gas properties in southeastern New Mexico. The Gulf Division is
continuing its exploration and development program in the shallow waters of the
Continental Shelf and is expanding into the deeper water "flex trend" where
the company acquired 89,000 net undeveloped acres in 1996. Internationally,
development activities will focus on bringing discoveries in Indonesia and Gabon
on production in 1997 and 1998 as well as continuing development of its
producing fields in Indonesia and Argentina. Exploration activities will focus
on the company's inventory of prospects in Southeast Asia, West Africa and South
America.

At December 31, 1996 worldwide proved oil and gas reserves totalled 124.3
MMBOE (83.1 MMBbls of crude oil and liquids and 247.2 Bcf of natural gas) of
which approximately 77% were domestic and 23% were foreign. Production in 1996
averaged 27.5 MBbls of crude oil and liquids and 163.4 MMcf of natural gas per
day, a 13% increase from 1995, reflecting a 3.0 MBbl per day increase in crude
oil and liquids production and an 18.7 MMcf per day increase in natural gas
production.

Capital expenditures for exploration and development projects totalled
approximately $181 million in 1996 and are expected to be approximately $214
million in 1997. In 1996 approximately 75% of such expenditures were domestic.
In 1997 International Division expenditures will increase to approximately 35%
of the total primarily due to increased development expenditures in Indonesia.
In 1996 the company participated in the drilling of 75 development wells (48
domestic and 27 international) and 33 exploratory wells (24 domestic and 9
international) of which, 19 exploratory wells and 66 development wells were
successfully completed. In 1997 the company expects to participate in 145
development wells (94 domestic and 51 international) and 47 exploratory wells
(37 domestic and 10 international).

RESERVES

The following tables set forth information regarding changes in the
company's estimates of proved net reserves from January 1, 1994 to December 31,
1996 and the balance of the company's estimated proved developed reserves at
December 31 of each of the years 1993 through 1996.

INCREASES (DECREASES)
-------------------------------------------------------------
BALANCE NET
AT REVISIONS EXTENSIONS, PURCHASES BALANCE
BEGINNING OF DISCOVERIES (SALES) OF AT END
OF PREVIOUS IMPROVED AND MINERALS OF
PERIOD ESTIMATES RECOVERY ADDITIONS IN PLACE PRODUCTION PERIOD
--------- --------- -------- ------------ ---------- ---------- --------

1994:
Oil and condensate (MMBbls)...... 64.6 5.3 1.3 5.5 (0.7) (8.9) 67.1
Natural Gas (Bcf)................ 251.2 (5.6) 0.9 36.2 (5.2) (48.5) 229.0
Oil Equivalent (MMBOE)........... 106.4 4.3 1.5 11.5 (1.5) (17.0) 105.2
1995:
Oil and condensate (MMBbls)...... 67.1 8.5 2.4 4.4 6.2 (8.9) 79.7
Natural Gas (Bcf)................ 229.0 1.4 0.2 36.9 18.0 (52.8) 232.7
Oil Equivalent (MMBOE)........... 105.2 8.7 2.5 10.7 9.2 (17.8) 118.5
1996:
Oil and condensate (MMBbls)...... 79.7 5.7 -- 2.2 5.6 (10.1) 83.1
Natural Gas (Bcf)................ 232.7 22.2 -- 41.9 10.2 (59.8) 247.2
Oil Equivalent (MMBOE)........... 118.5 9.4 -- 9.2 7.3 (20.1) 124.3(a)

DECEMBER 31,
----------------------------------------
1996 1995 1994 1993
------- ------ ------ ------
PROVED DEVELOPED RESERVES (MMBOE).... 103.2 95.0 82.7 83.2

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

(a) At December 31, 1996, 4.3 MMBOE were subject to a 90% net profits interest
held by Santa Fe Energy Trust. See "-- Santa Fe Energy Trust."

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 76% over the five years ended December 31, 1996.

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, 1993 through 1996.

PRODUCTION AND DEVELOPMENT ACTIVITIES

CENTRAL DIVISION

The Central Division's producing properties consist primarily of long-lived
enhanced recovery properties in the Permian Basin of west Texas and light oil
and natural gas properties in southeastern New Mexico. Central Division
production averaged 15.9 MBbls of crude oil and liquids and 44.1 MMcf of natural
gas per day in 1996, a 13% increase from 1995. During 1996 the Division spent
$49.7 million on development projects and acquisitions. The Division
participated in 41 gross (19.9 net) development wells, 34 (17.1 net) of which
were successful. The acquisition of three enhanced oil recovery properties in
west Texas for $20 million added production of approximately 1.0 MBOE per day.

The company is engaged in development activities primarily through the use
of secondary waterfloods and tertiary CO2 floods on its properties in mature
fields in the Permian Basin of west Texas and the development of producing
properties discovered or acquired by the company. 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. Following the
waterflood phase, certain fields may continue to produce in response to tertiary
EOR projects, such as the injection of CO2 which

mixes with the oil and improves the efficiency of the water flood. The Wasson
and Reeves fields are the most significant of the company's enhanced oil
recovery properties.

The company has been active in the Wasson field in the Permian Basin of
west Texas since 1939. The company's interests in this field consist principally
of royalty and working interests in four units, operated by affiliates of Amoco
Corporation, Atlantic Richfield Company and Shell Oil Company, which are
presently under CO2 flood. 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 1996 the Wasson field accounted for approximately 21% of the
company's crude oil and liquids production. 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.

The company is the operator and 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 1996, 21 wells
were drilled and 15 wells were worked over as part of a program to infill drill
the unit from 40-acre to 20-acre spacing and enhance current waterflood
operations.After three years, the program has more than doubled the production
rates at the beginning of the project. Based on its success to date, the company
plans to continue the infill drilling and workover program in this field in
1997. During 1996 the Reeves field accounted for approximately 7% of the
company's crude oil and liquids production.

The company continued its development activities in Lea and Eddy Counties
in southeastern New Mexico with a total of 22 gross (8.6 net) development wells
being completed in 1996. At year-end 1996, production from this area averaged
9.7 MBOE per day, a 10% increase from year-end 1995. The Cisco-Canyon project in
Eddy County continues to be the company's most significant project in the area.
At year-end net production from the project was averaging approximately 4.4 MBOE
per day from eleven wells. Development drilling in the East Indian Basin area of
the Cisco-Canyon project added approximately 1.7 MBOE per day to 1996
production. Development drilling will continue in the area in 1997.

Central Division development and acquisition capital expenditures are
expected to total approximately $66 million in 1997. Such expenditures include
the first quarter acquisitions of working interests in certain properties in the
Levelland field in the Permian Basin of west Texas for approximately $31.4
million. Such properties currently produce approximately 1,100 BOE per day, net
to the company.

GULF DIVISION

Gulf Division production in 1996 increased to 98.1 MMcf of natural gas per
day and 3.6 MBbls of crude oil and liquids per day, a 10% increase from 1995.
The increase in production, which reversed a two-year decline, was due primarily
to the Company's successful exploration program in 1995 and 1996, during which
14 of 19 exploratory wells were successful. Gulf Division properties accounted
for 60% of the company's 1996 natural gas production and 50% of the company's
proved natural gas reserves at year-end 1996.

The company's activities in the Gulf of Mexico have historically been
concentrated in the shallow water area (less than 400 feet of water) where the
company has considerable experience in drilling and field operations. The Gulf
Division participates in 51 producing fields on 90 blocks, 11 of which are
company-operated. The company expects seven new fields to commence production in
1997, six of which are company-operated.

During 1996 the Division spent $41.8 million on development, including $6.8
million on acquisitions. The company participated in the drilling of seven gross
(1.6 net) development wells, six of which were successfully completed. Three of
these wells were producing at year end 1996, including a horizontal completion
that is part of the Main Pass 225 Unit. The Main Pass 225 Unit is currently
producing approximately 10 MMcf of natural gas per day net to the company. The
remaining three wells are scheduled to commence production in 1997 and 1998. In
mid-1996 the company completed platform and pipeline construction and commenced
production from its 100% owned Galveston A-34 project. At year end three wells
were producing approximately 15 MMcf of natural gas and 300 barrels of
condensate per day.

Gulf Division development expenditures are expected to total approximately
$45 million in 1997. The division expects to participate in the drilling of six
development wells in 1997.

INTERNATIONAL DIVISION

International Division production and development operations are currently
focused in Indonesia, Argentina and Gabon. In 1996 the International Division
accounted for 29% of the company's crude oil and liquids and 13% of the
company's natural gas production. The Division's 1996 production comes from the
Salawati Basin and Salawati Island fields in Indonesia and the El Tordillo and
Sierra Chata fields in Argentina. New production will commence from the Mudi and
North Geragai fields in Indonesia in 1997 and from the Makmur field in Indonesia
and the Tchatamba discovery in Gabon in 1998. International Division proved
reserves at year-end 1996 accounted for 29% of the company's crude oil and
liquids reserves and 11% of the company's natural gas reserves. Such reserves do
not include volumes attributable to the Indonesian and Gabon fields which are
expected to begin production in 1997 and 1998.

International Division production averaged 8.0 MBBls of crude oil and
liquids and 21.2 MMcf of natural gas per day in 1996, a 17% increase from 1995.
During 1996 the Division spent $36.5 million on development projects and
acquisitions. In Argentina, the Division spent $12.1 million on ongoing field
enhancements at the El Tordillo and Sierra Chata fields and expansion of the gas
plant at the Sierra Chata field. In addition, the Division paid $7.4 million for
an additional 4% working interest in the El Tordillo field. Indonesian
operations accounted for $12.9 million of development expenditures and in Gabon
development expenditures totalled $3.1 million. During 1996 the Division
participated in 27 gross (5.8 net) development wells, 26 gross (5.6 net) of
which were successful.

INDONESIA. The company is the operator of 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, 1996, the
company held a 33 1/3% participation interest in the Salawati Basin Joint
Venture. The Salawati Basin Joint Venture operates under a production sharing
contract (a "PSC") with the Indonesia state oil agency ("Pertamina"), which
expires in the year 2020. As of December 31, 1996 the contract covered an area
of approximately 235,000 acres. Production occurs from seven oil and three gas
condensate fields. The entitlement of the Salawati Basin Joint Venture under the
PSC averaged approximately 6.5 MBbls per day (approximately 2.2 MBbls per day
net to the company) for the year ended December 31, 1996.

The company is also a participant in 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, 1996
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 under the terms of a Joint Operating
Body (a "JOB"). Sales from the Matoa field began in January of 1993 and in
December 1996 the field produced approximately 6.9 MBbls of oil per day
(approximately 2.0 MBbls per day net to the company) from 25 wells.

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. Pertamina has given preliminary approval of a
plan of development and the company and its partners have begun

procurement of facilities and construction services. Commercial oil sales are
expected to begin in the third quarter of 1997. The company has conducted a
seismic program to delineate the extent of the field and to further define
similar anomolies in the area. A sixth well was completed in February 1997 and a
seventh well is in progress. Three additional development wells are planned for
1997. The company holds a 12.5% interest and operates the Mudi project under the
terms of a JOB comprised of Pertamina and the company.

The Jabung Block covers nearly two million acres in central Sumatra. 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 the first quarter of 1995 the company
completed the North Geragai No. 1 discovery well on the Jabung Block in central
Sumatra and to date six additional productive wells have been drilled. In
September 1996 Pertamina approved the plan of development for the North Geragai
field and procurement of facilities and initial construction commenced in
October. Three additional development wells are planned for 1997. Commercial oil
sales from the field are expected to commence in mid-1997.

In August 1995 the Northeast Batara No. 1 exploratory well, located
approximately 25 miles northeast of the North Geragai No. 1, tested 420 barrels
of condensate and 22 MMcf of gas (approximately 55% carbon dioxide) per day from
three intervals. A second well tested 204 barrels of condensate and 12 MMcf of
gas per day. A seismic program is planned to delineate the extent of the field.

In December 1996 the company tested the Makmur No. 1, the third new field
discovery on the Jabung Block, at combined flow rates of 3,915 barrels of oil
and 6.8 MMcf of gas per day from three geologic intervals. Additional seismic
and delineation drilling will be required to determine the extent of the Makmur
reservoir.

The contracts under which the company operates the Salawati Basin Joint
Venture and the Tuban Block entitle the participants to recover all expenditures
related to the operation (the "cost recovery amount") by allocating to the
participants a portion of the crude oil production ("cost oil") sufficient, at
the Indonesia government official crude oil price ("ICP"), to offset the cost
recovery amount. All unrecovered costs in any calendar year are carried forward
to future years. The balance of production after deducting the cost recovery
amount is allocated to Pertamina and the participants (66% is allocated to
Pertamina with respect to the Salawati Basin Joint Venture and 71% is allocated
to Pertamina with respect to the Tuban Block). However, after the first five
years of production 25% of such production allocated to the participants must be
sold into the Indonesian domestic market for $0.20 per barrel.

Under the terms of the contracts under which the company operates the
Salawati Island Block and the Jabung Block, the joint venture participants are
allowed to recover the cost recovery amount, after an initial 20% portion
(approximately 8% to the joint venture participants and 12% to Pertamina) has
been deducted, by allocating to the joint venture participants cost oil
sufficient to offset the cost recovery amount. All unrecovered costs in any
calendar year are carried forward to future years. The balance of production
after allocation of cost oil is allocated approximately 62% to Pertamina and 38%
to the joint venture participants. However, after the first five years of
production 25% of such production allocated to the joint venture participants
must be sold into the Indonesian domestic market for 10% to 15% of ICP.

ARGENTINA. The company acquired an interest in the El Tordillo field in
Chubut Province, Argentina in 1991. At that time, the field was producing
approximately 10,500 gross barrels of oil per day. As of December 31, 1996 the
company and its partners have completed 282 workovers and drilled 30 new wells,
expanded the existing waterflood programs and initiated two new waterflood
pilots, increasing production to approximately 20,800 gross barrels of oil per
day. The company expects to drill 22 development wells and continue the workover
program in 1997 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 33% rate after deductions for capitalized costs and
expenses. The company holds a 22% working interest in the El Tordillo field.

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. Fourteen additional successful wells have been drilled and
the combined deliverability of the fifteen wells is approximately 180 MMcf of
natural gas per day with a carbon dioxide content of approximately 8%. The
company expects to drill two additional development wells in 1997. 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 with certain "take-or-pay" and "delivery-or-pay"
obligations with MetroGas S.A., a Buenos Aires gas distribution company. Natural
gas produced in excess of the contract requirements is sold on the spot market.
The company has committed to supply gas to the Chilean market via the GasAndes
Pipeline beginning in 1998. To fulfill its commitment under the new contract,
deliveries to Metro Gas will be reduced within the contract terms. Sales from
the field averaged 20.4 MMcf per day net to the company during 1996. There is a
12% royalty and a 1% provincial tax on gross production and the joint venture is
taxed at a 33% rate after deductions for capitalized costs and expenses. The
company has a 19.9% working interest in the Block and is the operator.

During 1997 the Division expects to spend $54.5 million on development
projects. Indonesian operations account for $27.5 million of such expenditures,
primarily on Jabung Block and the Mudi field where production will begin in
1997. In Argentina, the Division expects to spend $13.1 million on the El
Tordillo and Sierra Chata fields. In Gabon, where production is expected to
commence in 1998, development expenditures are expected to total $6.9 million.
During 1997 the Division expects to participate in 51 gross (10 net) development
wells.

EXPLORATION ACTIVITIES

The company drilled 33 gross exploratory wells (13.8 net wells) in 1996 of
which 19 (8.9 net) were successful, and the company plans to participate in the
drilling of 47 gross exploratory wells at a net cost to the company of
approximately $33 million during 1997. The company typically develops its own
prospects, in many cases utilizing 3-D seismic data. A large portion of the
company's undeveloped acreage position has been acquired through federal lease
sales and through entering into concessions with foreign governments. Prior to
drilling more expensive wells, the company generally brings in partner(s) to
share the cost while retaining operatorship. In certain instances, the company
is able to get its partners to pay the company's share of the cost to drill a
well. The company's exploration program is most active in the Gulf of Mexico,
where it recently entered the "flex trend", and certain foreign locations. The
company plans to drill five exploratory wells in the flex trend, the first of
which is scheduled for the second quarter of 1997, and ten exploratory wells in
foreign locations.

DOMESTIC

At year-end 1996, the company held an interest in 245,100 gross undeveloped
acres (124,100 net acres) in the shallow water Continental Shelf area of the
Gulf of Mexico. The company participated in 7 gross (2.9 net) exploratory wells
in the Gulf of Mexico in 1996, including 5 gross (2.4 net) discovery wells, for
an 83% net success rate.

The company's offshore program has been expanded to include prospects in
the flex trend in water depths of 400 to 2,500 feet. This area of the Gulf of
Mexico has only recently had sufficient infrastructure and technology to warrant
the company's entry into the play. The "'flex" area of the Gulf is
underexplored and contains larger prospects and field sizes than are being
drilled in the

shallower water "shelf" area. The company acquired 89,000 net acres on 14
prospects on 22 blocks in the flex trend in 1996 and intends to participate in
the two lease sales in 1997. Five of the flex trend prospects will be explored
under the terms of an agreement with Reading & Bates Development Co. A drilling
rig is under contract and drilling is expected to commence in the second quarter
of 1997. An affiliate of Reading & Bates will carry out the design, construction
and installation of facilities associated with commercial discoveries on the
five prospects.

In southeastern New Mexico, the company has continued a modest exploratory
program concentrating on multiple Permian and Pennsylvanian aged oil and gas
reservoirs ranging in depth from 1,500 to 16,000 feet. The focus in 1996 was to
drill for deeper, gas bearing objectives which also provide exposure to
shallower Delaware and Bone Springs oil reserves. The company has entered into a
joint venture 3-D seismic exploration program in western Michigan. The focus of
the play is shallow oil and gas reserves in Silurian reefs, a prolific producer
in the state. The company acquired an option covering more than 50,000 acres in
1996 and will begin the seismic and drilling phases of the program in 1997.

INTERNATIONAL

INDONESIA. In 1995 the company signed a new contract for the 956,000 acre
Bangko Block in south Sumatra. During 1996 the company drilled and abandoned two
exploratory wells, the majority of the company's costs of which were paid by its
partners. Additional exploration efforts on the block are being evaluated. The
company is the operator and holds a 35% interest in the Bangko Block.

In December 1996 the company signed a PSC with Pertamina giving the company
the right to explore the Pagatan Block, an area of approximately 2.1 million
acres along the southern coast of the island of Kalimantan. During the
three-year primary term of the contract, the company is obligated to drill at
least one well. The company is the operator and holds a 100 percent interest in
the block. The company is negotiating with potential partners for approximately
50% of its working interest.

COLOMBIA. In June 1996 the company signed a contract granting it the
exploration rights on approximately 425,000 acres in southern Colombia. The
Caprio Block covers an area in the Putumayo Basin, the northern extension of
Ecuador's Oriente Basin. The company is obligated to reprocess 1,500 kilometers
of seismic data within one year and has the option to drill an exploratory well
during the second year of the contract. The company holds a 75% working interest
in the block and is the operator.

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 northeast Ecuador. The contract includes an
initial exploration period of four years with optional extensions. Seismic
operations were completed in the first quarter of 1996 and the company drilled
two exploratory wells in the fourth quarter of 1996. One well was plugged and
abandoned and the other well has been temporarily abandoned after testing 500
barrels of oil per day. The company is obligated to drill two additional wells
on the block and plans to drill on other prospects to determine the ultimate
commerciality of the block. 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. During 1996 additional
seismic surveys were conducted to delineate the Tchatamba structure and further
define other prospects and two successful delineation wells were drilled. An
exploitation permit has been approved by the government and construction of
production facilities is expected to begin in late 1997. During 1997 one
development well and three exploratory wells are expected to be drilled on the
block. The Company holds a 25% working interest in the 614,200-acre permit area.

In August 1996 the company signed a contract to explore the Mondah Bay
Block in Gabon's Atlantic Salt Basin. The contract provides for an initial
exploration period of two years with a three-year optional extension and a
twenty-year production period. The company has committed to drill one well in
mid-1997 and it is expected that all of the company's share of the cost will be
paid by its

partner. The block is located in the northern, unexplored portion of the
Atlantic Salt Basin and covers a combined onshore and offshore area of
approximately 600 square miles. Initial activity will focus on the offshore
portions of the block where water depths are less than 100 feet and prospects
are targeted at drilling depths of less than 5,000 feet. The company holds a 50%
working interest in the block and is the operator.

COTE D'IVOIRE. In October 1996 the company signed an exploration contract
to explore Block CI-24 in the offshore portion of Cote d'Ivoire's Abidjan
margin. The block covers 649,000 acres in predominantly shallow water. Early
exploration activity will focus on the interpretation of a 3-D seismic survey
acquired by Petroci, the national oil company of Cote d'Ivoire. Petroci holds a
10% carried interest in the block and the company holds a 90% of the remaining
working interest and is the operator.

CHINA. In November 1996 the company signed a PSC with the Chinese National
Offshore Oil Company ("CNOOC") with respect to offshore Block 27/11 in the
Pearl River Mouth Basin approximately 100 miles south of Hong Kong. The block
consists of approximately 765,000 acres, with water depths generally less than
300 feet. The work program commitment on the block includes the acquisition of
approximately 600 miles of seismic data and a well to be drilled to at least
11,500 feet. Santa Fe holds a 40% working interest in the block which is
operated by Kerr-McGee.

In January 1997 the company signed two PSCs with CNOOC, giving the company
the right to explore two additional areas of the South China Sea. Block 15/34
covers approximately 800,000 acres in the Pearl River Mouth Basin, approximately
50 miles south of Hong Kong, adjacent to Block 27/11. Several prospect areas
have been identified from existing seismic and additional data acquisition will
focus on the confirmation and selection of drillsites as well as the
identification of additional drillable prospects. Block 23/28 is located north
of the large island of Haina and covers approximately 500,000 acres in the
southern portion of the Beibu Gulf Basin. Several prospect areas have been
identified from existing data which will be supplemented with 2-D and 3-D
seismic programs. The company is obligated to acquire 2-D and 3-D seismic and
drill a well to at least 10,500 feet on each of the blocks. The company holds
100% of the working interest in both contract areas.

DRILLING ACTIVITIES

The table below sets forth, for the periods indicated, the number of wells
drilled in which the company had an economic interest. As of December 31, 1996
wells in the process of drilling or completing included 4 gross (1.3 net)
domestic exploratory wells, 15 gross (6.7 net) domestic development wells, and 5
gross (1.2 net) foreign development wells.

YEAR ENDED DECEMBER 31,
------------------------------------------------------------
1996 1995 1994
------------------ ------------------ ------------------
GROSS NET GROSS NET GROSS NET
Development Wells ------ --------- ------ --------- ------ ---------

Domestic
Completed as natural gas
wells......................... 12 3.8 13 6.3 17 4.4
Completed as oil wells.......... 28 14.7 47 25.3 58 31.2
Dry holes....................... 8 3.0 4 1.5 3 1.5
Foreign
Completed as natural gas
wells........................... 5 1.1 3 0.9 2 0.4
Completed as oil wells.......... 21 4.5 17 3.2 14 4.3
Dry holes....................... 1 0.2 5 1.1 2 0.6
------ --------- ------ --------- ------ ---------
75 27.3 89 38.3 96 42.4
------ --------- ------ --------- ------ ---------
Exploratory Wells
Domestic
Completed as natural gas
wells......................... 10 5.1 13 6.3 3 1.5
Completed as oil wells.......... 6 2.9 9 3.3 9 3.5
Dry holes....................... 8 3.0 5 2.1 23 8.6
Foreign
Completed as natural gas
wells........................... 1 0.2 2 0.8 1 0.5
Completed as oil wells.......... 2 0.7 3 0.9 1 0.3
Dry holes....................... 6 1.9 3 0.8 6 2.1
------ --------- ------ --------- ------ ---------
33 13.8 35 14.2 43 16.5
------ --------- ------ --------- ------ ---------
108 41.1 124 52.5 139 58.9
====== ========= ====== ========= ====== =========

PRODUCING WELLS

The following table sets forth the company's ownership in producing wells
at December 31, 1996:

U.S.(A) ARGENTINA(B) INDONESIA(C) TOTAL
------------------ -------------- -------------- ---------------
GROSS NET GROSS NET GROSS NET GROSS NET
------ --------- ------ ---- ------ ---- ------ -----

Oil.................................. 8,539 931 386 84 368 117 9,293 1,132
Natural gas.......................... 567 164 16 3 7 2 590 169
------ --------- ------ ---- ------ ---- ------ -----
9,106 1,095 402 87 375 119 9,883 1,301
====== ========= ====== ==== ====== ==== ====== =====

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

(a) Includes 61 gross wells with multiple completions.

(b) At December 31, 1996 one gross gas well was shut-in.

DOMESTIC ACREAGE

The following table summarizes developed and undeveloped fee and leasehold
acreage in the United States at December 31, 1996. Excluded from such
information is acreage in which ownership interest is limited to royalty,
overriding royalty and other similar interests.

UNDEVELOPED DEVELOPED
-------------------- --------------------
STATE GROSS NET GROSS NET
--------- --------- --------- ---------
(IN ACRES)
Alabama -- Offshore................ -- -- 23,040 12,480
Alabama -- Onshore................. -- -- 824 112
Arkansas........................... 329 60 818 182
Colorado........................... 872 728 5,931 5,249
Kansas............................. 93 63 3,833 874
Louisiana -- Offshore.............. 232,523 109,651 229,185 88,302
Louisiana -- Onshore............... 1,856 609 8,998 2,093
Mississippi........................ 300 84 2,991 523
Montana............................ 3,450 428 670 43
New Mexico......................... 169,270 117,497 52,701 28,342
New York........................... -- -- 189 47
North Dakota....................... 2,963 986 4,570 1,025
Oklahoma........................... 6,631 5,417 21,569 8,091
Pennsylvania....................... 20 20 25 3
Texas -- Offshore.................. 133,003 103,478 58,381 18,087
Texas -- Onshore................... 137,942 107,137 188,270 133,865
Utah............................... 1,363 531 3,325 1,527
Wyoming............................ 16,384 9,260 22,844 10,753
--------- --------- --------- ---------
706,999 455,949 628,164 311,598
========= ========= ========= =========

FOREIGN ACREAGE

The following table summarizes foreign acreage at December 31, 1996:

UNDEVELOPED DEVELOPED
-------------------- --------------------
GROSS NET GROSS NET
--------- --------- --------- ---------
(THOUSANDS OF ACRES)
Argentina.......................... 2,169 539 93 19
China.............................. 765 306 -- --
Colombia........................... 423 318 -- --
Cote d'Ivoire...................... 197 197 -- --
Ecuador............................ 474 166 -- --
Gabon.............................. 1,001 345 -- --
Indonesia.......................... 6,427 3,297 43 13
--------- --------- --------- ---------
11,456 5,168 136 32
========= ========= ========= =========

SELECTED FINANCIAL AND OPERATING DATA

The following table sets forth selected financial and operating data with
respect to the company, excluding Monterey:

FINANCIAL DATA
INCOME STATEMENT DATA
Revenues........................ 290.4 230.7 212.3 250.0 212.4
--------- --------- --------- --------- ---------
Costs and Expenses
Production and
operating............... 80.6 69.7 63.7 63.6 48.5
Oil and gas systems and
pipelines............... -- -- -- 4.2 3.2
Exploration, including dry
hole costs.............. 32.8 21.0 19.0 29.3 22.8
Depletion, depreciation
and
amortization............ 110.8 100.8 89.3 111.5 102.3
Impairment of oil and gas
properties.............. 57.4 30.2 -- 50.2 --
General and
administrative.......... 21.2 19.6 19.5 23.1 22.1
Taxes (other than
income)................. 17.1 11.3 17.1 18.9 15.4
Restructuring
charges(b).............. -- -- 5.9 26.7 --
Loss (gain) on disposition
of assets............... (12.1) 0.3 (8.3) 0.6 (13.9)
--------- --------- --------- --------- ---------
307.8 252.9 206.2 328.1 200.4
--------- --------- --------- --------- ---------
Income (Loss) from Operations... (17.4) (22.2) 6.1 (78.1) 12.0
========= ========= ========= ========= =========
COSTS AND EXPENSES PER BOE
Production and operating(c)..... 4.03 3.92 3.76 3.43 3.28
Exploration, including dry hole
costs........................ 1.64 1.19 1.12 1.58 1.55
Depletion, depreciation and
amortization(d).............. 5.39 5.61 5.26 6.03 6.91
General and administrative(e)... 0.88 1.10 1.15 1.25 1.49
Taxes other than income(f)...... 0.86 0.63 1.01 1.03 1.04

(TABLE CONTINUED ON FOLLOWING PAGE)

YEAR ENDED DECEMBER 31,(a)
-----------------------------------------------------
1996 1995 1994 1993(g) 1992(h)
--------- --------- --------- --------- ---------
(IN MILLIONS OF DOLLARS, EXCEPT AS NOTED)
OPERATING DATA
DAILY AVERAGE PRODUCTION
Crude oil and liquids
(MBbls/day)
Domestic.................. 19.5 16.7 16.3 17.7 16.3
Argentina................. 3.7 2.6 2.4 2.4 2.4
Indonesia................. 4.3 5.2 5.7 4.1 1.8
--------- --------- --------- --------- ---------
27.5 24.5 24.4 24.2 20.5
========= ========= ========= ========= =========
Natural gas (MMcf/day).......... 163.4 144.7 132.8 159.0 119.2
Total production (MBOE/day)..... 54.7 48.6 46.6 50.7 40.4
AVERAGE SALES PRICES
Crude oil and liquids ($/Bbl)
Unhedged
Domestic............. 19.96 16.34 14.92 16.20 18.38
Argentina............ 19.06 14.72 13.23 14.07 15.99
Indonesia............ 18.92 16.10 15.09 15.50 17.51
Total................ 19.68 16.12 14.79 15.87 18.02
Hedged.................... 18.66 16.40 14.79 15.87 18.17
Natural Gas ($/Mcf)
Unhedged.................. 2.18 1.46 1.77 2.04 1.72
Hedged.................... 1.83 1.45 1.75 1.90 1.71
PROVED RESERVES AT YEAR END
Crude oil, condensate and
natural gas
liquids (MMBbls)............. 83.1 79.7 67.1 64.6 64.8
Natural gas (Bcf)............... 247.2 232.7 229.0 251.2 258.7
Proved reserves (MMBOE)......... 124.3 118.5 105.2 106.4 108.1
Proved developed reserves
(MMBOE)...................... 103.2 95.0 82.7 83.2 90.8
PRESENT VALUE OF PROVED RESERVES AT
YEAR-END
Before income taxes............. 1,047.7 602.8 417.0 400.7 532.0

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

(a) Certain prior period amounts have been restated to conform to 1996
presentation.

(b) 1993 amount includes losses on property dispositions of $16.5 million,
long-term debt repayment penalties of $8.6 million and accruals of certain
personnel benefits and related costs of $1.6 million. 1994 amount represents
severance, benefits and relocation expenses.

(d) Excludes effect of unproved property writedowns of $0.13 per BOE in 1996 and
$0.06 per BOE in 1995.

(e) Excludes effect of $1.6 million charge related to the abandonment of an
office lease and $2.0 million in costs and expenses related to the IPO
($0.18 per BOE) in 1996.

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

(g) 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) and gives
effect to the sale in 1993 of approximately 8.0 MMBOE of proved reserves.

(h) On May 19, 1992 Adobe Resources Corporation was merged with and into the
company.

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,
1996, 4.3 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.

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. As of December 31, 1996 the
company had made additional royalty payments (net of recoupments) totalling $1.2
million and will recoup $1.0 million from the proceeds payable to the Trust in
the first quarter of 1997. 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.

MONTEREY RESOURCES, INC.

In 1996 Santa Fe formed Monterey to assume the operations of Santa Fe's
Western Division (the "Western Division") which conducted Santa Fe's oil and
gas operations in the State of California. In November 1996, prior to the
initial public offering (the "IPO") discussed below, pursuant to a
contribution and conveyance agreement (the "Contribution Agreement"), among
other things: (i) Santa Fe contributed to Monterey substantially all of the
assets and properties of the Western Division, subject to the retention by Santa
Fe of a production payment, as defined below, and certain other assets; (ii)
Santa Fe retained a $30.0 million production payment (the "Production
Payment") with respect to certain properties in the Midway-Sunset field; (iii)
Monterey assumed all obligations and liabilities of Santa Fe associated with or
allocated to the assets and properties of the Western Division, including $245.0
million of indebtedness in respect of Santa Fe's 10.23% Series E Notes due 1997,
10.27% Series F Notes due 1998 and 10.61% Series G Notes due 2005 (the "Series
E Notes", "Series F Notes" and "Series G Notes", respectively) and (iv)
Monterey agreed to purchase from Santa Fe an $8.3 million promissory note
receivable related to the sale to a third party of certain surface acreage
located in Orange County, California. Also prior to the IPO, Monterey and Santa
Fe entered into a $75.0 million revolving credit facility with a group of banks
(the "Monterey Credit Facility") and borrowed $16.0 million which was retained
by Santa Fe.

In November 1996 Monterey sold 9,335,000 shares of its common stock for
total consideration of $123.6 million (after deducting underwriting discounts of
$9.1 million and other related costs of $2.6

million). The proceeds from the IPO were used in part to (i) repay the Series E
Notes and Series F Notes ($70.0 million) and pay a prepayment penalty thereon of
$2.5 million; (ii) retire the Production Payment ($30.0 million); (iii) repay
the $16.0 million outstanding under the New Credit Facility; and (iv) pay a $2.0
million fee with respect to a supplement to the indenture relating to Santa Fe's
11% Senior Subordinated Debentures due 2004. Subsequent to the IPO, Monterey
issued $175.0 million in aggregate principal amount of 10.61% Senior Notes due
2005 (the "Monterey Senior Notes") to holders of the Series G Notes in
exchange for the cancellation of such notes and paid a $1.3 million consent fee
in connection therewith.

In December 1996 Santa Fe sold the surface rights to approximately 116
surface acres in Orange County, California for total consideration of $24.2
million and recognized a $12.3 million gain. Santa Fe received $15.9 million in
cash and an $8.3 million note, which note was then purchased by Monterey for
cash.

At December 31, 1996, Santa Fe owned 82.8% of Monterey's outstanding common
stock. Santa Fe has announced that it intends to distribute pro rata to its
common shareholders all of the shares of Monterey's common stock that it owns by
means of a tax-free distribution. See -- "GENERAL."

The discussions included herein with respect to the years ended December
31, 1995 and prior relate to the operations of the Western Division. The
discussions with respect to the year ended December 31, 1996 relate to the
operations of the Western Division for January through October and the
operations of Monterey for November and December.

RESERVES

The following table sets forth information regarding changes in Monterey's
estimates of proved net reserves from January 1, 1994 to December 31, 1996 and
the balance of Monterey's estimated proved developed reserves at December 31, of
each of the years 1993 through 1996, as prepared by Ryder Scott:

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

1994:
Oil and Condensate (MMBbls)...... 183.6 9.9 12.6 -- 0.2 (15.1) 191.2
Gas (Bcf)........................ 11.8 2.9 -- -- 0.1 (1.4) 13.4
Oil Equivalent (MMBOE)........... 185.6 10.4 12.6 -- 0.2 (15.3) 193.5
1995:
Oil and Condensate (MMBbls)...... 191.2 9.7 13.7 -- 0.1 (15.2) 199.5
Gas (Bcf)........................ 13.4 0.9 -- -- -- (1.9) 12.4
Oil Equivalent (MMBOE)........... 193.5 9.8 13.7 -- 0.1 (15.5) 201.6
1996:
Oil and Condensate (MMBbls)...... 199.5 12.0 14.4 -- 7.6 (17.1) 216.4
Gas (Bcf)........................ 12.4 1.1 -- -- -- (1.3) 12.2
Oil Equivalent (MMBOE)........... 201.6 12.1 14.4 -- 7.6 (17.3) 218.4

DECEMBER 31,
------------------------------------------
1996 1995 1994 1993
--------- --------- --------- ---------
PROVED DEVELOPED RESERVES (MMBOE)... 172.6 158.6 141.8 142.3

During the five years ended December 31, 1996, Monterey spent a total of
$172.9 million on development activities on its properties. Cumulative
production from the properties during the same five-year period exceeded 79.8
MMBOE while additions to proved reserves exceeded 111.4 MMBOE (yielding 31.6
MMBOE net additions after production.) Based on reservoir engineering studies
prepared by Ryder Scott, Monterey believes that it can continue to make
significant additions to proved reserves on its properties through additional
EOR and development projects. Monterey anticipates

spending approximately $70.9 million during 1997 on additional development
projects on its properties. Because the actual amounts expended in the future
and the results therefrom will be influenced by numerous factors, including many
beyond its control, and due to the inherent uncertainty of reservoir engineering
studies, no assurances can be given as to the amounts that will be expended or,
if expended, that the results therefrom will be consistent with the Monterey's
prior experience or expectations.

DEVELOPMENT ACTIVITIES

Monterey is engaged in development activities primarily through the
application of thermal EOR techniques on its heavy oil properties in the San
Joaquin Valley. Thermal EOR operations involve the injection of steam into a
reservoir to raise the temperature and reduce the viscosity of heavy oil,
facilitating the flow of the oil into producing wellbores. In addition, Monterey
has begun to utilize horizontal drilling in conjunction with the steam projects
already deployed. Based on results to date it is believed that horizontal wells
can provide production rates up to 10 times greater than the typical vertical
well while providing drainage for portions of the reservoir that cannot be
effectively drained by vertical wells. In addition to these thermal techniques,
Monterey has extensive experience in the use of waterfloods, which involves the
injection of water into a reservoir to drive hydrocarbons into producing
wellbores.

In 1996 Monterey spent $48.7 million on development work including the
drilling of vertical infill and step-out wells and seven horizontal wells, the
addition of 39 steamflood patterns and the expansion of key facilities to serve
increased production and steam volumes. The majority of the 1996 development
activity was focused at Midway-Sunset and Kern River and resulted in a combined
net oil production increase from December 31, 1995 to December 31, 1996 of 4.3
MBbls per day. During 1996 Monterey drilled 227 gross (218 net) development
wells.

Monterey's production and reserves are concentrated in four fields in
California's San Joaquin Valley. These fields, Midway-Sunset, Kern River, South
Belridge and Coalinga account for 95% of Monterey's 1996 net production and 93%
of Monterey's December 31, 1996 proved reserves. Monterey's properties in these
fields are generally highly concentrated and equipped with efficient centralized
infrastructure.

MIDWAY-SUNSET. Monterey owns and operates a 100% working interest (96%
average net revenue interest) in over 13,000 gross acres and 2,300 producing
wells in the Midway-Sunset field. The Company is currently the largest producer
in the field and has operated there continuously since 1905. Substantially all
of the oil produced from the Midway-Sunset field is heavy crude oil located in
the Pleistocene and Miocene reservoirs at depths of less than 2,000 feet.

During 1996, Monterey's properties at Midway-Sunset produced at record
levels averaging 35.1 MBbls per day for the year, an increase of 2.5 MBbls per
day over the average for 1995, and accounted for 74% of Monterey's 1996 crude
production. Total December 31, 1996 proved reserves for Monterey's Midway-Sunset
properties represented approximately 75% of Monterey's total proved reserves.
Based on reservoir engineering studies prepared by Ryder Scott, Monterey
believes that it can continue to make significant additions to its proved
reserves in this field through additional EOR and development projects. Monterey
has identified in excess of 1,300 well operations that could be undertaken in
the field and anticipates completing 300 of these operations (including 40
horizontal wells) in 1997 at an estimated capital cost of $51.0 million.

KERN RIVER. Monterey owns and operates a 100% working interest (91%
average net revenue interest) in four properties in the Kern River field,
located near Bakersfield, California. Monterey acquired its interest in the Kern
River field in 1905. With field-wide production rates of approximately 135 MBbls
per day, the Kern River field is the second largest producing oil field in the
lower 48 states and has produced in excess of 1.5 billion barrels of oil. Most
of the oil produced from the Kern River field is heavy crude oil produced from
Plio-Pleistocene reservoirs at depths of less than 1,000 feet. During 1996, the
Kern River field accounted for approximately 11% of Monterey's total crude

production. As of December 31, 1996, Monterey's total proved reserves in the
Kern River field were approximately 9% of its total proved reserves. As with the
Midway-Sunset field, based on engineering studies prepared by Ryder Scott,
Monterey believes that it can continue to make significant additions to its
proved reserves in the Kern River field through additional thermal development
projects.

SOUTH BELRIDGE. Monterey has a 46% average working interest (40% average
net revenue interest) in its properties in the South Belridge field, which is
located 15 miles north of the Midway-Sunset field. Monterey acquired interests
in the South Belridge field in 1987 and expanded its holdings in 1991. The oil
in the South Belridge field is heavy and light crude that is produced from
depths of generally less than 2,000 feet. During 1996, the South Belridge field
accounted for approximately 5% of Monterey's total crude production. As of
December 31, 1996, Monterey's total proved reserves in the South Belridge field
were approximately 6% of its total proved reserves.

COALINGA. Monterey has a 100% average working interest (84% average net
revenue interest) in its properties in the Coalinga field which is located 55
miles southwest of Fresno, California. During 1996, the Coalinga field accounted
for approximately 5% of Monterey's crude production. As of December 31, 1996,
Monterey's total proved reserves in the Coalinga field were approximately 3% of
its total proved reserves.

SELECTED FINANCIAL AND OPERATING DATA

The following table sets forth selected financial and operating data with
respect to Monterey:

YEAR ENDED DECEMBER 31, (a)
-----------------------------------------------------
1996 1995 1994 1993 1992
--------- --------- --------- --------- ---------
(IN MILLIONS OF DOLLARS, EXCEPT AS NOTED)

FINANCIAL DATA
INCOME STATEMENT DATA
Revenues........................... 292.9 218.7 191.9 199.5 226.4
--------- --------- --------- --------- ---------
Costs and Expenses
Production and operating..... 107.8 86.1 87.4 101.7 106.3
Cost of crude oil
purchased.................. 20.8 6.5 11.7 11.1 9.9
Exploration, including dry
hole costs................. 1.7 2.4 1.4 1.7 2.7
Depletion, depreciation and
amortization............... 37.4 32.4 32.0 41.2 44.0
Impairment of oil and gas
properties................. -- -- -- 49.1 --
General and administrative... 8.9 7.3 7.8 9.2 8.8
Taxes (other than income).... 9.4 7.9 8.7 8.4 8.9
Restructuring charges........ -- -- 1.1 11.9 --
Loss (gain) on disposition of
oil and gas properties..... -- -- (0.3) 0.1 0.3
--------- --------- --------- --------- ---------
186.0 142.6 149.8 234.4 180.9
--------- --------- --------- --------- ---------
Income (Loss) from Operations...... 106.9 76.1 42.1 (34.9) 45.5
========= ========= ========= ========= =========
COSTS AND EXPENSES PER BOE:
Production and Operating
Expenses:.......................
Steam generation............. 2.51(b) 1.98 2.16 2.26 2.41
Lease operating.............. 3.53 3.56 3.55 4.05 4.24
Total................... 6.04(b) 5.54 5.71 6.31 6.65
Exploration, including dry holes... 0.10 0.15 0.09 0.11 0.17
Depletion, depreciation and
amortization.................... 2.16 2.08 2.09 2.59 2.79
General and administrative......... 0.44 0.47 0.51 0.58 0.56
Taxes (other than income).......... 0.54 0.51 0.56 0.53 0.56

(TABLE CONTINUED ON FOLLOWING PAGE)

YEAR ENDED DECEMBER 31, (a)
-----------------------------------------------------
1996 1995 1994 1993 1992
--------- --------- --------- --------- ---------
(IN MILLIONS OF DOLLARS, EXCEPT AS NOTED)
OPERATING DATA
DAILY AVERAGE PRODUCTION
Crude oil and liquids
(MBbls/day)..................... 46.8 41.8 41.3 42.5 42.0
Natural gas (MMcf/day)............. 3.5 5.3 3.8 6.4 7.1
Total production (MBOE/day)........ 47.4 42.7 41.9 43.6 43.2
AVERAGE SALES PRICES
Crude oil and liquids ($/Bbl)
Unhedged..................... 16.00 13.79 11.77 11.77 13.22
Hedged....................... 15.82 13.79 11.77 11.77 13.78
Natural gas ($/Mcf realized)....... 1.03 0.98 1.14 1.59 1.57
PROVED RESERVES AT YEAR-END
Crude oil, condensate and natural
gas liquids
(MMBbls)........................ 216.4 199.5 191.2 183.6 190.3
Natural gas (Bcf).................. 12.2 12.4 13.4 11.8 18.8
Proved reserves (MMBOE)............ 218.5 201.6 193.5 185.6 193.4
Proved developed reserves
(MMBOE)......................... 172.6 158.6 141.8 142.3 157.6
PRESENT VALUE OF PROVED RESERVES AT
YEAR-END
Before income taxes................ 1,047.8 654.4 553.8 167.1 383.2
PRODUCTION COSTS PER BOE (including
related production, severance and
ad valorem taxes) (in dollars)..... 6.64 5.98 6.19 6.85 7.23

- ------------
(a) Reflects the operations of the Western Division for the years 1992 through
1995. The year 1996 reflects the operations of the Western Division for
January through October and Monterey for November and December.

(b) Excludes $0.18 per BOE loss on hedging. The hedging transactions which
generated these losses expired on June 30, 1996. Including such hedging
losses, historical steam generation costs would have been $2.69 per BOE and
historical total production costs would have been $6.22 per BOE.

SANTA FE CONSOLIDATED

Unless otherwise indicated, discussions and amounts throughout the
remainder of this Form 10-K relate to Santa Fe Energy Resources, Inc.
consolidated with its 83% subsidiary Monterey. Therefore all references
hereafter to "Santa Fe" or the "Company" relate to Santa Fe, including
Monterey.

At December 31, 1996 the Company had worldwide proved reserves totaling
342.7 MMBOE (consisting of approximately 299.5 MMBbls of oil and approximately
259.4 Bcf of natural gas), of which approximately 92% were domestic reserves and
approximately 8% were foreign reserves. During 1996 the Company's worldwide
production aggregated approximately 37.4 MMBOE, of which approximately 73% was
crude oil and approximately 27% was natural gas.

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
offering. 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").

RESERVES

The following tables set forth information regarding changes in the
Company's estimates of proved net reserves from January 1, 1994 to December 31,
1996 and the balance of the Company's estimated proved developed reserves at
December 31 of each of the years 1993 through 1996, as prepared by Ryder Scott:

1994:
Crude Oil and Liquids (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
1995:
Crude Oil and Liquids (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
1996(A) :
Crude Oil and Liquids (MMBbls)... 279.2 17.7 14.4 2.2 13.2 (27.2) 299.5
Gas (Bcf)........................ 245.1 23.3 -- 41.9 10.2 (61.1) 259.4
Oil Equivalent (MMBOE)........... 320.1 21.5 14.4 9.2 14.9 (37.4) 342.7(b)

DECEMBER 31,
------------------------------------------
1996 1995 1994 1993
--------- --------- --------- ---------
PROVED DEVELOPED RESERVES (MMBOE).. 275.8 253.6 224.5 225.5

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

(a) At December 31, 1996 Monterey had proved reserves totalling 216.4 MMBbls
of oil and liquids and 12.2 Bcf of natural gas.

(b) At December 31, 1996, 4.3 MMBOE were subject to a 90% net profits interest
held by Santa Fe Energy Trust. See "-- Santa Fe Energy Trust."

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 33% over the five years ended December 31, 1996. 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.

During 1996 the Company filed Energy Information Administration Form 23
which reported natural gas and oil reserves for the year 1995. On an equivalent
barrel basis, the reserve estimates for the year 1995 contained in such report
and those reported herein for the year 1995 do not differ by more than five
percent.

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, 1996
Santa Fe was in the process of drilling or completing 4 gross (1.3 net) domestic
exploratory wells, 15 gross (6.7 net) domestic development wells, and 5 gross
(1.2 net) foreign development wells.

Development Wells
Domestic
Completed as natural gas
wells........................ 12 3.8 13 6.3 17 4.4
Completed as oil wells.......... 252 229.9 271 234.5 136 101.4
Dry holes....................... 11 6.0 4 1.5 4 2.5
Foreign
Completed as natural gas
wells........................... 5 1.1 3 0.9 2 0.4
Completed as oil wells.......... 21 4.5 17 3.2 14 4.3
Dry holes....................... 1 0.2 5 1.1 2 0.6
------ --------- ------ --------- ------ ---------
302 245.5 313 247.5 175 113.6
------ --------- ------ --------- ------ ---------
Exploratory Wells
Domestic
Completed as natural gas
wells........................ 10 5.1 13 6.3 3 1.5
Completed as oil wells.......... 6 2.9 9 3.3 9 3.5
Dry holes....................... 9 3.4 8 5.1 23 8.6
Foreign
Completed as natural gas
wells........................... 1 0.2 2 0.8 1 0.5
Completed as oil wells.......... 2 0.7 3 0.9 1 0.3
Dry holes....................... 6 1.9 3 0.8 6 2.1
------ --------- ------ --------- ------ ---------
34 14.2 38 17.2 43 16.5
------ --------- ------ --------- ------ ---------
336 259.7 351 264.7 218 130.1
====== ========= ====== ========= ====== =========

PRODUCING WELLS

The following table sets forth Santa Fe's ownership in producing wells at
December 31, 1996:

U.S.(a) ARGENTINA(b) INDONESIA(c) TOTAL
--------------------- -------------- ----------------- ---------------
GROSS NET GROSS NET GROSS NET GROSS NET
--------- --------- ------ ---- --------- ---- ------ -----

Oil.................................. 14,178 6,034 386 84 368 117 14,932 6,235
Natural gas.......................... 569 164 16 3 7 2 592 169
--------- --------- ------ ---- --------- ---- ------ -----
14,747 6,198 402 87 375 119 15,524 6,404
========= ========= ====== ==== ========= ==== ====== =====

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

(a) Includes 61 gross wells with multiple completions.

(b) At December 31, 1996 one gross gas well was shut-in.

DOMESTIC ACREAGE

The following table summarizes Santa Fe's developed and undeveloped fee and
leasehold acreage in the United States at December 31, 1996. 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
(IN ACRES)
Alabama -- Offshore............... -- -- 23,040 12,480
Alabama -- Onshore................ -- -- 824 112
Arkansas.......................... 329 60 818 182
California -- Offshore............ -- -- 17,280 2,074
California -- Onshore............. 6,602 6,602 19,716 19,496
Colorado.......................... 872 728 5,931 5,249
Kansas............................ 93 63 3,833 874
Louisiana -- Offshore............. 232,523 109,651 229,185 88,302
Louisiana -- Onshore.............. 1,856 609 8,998 2,093
Mississippi....................... 300 84 2,991 523
Montana........................... 3,450 428 670 43
New Mexico........................ 169,270 117,497 52,701 28,342
New York.......................... -- -- 189 47
North Dakota...................... 2,963 986 4,570 1,025
Oklahoma.......................... 6,631 5,417 21,569 8,091
Pennsylvania...................... 20 20 25 3
Texas -- Offshore................. 133,003 103,478 58,381 18,087
Texas -- Onshore.................. 137,942 107,137 188,270 133,865
Utah.............................. 1,363 531 3,325 1,527
Wyoming........................... 16,384 9,260 22,844 10,753
--------- --------- --------- ---------
713,601 462,551 665,160 333,168
========= ========= ========= =========

At December 31, 1996 the Company held oil and gas rights to 372,062 net
undeveloped leasehold acres. The primary lease terms with respect to 9% of such
acreage expires in 1997, 8% in 1998, 10% in 1999, 8% in 2000 and the remainder
thereafter. In addition, the Company holds 90,489 acres of undeveloped fee
acreage, located primarily in Texas.

FOREIGN ACREAGE

See "SANTA FE EXCLUDING MONTEREY -- Foreign Acreage."

CURRENT MARKETS FOR OIL AND 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 LG&E Natural Marketing Inc. ("LG&E"), formerly
Hadson Corporation ("Hadson").

The revenues generated by the Company's operations are highly dependent
upon the prices of, and demand for, oil and gas. 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 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 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."

Monterey's 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 1996 affiliates of Shell Oil Company, Celeron Corporation and
Coastal States Trading, Inc. accounted for approximately 24%, 15% and 12%,
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 1996. 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
LG&E pursuant to the terms of which LG&E markets a substantial portion of the
Company's domestic natural gas production. Pursuant to such gas contract, LG&E
is required to pay the Company for all production delivered at a price for such
gas equal to stipulated published monthly index prices. LG&E 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 LG&E are made in immediately available funds no later than the last
working day of the month following the month of production.

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 its technical and
operational capabilities. Many competitors have greater financial and other
resources than the Company. 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 program, 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.

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, many of the issues related to this Order are
still pending final resolution by the FERC (in remand proceedings) and 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 (which
has been approved by the courts) of generally approving the divestiture of
pipeline-owned gathering facilities to pipeline affiliates, (ii) FERC's efforts
to implement uniform standards for pipeline electronic bulletin boards,
electronic data exchange, and basic business and operational practices of the
pipelines,

(iii) efforts to refine FERC's regulations controlling the operation of the
secondary market for released pipeline capacity, (iv) a policy statement
regarding market and other non-cost-based rates for interstate pipeline
transmission and storage capacity and (v) an inquiry into the appropriate nature
and extent of continuing FERC regulation of offshore pipelines. The on-going and
evolving nature of these regulatory initiatives make it impossible at this time
to predict their ultimate impact upon marketing natural gas.

Finally, numerous states are in 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 the LDCs' commercial,
industrial, and, in more and more 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 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 response to threats to the public health or the
environment and to seek to recover from the responsible classes of 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. Certain
properties owned or used by the Company or its predecessors have been
investigated under state and Federal Superfund statutes, and the Company has
been and could be named a potentially responsible party ("PRP") for the
cleanup of some of these sites.

Pursuant to the Contribution Agreement, Monterey agreed to indemnify and
hold harmless Santa Fe from and against any costs incurred in the future
relating to environmental liabilities of the Western Division assets (other than
those retained by Santa Fe), including any costs or expenses incurred at any of
the OII Site, the Santa Fe Springs Site and the Eastside Site (as defined
herein), and any costs or liabilities that may arise in the future are
attributable to laws, rules or regulations in respect to any property or
interest therein located in California and formerly owned or operated by the
Western Division or its predecessors.

The Company has been identified as one of over 250 PRPs at a Superfund site
in Los Angeles County, California (the "OII Site"). The OII 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 $0.9 million. 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 $1.9
million and such costs have been provided for in the financial statements.
Pursuant to consent decrees settling lawsuits against the municipalities and
transporters involved with the OII site but not named by the EPA as PRPs, such
parties are required to pay approximately $84 million, of which approximately
$76 million will be credited against future remediation expenses. The EPA and
the PRPs are currently negotiating the final closure requirements. After taking
into consideration the credits from the municipalities and transporters, the
Company estimates its share of final costs of closure will be approximately $0.8
million, which amount has been provided for by the Company in its financial
statements. The Company has entered into a Joint Defense Agreement with the
other PRPs to defend against a lawsuit filed in September 1994 by 95 homeowners
alleging, among other things, nuisance, trespass, strict liability and

infliction of emotional distress. A second lawsuit has been filed by 33
additional homeowners and the Company and the other PRPs have entered into a
Joint Defense Agreement. At this stage of the lawsuit the Company is not able to
estimate costs or potential liability.

In 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 other
PRPs to negotiate with the EPA regarding implementation of a remedial plan for a
site located in Santa Fe Springs, California (the "Santa Fe Springs Site").
The Company owned the property on which the Santa Fe Springs 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 and for a period thereafter, hazardous
wastes were allegedly disposed at the Santa Fe Springs Site. The EPA estimates
total past and future costs for remediation to be approximately $8.0 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. The PRPs estimate
total costs to final remediation to be $3.0 million and the Company has provided
$250,000 for such costs in the financial statements.

In 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 (the
"Eastside Site") during its fourteen-year operation from 1971 to 1985. EPC has
since liquidated all assets and placed the proceeds in trust (the "EPC Trust")
for closure and post-closure activities. However, these monies may 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 $0.8 million,
the cost of which will be shared by the PRPs and the EPC Trust. The ultimate
costs of subsequent phases will not be known until the remedial investigation
and feasibility study is completed and a remediation plan is accepted by the
DTSC. The Company currently estimates final remediation could cost $2 million to
$6 million and believes the monies in the EPC Trust will be sufficient to fund
the lower end of this range of costs. The Company has provided $80,000 in its
financial statements for its share of costs related to this site.

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 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, 1996, the Company had approximately 651 employees, 177
of whom were covered by a collective bargaining agreement which expires on
January 31, 1999. Of such employees, 307 are employed by Monterey, including all
employees who are covered by the collective bargaining agreement. 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 -- SANTA FE CONSOLIDATED -- Other Business
Matters -- Environmental Regulation" and Note 14 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.

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 1996.

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

1996
1st Quarter..................... 8 3/8 10 1/2
2nd Quarter..................... 10 1/4 12 3/8
3rd Quarter..................... 11 1/4 14 1/4
4th Quarter..................... 13 15 1/8

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, 1996 the Company had approximately 38,500 shareholders of
record.

ITEM 6. SELECTED FINANCIAL DATA

YEAR ENDED DECEMBER 31,
------------------------------------------------------
1996 1995 1994 1993 1992(d)
--------- --------- --------- ------- ---------
(IN MILLIONS OF DOLLARS, EXCEPT AS NOTED)

SELECTED FINANCIAL DATA(A)
INCOME STATEMENT DATA
Revenues........................ 583.3 449.4 404.2 449.5 438.8
--------- --------- --------- ------- ---------
Costs and Expenses
Production and operating... 188.4 155.8 151.1 165.3 154.8
Cost of crude oil
purchased................ 20.8 6.5 11.7 11.1 9.9
Oil and gas systems and
pipelines................ -- -- -- 4.2 3.2
Exploration, including dry
hole costs............... 34.5 23.4 20.4 31.0 25.5
Depletion, depreciation and
amortization............. 148.2 133.2 121.3 152.7 146.3
Impairment of oil and gas
properties............... 57.4 30.2 -- 99.3 --
General and
administrative........... 30.1 26.9 27.3 32.3 30.9
Taxes (other than
income).................. 26.5 19.2 25.8 27.3 24.3
Restructuring charges(b)... -- -- 7.0 38.6 --
Loss (gain) on disposition
of assets................ (12.1) 0.3 (8.6) 0.7 (13.6)
--------- --------- --------- ------- ---------
493.8 395.5 356.0 562.5 381.3
--------- --------- --------- ------- ---------
Income (Loss) from Operations... 89.5 53.9 48.2 (113.0) 57.5
Interest income............ 1.9 10.7 2.8 9.1 2.3
Interest expense........... (37.6) (32.5) (27.5) (45.8) (55.6)
Interest capitalized....... 5.2 5.8 3.6 4.3 4.9
Other income (expense)..... (1.0) (1.6) (4.0) (4.8) (10.0)
--------- --------- --------- ------- ---------
Income (Loss) Before Income
Taxes, Minority Interest and
Extraordinary Items........... 58.0 36.3 23.1 (150.2) (0.9)
Income taxes............... (14.3) (9.7) (6.0) 73.1 (0.5)
--------- --------- --------- ------- ---------
Income (Loss) Before Minority
Interest and Extraordinary
Items......................... 43.7 26.6 17.1 (77.1) (1.4)
Minority Interest in
Monterey Resources,
Inc...................... (1.3) -- -- -- --
--------- --------- --------- ------- ---------
Income (Loss) Before
Extraordinary Items........... 42.4 26.6 17.1 (77.1) (1.4)
Extraordinary Item -- Debt
Extinguishment
Costs...................... (6.0) -- -- -- --
--------- --------- --------- ------- ---------
Net Income (Loss)............... 36.4 26.6 17.1 (77.1) (1.4)
Preferred Dividend
Requirement.............. (13.5) (14.8) (11.7) (7.0) (4.3)
Convertible Preferred
Repurchase Premium....... (33.7) -- -- -- --
--------- --------- --------- ------- ---------
Earnings (Loss) Attributable to
Common Stock.................. (10.8) 11.8 5.4 (84.1) (5.7)
========= ========= ========= ======= =========
Per share data (in dollars)
Earnings (loss) before
extraordinary items...... (0.05) 0.13 0.06 (0.94) (0.07)
Extraordinary items........ (0.07) -- -- -- --
Earnings (loss) to common
shares................... (0.12) 0.13 0.06 (0.94) (0.07)
Weighted average number of
common shares outstanding (in
millions)..................... 90.6 90.2 89.9 89.7 79.0
STATEMENT OF CASH FLOWS DATA
Net cash provided by operating
activities.................... 227.6 174.5 124.5 160.2 141.5
Net cash used in investing
activities.................... 206.8 160.8 57.7 121.4 15.9
BALANCE SHEET DATA (AT PERIOD END)
Properties and equipment, net... 909.8 889.5 843.0 832.7 1,101.8
Total assets.................... 1,120.0 1,064.8 1,071.4 1,076.9 1,337.2
Long-term debt.................. 278.5 344.4 350.4 405.4 492.8
Convertible preferred stock..... 19.7 80.0 80.0 80.0 80.0
Shareholders' equity............ 526.8 437.7 423.3 323.6 416.6

(TABLE CONTINUED ON FOLLOWING PAGE)

YEAR ENDED DECEMBER 31,
-----------------------------------------------------
1996 1995 1994 1993(c) 1992(d)
--------- --------- --------- --------- ---------
(IN MILLIONS OF DOLLARS, EXCEPT AS NOTED)
SELECTED OPERATING DATA(A)
DAILY AVERAGE PRODUCTION
Crude oil and liquids
(MBbls/day)
Domestic.................. 66.3 58.5 57.6 60.2 58.3
Argentina................. 3.7 2.6 2.4 2.4 2.4
Indonesia................. 4.3 5.2 5.7 4.1 1.8
--------- --------- --------- --------- ---------
74.3 66.3 65.7 66.7 62.5
========= ========= ========= ========= =========
Natural gas (MMcf/day).......... 166.9 150.0 136.6 165.4 126.3
Total production (MBOE/day)..... 102.1 91.3 88.5 94.3 83.6
AVERAGE SALES PRICES
Crude oil and liquids ($/Bbl)
Unhedged
Domestic............. 17.17 14.52 12.66 13.07 14.66
Argentina............ 19.06 14.72 13.23 14.07 15.99
Indonesia............ 18.92 16.10 15.09 15.50 17.51
Total................ 17.36 14.65 12.89 13.26 14.80
Hedged.................... 16.87 14.75 12.89 13.26 15.22
Natural Gas ($/Mcf)
Unhedged.................. 2.16 1.44 1.75 2.03 1.71
Hedged.................... 1.81 1.43 1.73 1.89 1.70
PROVED RESERVES AT YEAR END
Crude oil, condensate and
natural gas
liquids (MMBbls)............. 299.5 279.2 258.3 248.2 255.1
Natural gas (Bcf)............... 259.4 245.1 242.4 263.0 277.5
Proved reserves (MMBOE)......... 342.7 320.1 298.7 292.0 301.5
Proved developed reserves
(MMBOE)...................... 275.8 253.6 224.5 225.5 248.4
PRESENT VALUE OF PROVED RESERVES AT
YEAR-END
Before income taxes............. 2,095.5 1,257.2 970.8 567.8 915.2
After income taxes.............. 1,477.1 930.2 739.9 502.4 733.5
PRODUCTION COSTS PER BOE (including
related production, severance
and ad valorem taxes)
(in dollars).................... 5.64 5.18 5.34 5.43 5.71

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

(a) Certain prior period amounts have been restated to conform to 1996
presentation.

(b) 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. 1994 amount represents
severance, benefits and relocation expenses.

(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) and gives
effect to the sale in 1993 of approximately 8.0 MMBOE of proved reserves.

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

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

The Company reported a loss to common shares for the fourth quarter of 1996
of $46.2 million, or $0.51 per share, compared to earnings to common shares of
$4.7 million, or $0.05 per share, in the fourth quarter of 1995. Earnings for
the fourth quarter of 1996 included pretax charges of $47.0 million for
impairment of oil and gas properties and $9.2 million in debt extinguishment
costs associated with the IPO and, in addition, a $33.7 million premium paid
with respect to the purchase of 3.8 million shares of the Company's Convertible
Preferred Stock, 7% Series. Earnings for the fourth quarter also included a
$12.3 million gain on the sales of certain surface lands in California. Crude
oil and liquids sales of 76.5 MBbls per day represents the highest quarterly
average in the Company's history. The Company's average hedged sales price for
crude oil and liquids of $18.80 per barrel was $4.74 per barrel higher than the
fourth quarter of 1995. Similarly, the Company's average hedged sales price for
natural gas increased $0.40 per Mcf from the fourth quarter of 1995 to $2.04 per
Mcf.

The Company reported a loss to common shares for the full year 1996 of
$10.8 million, or $0.12 per share, compared to earnings to common shares of
$11.8 million, or $0.13 per share, in 1995. Crude oil and liquids sales averaged
74.3 MBbls per day, the highest annual average in the Company's history. The
Company's average hedged sales price for crude oil and liquids of $16.87 per
barrel was $2.12 per barrel higher than 1995. Average natural gas sales of 166.9
MMcf per day were also the highest in the Company's history. The Company's
average hedged sales price for natural gas increased $0.38 per Mcf from the 1995
average to $1.81 per Mcf in 1996.

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.

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 1996 of $17.17
per barrel, compared to $20.44 per barrel for West Texas Intermediate ("WTI")
crude oil (an industry posted price generally indicative of prices for sweeter
light crude oil). In 1996 the Company's average sales price for California heavy
crude oil was $15.77 per barrel, approximately 77% 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 1995 and 1996 the actual
average sales price (unhedged) received by the Company ranged from a high of
$18.80 per barrel in the fourth quarter of 1996 to a low of $14.16 per barrel
for the fourth quarter of 1995. Based on operating results for the year 1996,
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 $14.6
million change in net income and a $18.0 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 its
debt levels and related interest expense, that might 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 1996 and 1995 for its natural gas ranged from a high of $2.45 per Mcf
in the fourth quarter of 1996 to a low of $1.31 per Mcf in the first quarter of
1995.

Based on operating results for the year 1996, 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 $2.1 million change in net income (net of $1.0
million in costs associated with natural gas purchased for use in steam
generation) and a $2.6 million change in cash flow from operating activities
(net of $1.3 million in costs associated with natural gas purchased for steam
generation). The foregoing estimates do not give effect to changes in any other
factors, such as the effect of the Company's hedging program or its debt levels
and related interest expense, that might 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 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.

The Company has open crude hedges on an average of approximately 7,700
barrels per day for the period January to July 1997. The instruments used have
floors ranging from $21 to $23 per barrel and ceilings ranging from $24 to $27
per barrel. Under the terms of the instruments, if the aggregate average of the
applicable daily settlement prices is below the floor, the Company will receive
a settlement based on the difference, and if the aggregate average of the
applicable daily settlement prices is above the ceiling, the Company will be
required to pay an amount based on the difference. 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)
-------------------- ---------------------
27.00 (1.6)
26.00 (0.2)
25.00 (0.1)
23.00 - 24.00 --
22.00 0.3
21.00 1.1
20.00 2.7

Crude oil hedges resulted in a $13.4 million decrease in revenues in 1996
and a $2.4 million increase in revenues in 1995.

The Company has no open natural gas hedges. In 1996 and 1995 natural gas
hedges resulted in decreases in revenues of $21.4 million and $0.3 million,
respectively.

In addition to its oil and gas sales hedges, for the first six months of
1996 the Company 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.
Such hedges resulted in a $3.2 million increase in 1996 production and operating
costs.

In February 1996 the Bureau of Land Management ("BLM") of the United
States Department of the Interior (which operates the Company's leases of
Federal lands) agreed, effective as of June 1, 1996, to reduce the royalties
payable on any Federal lease that produces heavy oil. As a result of this

program, the Company's royalty rate on its Federal leases which produce heavy
oil (all of which are operated by Monterey) has been reduced from 12.5% to an
average of 4.8%, resulting in a net increase in the production attributable to
the Company's net revenue interests in such leases of approximately 1,600
barrels per day. The royalty reduction will be terminated upon the first to
occur of (i) the determination by the BLM that the WTI average oil price (as
adjusted for inflation) has remained above $24 per barrel for six consecutive
months and (ii) such time after September 10, 1999, as the Secretary of the
Interior determines that the heavy oil royalty rate reduction has not produced
the intended results (i.e., to reduce the loss of otherwise recoverable
reserves).

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,
-------------------------------
1996 1995 1994
--------- --------- ---------
CRUDE OIL AND LIQUIDS PRODUCED
REVENUES ($ MILLIONS)
Sales
Domestic
California Heavy........... 251.4 193.9 161.8
Other...................... 165.3 115.9 104.3
--------- --------- ---------
416.7 309.8 266.1
Argentina..................... 25.8 13.8 11.6
Indonesia..................... 29.5 30.8 31.3
Hedging......................... (13.4) 2.4 --
Net Profits Payments............ (3.2) (4.4) (3.8)
--------- --------- ---------
455.4 352.4 305.2
========= ========= =========
VOLUMES (MBBLS/DAY)
Domestic
California Heavy.............. 43.5 38.9 38.3
Other......................... 22.8 19.6 19.3
--------- --------- ---------
66.3 58.5 57.6
Argentina....................... 3.7 2.6 2.4
Indonesia....................... 4.3 5.2 5.7
--------- --------- ---------
74.3 66.3 65.7
========= ========= =========
SALES PRICES ($/BBL)
Domestic
California Heavy.............. 15.77 13.65 11.57
Other......................... 19.84 16.24 14.83
Total......................... 17.17 14.52 12.66
Argentina....................... 19.06 14.72 13.23
Indonesia....................... 18.92 16.10 15.09
Total........................... 17.36 14.65 12.89
Total Hedged.................... 16.87 14.75 12.89
NATURAL GAS PRODUCED
REVENUES ($ MILLIONS)
Sales
Domestic...................... 122.2 73.3 87.2
Foreign....................... 9.8 5.5 0.1
--------- --------- ---------
132.0 78.8 87.3
Hedging......................... (21.4) (0.3) (1.0)
Net Profits Payments............ (4.8) (1.4) (2.9)
--------- --------- ---------
105.8 77.1 83.4
========= ========= =========
VOLUMES (MMCF/DAY)
Domestic........................ 145.7 137.7 136.3
Foreign......................... 21.2 12.3 0.3
--------- --------- ---------
166.9 150.0 136.6
========= ========= =========
SALES PRICES ($/MCF)
Unhedged
Domestic...................... 2.29 1.46 1.75
Foreign....................... 1.27 1.22 0.99
Total......................... 2.16 1.44 1.75
Hedged.......................... 1.81 1.43 1.73

Total revenues increased 30% from $449.4 million in 1995 to $583.3 million
in 1996. Revenues from the sales of crude oil and liquids produced increased
$103.0 million, primarily reflecting increased sales prices ($65.6 million) and
increased volumes ($52.1 million). Such increases were partially offset by a
$13.4 million hedging loss in 1996 compared to a $2.4 million hedging gain in
1995. Crude oil and liquids sales volumes increased 8.0 MBbls per day primarily
due to capital spending on the Company's heavy oil properties (3.5 MBbls per
day), reduced royalties on Federal heavy oil leases (1.0 MBbls per day) and new
domestic production and acquired interests in certain producing properties (3.4
MBbls per day).

Revenues from the sales of natural gas produced increased $28.7 million,
primarily reflecting increased sales prices ($39.5 million) and increased
volumes ($13.7 million). Such increases were partially offset by a $21.4 million
hedging loss in 1996 compared to a loss of $0.3 million in 1995. Domestic
natural gas sales volumes increased 8.0 MMcf per day primarily reflecting new
production partially offset by declines in production from more mature fields.
The increase in international sales volumes primarily reflects a full year's
production from the Company's Sierra Chata field in Argentina, which commenced
production in April 1995, and increased demand for the Argentine natural gas.

Revenues from the sales of crude oil purchased relate to the sale of crude
oil purchased and blended with certain of the Company's heavy oil production to
facilitate pipeline transportation. The cost to purchase such crude oil is
included in Costs and Expenses. The increase in 1996 reflects an increase in
blending to transport heavy oil to more attractive markets outside southern
California.

Total revenues increased 11% from $404.2 million in 1994 to $449.4 million
in 1995. Crude oil and liquids revenues increased $47.2 million, primarily
reflecting the effect of increased sales prices ($44.3 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 $449.5 million in 1993 to $404.2 million
in 1994. Crude oil and liquids revenues declined $10.2 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 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 due to low prices resulted in a reduction in 1994 volumes of
approximately 5.1 MMcf per day and a prior period adjustment included in 1993
represented volumes of approximately 4.0 MMcf per day.

COSTS AND EXPENSES

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

1996 1995 1994
--------- --------- ---------
Production and operating (a)......... 5.02(f) 4.65 4.65
Exploration, including dry hole
costs.............................. 0.92 0.70 0.63
Depletion, depreciation and
amortization (b)................... 3.89 3.96 3.76
General and administrative........... 0.67(g) 0.81 0.85
Taxes other than income (c).......... 0.71 0.58 0.80
Interest, net (d)(e)................. 0.82 0.93 1.08

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

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

(b) Excludes effect of unproved property writedowns of $0.07 per BOE in 1996
and $0.03 per BOE in 1995.

(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.

(f) Excludes effect of $0.9 million charge for environmental clean-up costs
($0.02 per BOE).

(g) Excludes effect of $1.6 million charge related to the abandonment of an
office lease and $3.3 million in costs and expenses related to the IPO
($0.14 per BOE).

Costs and expenses totalled $493.8 million in 1996 compared to $395.5
million in 1995. Production and operating costs increased $32.6 million,
primarily reflecting higher production volumes, $3.2 million in expenses related
to hedges of natural gas purchased in connection with steam generation
operations in California (see -- General) and higher volumes and prices for
natural gas purchased in connection with such steam generation operations. The
cost of crude oil purchased increased primarily due to increased blending
activity (see -- REVENUES). The $11.1 million increase in exploration costs
primarily reflects higher geological and geophysical expenditures ($6.4 million)
and higher dry hole costs ($5.7 million). The increase in depletion,
depreciation and amortization ("DD&A") primarily reflects higher production
volumes. The impairments of oil and gas properties of $57.4 million in 1996 and
$30.2 million in 1995 represent writedowns taken in accordance with the
Company's accounting policy discussed in Note 1 to the Consolidated Financial
Statements. The increase in general and administrative expense primarily
reflects $3.3 million in expenses related to the IPO. The increase in taxes
other than income primarily reflects higher production and severance taxes due
to higher prices and volumes ($2.7 million) and higher ad valorem taxes. Taxes
other than income in 1995 included a $0.7 million benefit related to the
settlement of certain disputed sales and use taxes. The gain on disposition of
properties in 1996 includes a $12.3 million gain on the fourth quarter sale of
certain surface properties in Orange County, California.

Costs and expenses totalled $395.5 million in 1995 compared to $356.0
million in 1994. 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 high level of capital
expenditures in 1995. 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 $356.0 million compared to $562.5
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.

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 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.

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.

Income taxes for 1996 include a $8.3 million deferred tax benefit related
to certain foreign expenditures incurred in prior periods. 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.

The extraordinary item reported in 1996 represents costs and expenses
associated with the retirement of certain of the Company's debt in association
with the IPO. See Note 2 to the Consolidated Financial Statements.

The Company's preferred dividend requirement for 1996 includes a $33.7
million premium related to the purchase of 3.8 million shares of the Company's
Convertible Preferred Stock, 7% Series. The increase in the Company's preferred
dividend requirement in 1994 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 has elected to continue to account for
stock-based compensation in accordance with

Opinion 25 and the pro forma disclosures in accordance with the provisions of
FAS 123 are included in Note 12 to the Consolidated 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 33% over the five years
ended December 31, 1996; 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 totalled $244.3 million in 1996; net cash used for capital
expenditures and producing property acquisitions in such period totalled $223.5
million.

The increase in accounts receivable in 1996 primarily reflects the effect
of higher sales prices and an increase in crude oil blending activity, partially
offset by the collection of the income tax refund discussed below. The increase
in other current assets primarily reflects an increase in advances to the
operators of joint interest oil and gas properties due to higher capital
spending and the note receivable associated with the sale of certain surface
property. Other assets at December 31, 1996 includes $24.2 million in escrowed
funds related to a producing property acquisition the Company completed in
January 1997. The increase in accounts payable at year end 1996 primarily
reflects an increase in capital projects in progress and increased crude oil
blending activity. The increase in income taxes payable in 1996 primarily
reflects current taxes associated with the contribution of assets to Monterey
and the Proposed Spin Off. The increase in other current liabilities reflects
higher advances received from joint interest partners.

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
accounts 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.

Monterey intends to pay its shareholders a quarterly dividend of $0.15 per
share. The first dividend has been declared and will be paid in April 1997
consisting of a prorated dividend of $0.22 per share in respect of Monterey's
first partial quarter which ended December 31, 1996 and its first full quarter
ending March 31, 1997. Santa Fe will receive a total of approximately $10.0
million with respect to the 45.4 million shares that it currently holds. To the
extent Monterey continues to pay such dividends, Santa Fe will receive dividends
of approximately $6.8 million per quarter (assuming a quarterly dividend of
$0.15 per share) until the Proposed Spin Off is consummated. Such amounts would
be available to fund the Company's operations, other than those conducted by
Monterey.

Effective November 13, 1996 Santa Fe entered into a revolving credit
agreement (the "Santa Fe Credit Agreement") which matures November 13, 2001.
The Santa Fe Credit Agreement permits the Company to obtain revolving credit
loans and issue letters of credit up to an aggregate amount of up to $150.0
million, with the aggregate amount of letters of credit outstanding at any time
limited to $30.0 million. Borrowings under the Santa Fe Credit Agreement are
unsecured and interest rates are tied to

the bank's prime rate or eurodollar offering rate, at the option of the Company.
At December 31, 1996, no loans or letters of credit were outstanding under the
terms of the Santa Fe Credit Agreement.

Effective November 13, 1996 Monterey entered into the Monterey Credit
Agreement which matures November 13, 2000. The Monterey Credit Agreement permits
Monterey to obtain revolving credit loans and issue letters of credit up to an
aggregate amount of up to $75.0 million, with the aggregate amount of letters of
credit outstanding at any time limited to $15.0 million. Borrowings under the
Monterey Credit Agreement are unsecured and interest rates are tied to the
bank's prime rate or eurodollar offering rate, at the option of Monterey. At
December 31, 1996 no loans or letters of credit were outstanding under the terms
of the Monterey Credit Agreement.

In November 1996 Monterey issued the Monterey Senior Notes which were
exchanged for $175.0 million of senior notes previously issued by Santa Fe. The
Monterey Senior Notes bear interest at 10.61% per annum and are payable in full
in 2005. Monterey is required to repay, without premium, $25.0 million of the
principal amount each year from 1999 through 2005.

Certain of the credit agreements and the indenture for the Debentures
include covenants that restrict Santa Fe and Monterey'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, 1996 Santa Fe could incur up to $417.7 million of additional
indebtedness and pay dividends of up to $36.8 million on its aggregate capital
stock (including its common stock, 7% Convertible Preferred Stock and Series A
Preferred). At December 31, 1996, under the most restrictive of these covenants,
Monterey could incur up to $253.4 million of additional indebtedness and pay
dividends of $61.7 million on its common stock. Monterey is prohibited from
paying more than $31.0 million in dividends to Santa Fe in any fiscal year prior
to the consummation of the Proposed Spin Off.

The Company has three short-term uncommitted lines of credit totalling
$60.0 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, 1996 $4.0 million was outstanding under these
lines of credit.

At December 31, 1996 the Company had outstanding letters of credit
totalling $6.0 million, $2.3 million of which related to the operations of
Monterey.

INITIAL PUBLIC OFFERING AND PROPOSED SPINOFF

In the third quarter of 1996 the Company announced its intention to
separate its operations in the State of California from the rest of its domestic
and international operations. In November such operations were assumed by
Monterey which subsequently issued 9.3 million shares of its common stock in an
initial public offering. The proceeds from the offering were primarily used to
retire certain of the Company's then outstanding long-term debt. See Items 1 and
2. Business and Properties -- MONTEREY RESOURCES, INC.

The Company has announced that it intends to distribute pro rata to its
common shareholders all of its remaining ownership interest in Monterey by means
of a tax-free distribution. The Proposed Spin Off is subject to certain
conditions including, the receipt of a ruling from the Internal Revenue Service
that such a distribution would be tax-free, the approval of such distribution by
the Company's common shareholders, the absence of any future change in the
market or economic conditions (including developments in the capital markets) or
the Company's or Monterey's business or financial condition that causes the
Company's Board of Directors to conclude that the Proposed Spin Off is not in
its shareholders' best interests and the final declaration of the Proposed Spin
Off by the Company's Board of Directors. The Proposed Spin Off is not expected
to occur prior to July 1997.

The Company is taking these actions because of its belief that its oil and
gas operations have developed over time into separate businesses that operate
independently and have diverging capital requirements and risk profiles. In
addition, the Board of Directors believes that dividing the Company's operations
into two independent companies will allow each to more efficiently develop its

distinct resource base and pursue separate business opportunities while
providing each with improved access to capital markets. The Board of Directors
also believes that the IPO and the Proposed Spin Off will allow investors to
better evaluate each business, enhancing the likelihood that each would achieve
appropriate market recognition for its performance. If the Proposed Spin Off
occurs, the market price of the Company's common stock will decline to reflect
the distribution of the Monterey common stock and the increased shares available
in the market may have an adverse effect on the market price of Monterey's
common stock.

Also in November, the Company completed the purchase of 3.8 million of the
5.0 million outstanding shares of its Convertible Preferred Stock, 7% Series,
for $24.50 per share, net to the seller in cash. The Company made the offer
because it believes that the goals of the Proposed Spin Off can be better
achieved by reducing the number of preferred shares outstanding and simplifying
the Company's capital structure.

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 -- SANTA FE
CONSOLIDATED -- Other Business Matters -- Environmental Regulation" and Note 14
to the Consolidated Financial Statements.

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.

FORWARD LOOKING STATEMENTS

In its discussion and analysis of financial condition and results of
operations, the Company has included certain statements (other than statements
of historical fact) that constitute forward-looking statements within the
meaning of Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934. When used herein, the words "budget,"
"budgeted," "anticipate," "expects," "believes," "seeks," "goals,"
"intends" or "projects" and similar expressions are intended to identify
forward-looking statements. It is important to note that the Company's actual
results could differ materially from those projected by such forward-looking
statements. Although the Company believes that the expectations reflected in
such forward-looking statements are reasonable and such forward-looking
statements are based upon the best data available at the time this report is

filed with the Securities and Exchange Commission, no assurance can be given
that such expectations will prove correct. Factors that could cause the
Company's results to differ materially from the results discussed in such
forward-looking statements include, but are not limited to, the following:
production variances from expectations, volatility of oil and gas prices, the
need to develop and replace its reserves, the substantial capital expenditures
required to fund its operations, exploration risks, environmental risks,
uncertainties about estimates of reserves, competition, government regulation
and political risks, and the ability of the Company to implement its business
strategy. All such forward-looking statements in this document are expressly
qualified in their entirety by the cautionary statements in this paragraph.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

PAGE
----
Audited Financial Statements
Report of Independent
Accountants ............................................................... 63
Consolidated Statement of
Operations for the years
ended December 31, 1996,
1995 and 1994 ............................................................. 64
Consolidated Balance Sheet
- -- December 31, 1996 and
1995 ...................................................................... 65
Consolidated Statement of
Cash Flows for the years
ended December 31, 1996,
1995 and 1994 ............................................................. 66
Consolidated Statement of
Shareholders' Equity for
the years ended December
31, 1996, 1995 and 1994 ................................................... 67
Notes to Consolidated
Financial Statements ...................................................... 68

Unaudited Financial Information
Supplemental Information
to Consolidated Financial
Statements ................................................................ 91

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

None.

PART III

ITEMS 10, 11, 12 AND 13. DIRECTORS AND EXECUTIVE OFFICERS, EXECUTIVE
COMPENSATION, SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT AND CERTAIN RELATIONSHIPS AND
RELATED TRANSACTIONS.

EXECUTIVE OFFICERS OF SANTA FE

Listed below are the names, ages (as of February 1, 1997) 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
or her successor is elected or appointed or until his or her earlier death,
resignation or removal.

HUGH L. BOYT, 51 Senior Vice President -- Production since March 1, 1990.
From 1989 until March 1990, Mr. Boyt served as Corporate Production Manager.

JERRY L. BRIDWELL, 53 Senior Vice President -- Exploration and Land since
1986.

JANET F. CLARK, 42 Vice President and Chief Financial Officer since January
1997. Ms. Clark was with Southcoast Capital Corporation from January 1994
until she joined Santa Fe. While with Southcoast Capital Ms. Clark served as
Vice President from January 1994 to June 1996 and as Director, Corporate
Finance, from June 1996 to December 1996. From December 1992 to January 1994
Ms. Clark served as Senior Vice President with Williams MacKay Jordan &
Company. Prior to December 1992 Ms. Clark was an independent financial
consultant.

E. EVERETT DESCHNER, 56 Vice President -- Engineering and Evaluation since
April 1990.

KATHY E. HAGER, 45 Vice President -- Public Affairs since January 1997.
From January 1994 to January 1997 Ms. Hager served as Director, Investor
Relations and from September 1990 to January 1994 as Manager, Investor
Relations.

CHARLES G. HAIN, JR., 50 Vice President -- Human and Data Resources since
1994. Vice President -- Employee Relations from 1988 until 1994.

DAVID L. HICKS, 47 Vice President -- Law and General Counsel since March
1991.

DIRECTORS

CURRENT DIRECTORS. Listed below are the names and ages (as of February 1,
1997) of, and certain other information about, all the current directors of the
Company. The indicated periods of service as a director of the Company include
service during the time the Company was a wholly owned subsidiary of Santa Fe
Pacific Corporation.

FIRST ELECTED
NAME, AGE AND BUSINESS EXPERIENCE A DIRECTOR
- ------------------------------------- -------------

DIRECTORS CONTINUING IN OFFICE UNTIL 1997

Marc J. Shapiro, 49 ............................................. 1990
Chairman and Chief Executive
Officer of Texas Commerce Bank
National Association ("Texas
Commerce Bank") (banking) since
1987, and a member of the Policy
Council of Chase Manhattan
Corporation, (successor to the
Management Committee of Chemical
Banking Corporation) since December
1991. Mr. Shapiro is also a
director of Browning-Ferris
Industries, Burlington Northern
Santa Fe Corporation and a trustee
of Weingarten Realty Investors

William E. Greehey, 60 .......................................... 1991
Chairman of the Board, Chief
Executive Officer and director of
Valero Energy Corporation (refining
and marketing, gas transmission and
processing) since 1983. Mr. Greehey
is also a director of
Weatherford-Enterra

DIRECTORS CONTINUING IN OFFICE UNTIL 1998

Melvyn N. Klein, 55 ............................................. 1993
Attorney and Counselor at Law;
private investor; the sole
stockholder of a general partner in
GKH Partners, L.P. Mr. Klein is
also a principal of Questor
Management Company, and director of
Anixter International and Bayou
Steel Corporation (specialty steel
manufacturer)

James L. Payne, 59 .............................................. 1986
Chairman of the Board, President
and Chief Executive Officer of the
Company since June 1990. Mr. Payne
was President of Santa Fe Energy
Company, a predecessor in interest
of the Company from January 1986 to
January 1990 when he became
President of the Company. From 1982
to January 1986 Mr. Payne was
Senior Vice President--Exploration
and Land of Santa Fe Energy
Company. Mr. Payne is also a
director of Pool Energy Services
Co. (oilfield services), and
Monterey Resources, Inc.

DIRECTORS CONTINUING IN OFFICE UNTIL 1999

Allan V. Martini, 69 ............................................ 1990
Retired Vice President
Exploration/Production and director
of Chevron Corporation (petroleum
operations) since August 1988. Mr.
Martini served in that position
from July 1986 until his
retirement

(TABLE CONTINUED ON FOLLOWING PAGE)

FIRST ELECTED
NAME, AGE AND BUSINESS EXPERIENCE A DIRECTOR
- ------------------------------------- -------------

Reuben F. Richards, 67........................................... 1992
Chairman of the Board, Terra
Industries Inc. (argibusiness) from
December 1982 until retirement in
March 1996. Chief Executive Officer
thereof from December 1982 to May
1991 and President thereof from
July 1983 to May 1991; Chairman of
the Board, Engelhard Corporation
(specialty chemicals, engineered
materials and precious metals
management services) from May 1985
to December 1994 and director
thereof since prior to 1990;
Chairman of the Board, Minorco
(U.S.A.) Inc. ("Minorco (USA)"),
from May 1990 to March 1996 and
Chief Executive Officer and
President from February 1994 to
March 1996. Mr. Richards is also a
director of Ecolab, Inc. (cleaning
and sanitizing products), Engelhard
Corporation, Potlatch Corporation
(forest products), and Minorco.

Kathryn D. Wriston, 57........................................... 1990
For the past five years, director
of various corporations and
organizations, including
Northwestern Mutual Life Insurance
Company and the Stanley Works and a
Trustee of the Financial Accounting
Foundation.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. Since July 1, 1990, the
Company has entered into agreements with Texas Commerce Bank or affiliates
thereof providing for cash management, lending, depository and other banking
services in the normal course of business. Texas Commerce Bank also issued
standby letters of credit with various expiration dates for security and
environmental requirements totaling $4,206,854 as of December 31, 1996. Texas
Commerce Bank is also the Trustee of the Company's Retirement Income Plan.
Finally, effective November 19, 1992, the Company in return for cash contributed
certain oil and gas interests to the Santa Fe Energy Trust which in turn issued
Secure Principal Energy Receipts evidencing an interest in the Trust and a
United States Treasury Obligation. Texas Commerce Bank is the Trustee of the
Trust and acts as registrar and transfer agent of the Secure Principal Energy
Receipts. During 1996 the Company paid Texas Commerce Bank interest in the
amount of $76,144 for loans to the Corporation and fees for various services in
the amount of $320,798 (which does not include $34,274 paid from the Retirement
Income Plan Trust). In addition, Mr. Shapiro, a director of the Company, is
Chairman and Chief Executive Officer of Texas Commerce Bank. Mr. Shapiro has no
direct or personal interest in these banking arrangements. His interest arises
only because of his positions as an officer of Texas Commerce Bank and a
director of the Company. Mr. Shapiro has abstained from voting on any issues
involving the relationships between the Company and Texas Commerce Bank.

In the opinion of the Company, the fees paid to Texas Commerce Bank for the
services performed are normal and customary.

Mr. Shapiro is also a director of Burlington Northern Santa Fe Corporation
which, as a result of a business combination in September 1995, became the
successor in interest to SFP. In connection with the distribution of shares of
the Company's common stock by SFP (and the initial distribution in December 1989
to SFP by one of SFP's wholly owned subsidiaries of such shares) (collectively
the "SFP 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 SFP Spin Off was determined to be a taxable event
resulting primarily from actions taken by the Company during a one year period
that ended on 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 SFP
Spin Off.

For periods prior to the date of the SFP Spin Off, the Company was included
in the consolidated federal income tax return filed by SFP as the common parent
for itself and its subsidiaries. Pursuant to the Agreement for the Allocation of
the Consolidated Federal Income Tax Liability Among the Members of the SFP
Affiliated Group and various state agreements for the allocation of tax
liability among the SFP Group (the "Tax Agreements") between SFP and its
subsidiaries, the Company paid

to SFP an amount approximating the federal income tax liability and for years
1989 and 1990 the state income tax liability it would have paid if it and its
subsidiaries were members of separate consolidated groups. These amounts were
payable regardless of whether the SFP consolidated group, as a whole, had any
current federal or state income tax liability. Pursuant to the Agreement
Concerning Taxes between SFP and the Company, after the SFP Spin Off additional
payments to or refunds from SFP may be made if there is an audit, carryover or
similar adjustment subsequently made that impacts the computation of amounts
paid SFP as described above.

Mr. Shapiro has no direct or personal interest in the above described
transaction. His interest arose only because of his position as a director of
Burlington Northern Santa Fe Corporation and as a director of the Company.

Mr. Payne is also a director of Pool Energy Services Co. ("Pool") which
provides various oilfield services. During 1996 the Company and Monterey paid
Pool subsidiaries $7,094,573 for services performed on properties operated by
the Company or Monterey. Mr. Payne has no direct or personal interest in these
services. His interest arises only because of his position as an officer of the
Company and a director of Pool. In the opinion of the Company, the amounts paid
for services performed by Pool were competitive and were normal and customary in
the industry.

The Company entered into an Agreement Regarding Shelf Registration dated
March 24, 1995, with HC Associates ("HC") which owns more than 5% of the
Company's common stock whereby the Company agreed that upon written demand
(which demand may be submitted to the Company once, provided such registration
is effected and the registration statement is declared effective) from HC, GKH
Partners, L.P. ("GKH"), GKH Investments, L.P., Ernest H. Cockrell Texas
Testamentary Trust or Carol Cockrell Jennings Texas Testamentary (collectively,
the "Selling Stockholders") at any time prior to March 27, 2000 to file with
the Securities and Exchange Commission a registration statement to register the
offer and sale, from time to time, by the Selling Stockholders of up to
5,203,091 shares of the Company's common stock beneficially owned by them as of
March 24, 1995, subject to certain specified restrictions. The Company is
obligated to pay all expenses incidental to such registration, excluding
underwriting discounts, commissions, fees or disbursements of legal counsel for
the Selling Stockholders.

See also Report of the Compensation and Benefits Committee -- Compensation
Committee Interlocks and Insider Participation at page 53 and Security Ownership
of Certain Beneficial Owners at page 47.

With respect to certain fees which will be payable to affiliates of Texas
Commerce Bank and to GKH upon consummation of the Proposed Spin Off, see Note 2
to the Consolidated Financial Statements.

OTHER INFORMATION CONCERNING DIRECTORS. In 1996, the Board met eight
times, and each member of the Board as it was composed at the time attended at
least 75% of the total number of meetings of the Board and the total number of
meetings held by all committees of the Board on which he or she served.

DIRECTORS COMPENSATION. Directors who are not employees of the Company or
its subsidiaries receive an annual cash retainer fee of $10,000, a fee of $1,000
for each meeting of the Board attended, and a fee of $1,000 (an additional
$2,000 annual retainer for the committee Chairman) for each committee meeting
attended plus expenses for each Board or committee meeting attended. In
addition, on May 8, 1996, the shareholders of the Company approved an amendment
to the 1990 Incentive Stock Compensation Plan, as amended (the "Stock Plan")
whereby a portion of the annual retainer is paid in shares of the Company's
common stock as well as a grant of Non-Qualified Stock Options ("NQSOs).
Pursuant to this amendment non-employee directors receive as a portion of their
retainer 1,000 shares of common stock with a six-month restriction period during
which it may not be transferred and 5,000 NQSOs issued at Fair Market Value (as
defined in the Stock Plan) as of the date of the Annual Meeting of Shareholders.
Further, all newly elected directors receive a one-time grant of 10,000 NQSOs
with a

strike price of the Fair Market Value on the date the director is first elected.
Current directors received a similar one-time grant effective February 1, 1996,
the date the amendment to the Stock Plan was approved by the Board. Additional
terms and conditions relating to the NQSOs are described on page 52.

BOARD COMMITTEES. In 1996, the Board maintained Audit, Compensation and
Benefits, Executive, Nominating and Pension Committees. Following are the
members of each committee and brief descriptions of their functions. All
chairman of the committees are non-employee directors.

The members of the Audit Committee are Kathryn D. Wriston (Chairman), Marc
J. Shapiro and Melvyn N. Klein. The principal functions of the Audit Committee,
which met three times in 1996, include overseeing the performance and reviewing
the scope of the audit function of independent accountants. The Audit Committee
also reviews, among other things, audit plans and procedures, the Company's
policies with respect to conflicts of interest and the prohibition on the use of
corporate funds or assets for improper purposes, changes in accounting policies,
and the use of independent accountants for non-audit services.

The members of the Compensation and Benefits Committee are William E.
Greehey (Chairman), Kathryn D. Wriston and Reuben F. Richards. The principal
function of the Compensation and Benefits Committee, which met five times in
1996, is to administer all executive compensation and benefit plans of the
Company. Members of the Compensation and Benefits Committee are not eligible to
participate in any benefit plans of the Company that they administer except the
Stock Plan pursuant to which grants may be made only as described above. In
December 1996 the Pension Committee was abolished and its duties described below
were assumed by the Compensation and Benefits Committee.

The members of the Nominating Committee are Allan V. Martini (Chairman),
Kathryn D. Wriston and James L. Payne. The Nominating Committee, which met twice
in 1996, receives recommendations for review and evaluates the qualifications of
and selects and recommends to the Board of Directors, nominees for election as
Directors. The Nominating Committee will consider nominees recommended by
stockholders. Any such recommendation, together with the nominee's
qualifications and consent to be considered as a nominee, should be sent in
writing to the Secretary of the Company not less than 30 days nor more than 60
days prior to the annual meeting.

The members of the Executive Committee are Melvyn N. Klein (Chairman),
William E. Greehey, James L. Payne, Allan V. Martini and Reuben F. Richards. The
Committee, which met twice in 1996, may exercise during periods between meetings
of the Board of Directors, all powers of the Board in the management and
business of the Company subject to limitations imposed by the Bylaws,
Certificate of Incorporation or applicable law.

The members of the Pension Committee were a former director as Chairman,
James L. Payne and Allan V. Martini. The duties of the Pension Committee which
met once in 1996, included reviewing the actions of the Pension Administration
and Pension Investment Committees which are composed of Company employees,
making recommendations to the Board of Directors concerning future memberships
of such committees and such other recommendations as may be necessary or
appropriate, and recommending to the Board of Directors substantial amendments
to the Company's retirement plan which do not change benefit levels. The duties
of the Pension Committee were assumed by the Compensation and Benefits Committee
in December 1996.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS

To the best of the Company's knowledge, the following persons are the only
persons who are beneficial owners of more than five percent of the Company's
common stock, Convertible Preferred Stock, 7% Series, or $.732 Series A
Convertible Preferred Stock based upon the number of shares outstanding on
December 31, 1996:

NUMBER OF
NUMBER OF SHARES OF
SHARES OF $.732
NUMBER OF CONVERTIBLE SERIES A
SHARES OF PERCENT PREFERRED PERCENT CONVERTIBLE PERCENT
COMMON OF STOCK, OF PREFERRED OF
NAME AND ADDRESS STOCK(A) CLASS 7% SERIES CLASS STOCK CLASS
- ------------------------------------- ------------- ------- ------------ ------- --------- -------

HC Associates(b)..................... 5,203,091 5.7% -- -- % -- -- %
200 West Madison Street
27th Floor
Chicago, Illinois 60606
Neuberger & Berman, LLC(c)........... 4,535,168 5.0% -- -- % -- -- %
605 Third Ave.
New York, New York 10158
Merrill Lynch & Co., Inc.(d)......... 10,126,285 11.1% 64,393 5.0% 500,000 4.7%
World Financial Center, North Tower
250 Vesey Street
New York, NY 10281
OppenheimerFunds, Inc.(e)............ -- -- % -- -- % 825,000 7.7%
Two World Trade Center
Suite 3400
New York, New York 10048
FMR Corp.(f)......................... 9,388,321 10.3% -- -- % 2,498,800 23.4%
82 Devonshire Street
Boston, Massachusetts 02109

The holders of Convertible Preferred Stock, 7% Series, of which there are
1,229,890 shares outstanding, may, at their option, convert any or all such
shares into 1.3913 shares of the Corporation's common stock. Each share of $.732
Series A Convertible Preferred Stock, of which there are 10,700,000 shares
outstanding, is convertible at the option of the holder into 0.8474 shares of
the Corporation's common stock at any time prior to May 15, 1998.
- ------------

(a) Each holder has claimed sole voting and investment power concerning these
shares except as noted below. The number of shares of common stock does not
include shares issuable upon conversion of preferred stock.

(b) As reported at May 31, 1995, HC Associates, a Delaware general partnership
("HC") is the owner of 5,203,091 shares (approximately 5.7 percent) of the
common stock of the Corporation. HC was organized in December 1992 for the
purpose of, among other things, acquiring, holding, selling, exchanging and
otherwise dealing with shares of the Corporation's common stock. The
partners of HC (and their respective percentage interests in HC) are GKH
Investments, L.P. (the "Fund") (92.743659 percent), GKH Partners, L.P., as
nominee for GKH Private Limited (3.506491 percent), Ernest H. Cockrell Texas
Testamentary Trust (1.874963 percent) and Carol Cockrell Jennings Texas
Testamentary Trust (1.874965 percent). The sole general partner of the Fund,
a Delaware limited partnership is GKH Partners, L.P. ("GKH"), a Delaware
limited partnership. Pursuant to a management agreement, GKH manages assets
on behalf of GKH Private Limited ("GKHPL"). The number of shares described
above do not include 39,100 shares of common stock acquired in September
1994 by GKH on behalf of GKHLP and the Fund. The general partners of GKH are
JAKK Holding Corp., a Nevada corporation ("JAKK"), DWL Lumber Corporation,
a Delaware corporation ("DWL"); and HGM Associates Limited Partnership, an
Illinois limited partnership ("HGMLP"). The sole general partner of HGMLP
is HGM Corporation, a Nevada corporation ("HGM"). Melvyn N. Klein is the
sole director and stockholder of JAKK and serves as its president, treasurer
and secretary. Mr. Klein disclaims beneficial ownership of the shares of
common stock owned by HC, GKH, GKHLP and the Fund. Dan W. Lufkin is

(FOOTNOTES CONTINUED ON FOLLOWING PAGE)

president, director and sole stockholder, Craigh Leonard is secretary and a
director and Douglas J. McBride is assistant secretary and a director of
DWL. Jay A. Pritzker is a director and Chairman of the Board, Thomas J.
Pritzker is president and a director, Glen Miller is vice president and
treasurer and Harold S. Handelsman is vice president and secretary of HGM.

(c) As reported at February 13, 1997, Neuberger & Berman LLC is deemed to be a
beneficial owner of these shares for the purpose of Rule 13(d) since it has
shared power to make decisions whether to retain or dispose of the
securities of many unrelated clients. Neuberger & Berman, LLC does not
however have any economic interest in the securities of these clients. The
clients are the actual owners of the securities and have the sole right to
receive and the power to direct the receipt of dividends from or proceeds
from the sale of such securities.

Principals of Neuberger & Berman, LLC own 438,700 shares of the Company's
common stock. The principals own these shares in their own personal
securities accounts, Neuberger & Berman, LLC disclaims beneficial ownership
of these shares since they were purchased with each principals' personal
funds and each principal has exclusive dispositive and voting power over the
shares held in their respective accounts.

Neuberger & Berman Profit Sharing Retirement Plan owns 290,100 shares. Such
shares are held in a securities account in the name of the Plan with
Neuberger & Berman, LLC and are held in street name. The Plan's sole
beneficial owners are current and former Neuberger & Berman, LLC employees
and Principals who are Plan participants. Neuberger & Berman Trust Company
(a wholly owned affiliate of Neuberger & Berman, LLC) is trustee of the
Plan. One Principal of Neuberger & Berman, LLC makes day to day investment
decisions for the Plan. Neuberger & Berman, LLC disclaims beneficial
ownership of these shares.

(d) As reported at February 11, 1997, Merrill Lynch & Co., Inc., a Delaware
corporation ("ML & Co."), Merrill Lynch Group, Inc., a Delaware
corporation ("ML Group"), whose address is World Financial Center, North
Tower, 250 Vesey Street, New York, N.Y. 10281, and Princeton Services, Inc.,
a Delaware corporation ("PSI"), whose address is 800 Scudders Mill Road,
Plainsboro, N.J. 08536, are parent holding companies pursuant to Section
240, 13d-1 (b)(1)(ii)(G) of the Securities Exchange Act of 1934 (the
"Exchange Act"). The relevant subsidiaries of ML & Co. are Merrill Lynch
Pierce, Fenner & Smith Incorporated, a Delaware corporation with its
principal place of business at 250 Vesey Street, New York, N.Y.
("MLPF&S"), ML Group and PSI, which is the general partner of Merrill
Lynch Asset Management, L. P. (d/b/a) Merrill Lynch Asset Management
("MLAM"). The relevant subsidiaries of Merrill Lynch Group are PSI and
certain Merrill Lynch trust companies.

ML & Co. may be deemed to be the beneficial owner of the reported securities
of the Company as set forth by virtue of its control of its wholly-owned
subsidiaries, ML Group and MLPF&S.

MLPF&S, a wholly owned direct subsidiary of ML & Co. and a broker-dealer
registered pursuant to the Exchange Act holds certain of the reported
securities in proprietary trading accounts and may be deemed to be the
beneficial owner of securities held in customer accounts over which MLPF&S
has discretionary power and in unit investment trusts for which MLPF&S is
the sponsor.

ML Group, a wholly owned direct subsidiary of ML & Co., may be deemed to be
the beneficial owner of the reported securities of the Corporation as set
forth by virtue of its control of (i) its wholly-owned subsidiary, PSI, and
(ii) certain Merrill Lynch trust companies, each of which is a wholly-owned
subsidiary of ML Group and a bank as defined in Section 3(a)(6) of the
Exchange Act.

One or more Merrill Lynch trust companies or institutions, each of which is
a bank as defined in Section 3(a)(6) of the Exchange Act, may be deemed the
beneficial owner of certain of the reported securities of the Company held
by customers in accounts over which such trust companies or institutions
have discretionary authority.

PSI, a wholly owned direct subsidiary of ML Group, may be deemed to be the
beneficial owner of certain of the reported securities of the Company as set
forth by virtue of its being the general partner of MLAM.
MLAM, a Delaware limited partnership with its principal place of business at
800 Scudders Mill Road, Plainsboro, New Jersey, is an investment advisor
registered under Section 203 of the Investment Advisors Act of 1940. MLAM
may be deemed to be the beneficial owner of certain of the reported
securities of the Company as set forth by virtue of its acting as investment
advisor to one or more investment companies registered under Section 8 of
the Investment Company Act of 1940, and/or to one or more private
accounts.

A registered investment company advised by MLAM, Merrill Lynch Growth Fund
for Investment for Retirement is the beneficial owner of 9,000,000 shares of
the Company's common stock as reported and is a reporting person
hereunder.

Pursuant to Section 240.13d-4 of the Exchange Act, ML&Co., ML Group and PSI
disclaim beneficial ownership of the securities of the Corporation reported,
and the filing of a Schedule 13G shall not be construed as an admission that
such entity is, for purposes of Section 13(d) or 13(g) of the Exchange Act,
the beneficial owner of any of the securities of the Company.

(e) As reported at February 10, 1997, the Board of Directors or Trustees of the
registered investment companies managed by Oppenheimer Funds, Inc. ("OFI")
and owning the shares of the Corporation's $.732 Series A Convertible
Preferred Stock shown can direct the disposition of dividends received by
OEIF and can dispose of such securities. Additionally, OFI shares the power
to dispose of such securities with the Board of Directors or Trustees of
such funds; however, the Board of Trustees of such funds have delegated
these responsibilities to OFI as the fund's investment advisor under its
investment advisory agreement. OFI has an interest relating to 7.5% of the
securities noted by virtue of the interest of 7.5% of such securities owned
by OEIF. OFI disclaims ownership of such securities except as expressly
stated above.

(f) As reported at February 14, 1997, as of December 31, 1996, Fidelity
Management & Research Company ("Fidelity"), 82 Devonshire Street, Boston,
Massachusetts 02109, a wholly-owned subsidiary of FMR Corp. and an
investment advisor registered under Section 203 of the Investment Advisors
Act of 1940, is the beneficial owner of 8,980,198 or 9.9% of the common
stock and 1,879,600 shares or 17.6% of the $.732 Series A Convertible
Preferred Stock of the Company as a result of acting as an investment
advisor to various investment companies registered under Section 8 of the
Investment Company Act of 1940.

Edward C. Johnson 3d, FMR Corp., through its control of Fidelity, and the
funds each has sole power to dispose of the 8,980,198 shares of common stock
and 1,879,600 shares of Preferred Stock owned by the funds. Neither FMR
Corp. nor Edward C. Johnson 3d, Chairman of FMR Corp., has the sole power to
vote or direct the voting of the shares owned directly by the Fidelity
Funds, which power resides with the Funds' Board of Trustees. Fidelity
carries out the voting of the shares under written guidelines established by
the Funds' Boards of Trustees.

Fidelity Management Trust Company, 82 Devonshire Street, Boston,
Massachusetts 02109, a wholly-owned subsidiary of FMR Corp., and a bank as
defined in Section 3(a)(6) of the Securities Exchange Act of 1934, is the
beneficial owner of 408,123 shares or less than 1% of the common stock and
619,200 shares or 5.8% of the $.732 Series A Convertible Preferred Stock of
the Company as a result of its serving as an investment manager of the
institutional accounts. Edward C. Johnson 3d and FMR Corp., through its
control of Fidelity Management Trust Company, each has sole dispositive
power over these shares, the sole power to vote or direct the vote over a
portion of the shares and no power to vote or direct the voting of the
balance of such shares.

Members of the Edward C. Johnson 3d family and trusts for their benefit are
the predominant owners of Class B shares of common stock of FMR corp.,
representing approximately 49% of the voting power of FMR Corp. Mr. Johnson
3d owns 12.0% and Abigail Johnson owns 24.5% of the aggregate outstanding
voting stock of FMR Corp. Mr. Johnson 3d is Chairman of FMR Corp. and
Abigail P. Johnson is a Director of FMR Corp. The Johnson family group and
all other Class B shareholders have entered into a shareholders' voting
agreement under which all Class B shares will be voted in accordance with
the majority vote of Class B shares. Accordingly, through their ownership of
voting common stock and the execution of the shareholders' voting agreement,
members of the Johnson family may be deemed, under the Investment Company
Act of 1940, to form a controlling group with respect to FMR Corp.

STOCK OWNERSHIP OF DIRECTORS AND EXECUTIVE OFFICERS

The following table sets forth the amount of common stock beneficially
owned as of February 1, 1997 by each of the directors, by each of the executive
officers, and by all directors and executive officers as a group. Unless
otherwise noted, each of the named persons and members of the group has sole
voting and investment power with respect to the shares shown. No individual
listed below, except Mr. Payne, beneficially owns one percent or more of the
Company's outstanding common stock. In addition, no individual listed below
beneficially owns any shares of Convertible Preferred Stock, 7% Series. With the
exception of Mr. Payne, no individual listed below owns any $.732 Series A
Convertible Preferred Stock.

SHARES
NAME OF DIRECTOR, OWNED PERCENT
EXECUTIVE OFFICER OR GROUP BENEFICIALLY OF CLASS
- ------------------------------------- ------------ --------
William E. Greehey................... 49,726 --
Melvyn N. Klein(a)................... 5,063,203 5.6%
Allan V. Martini..................... 22,907 --
Reuben F. Richards................... 21,387 --
Marc J. Shapiro...................... 26,707 --
Kathryn D. Wriston................... 21,629 --
James L. Payne(b).................... 946,277 1.0%
Jerry L. Bridwell(c)................. 366,985 --
Hugh L. Boyt(d)...................... 280,314 --
R. Graham Whaling(e)................. 20,627 --
Directors and Executive Officers as a
Group(f)........................... 7,269,102 7.8%

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

(a) Includes 5,048,083 shares of common stock which may be deemed to be owned by
GKH primarily through its participation in HC Associates. See "Security
Ownership of Certain Beneficial Owners" for a description of ownership of
the Corporation's common stock by HC Associates. Mr. Klein is the sole
stockholder of one of the general partners in GKH Partners, L. P., the
general partner of GKH Investments, L. P. and the nominee for GKH Private
Limited and disclaims beneficial ownership of the shares held by HC
Associates. Also includes 15,000 shares which could be received upon the
exercise of options within 60 days. The weighted average exercise price of
such options is $10.2292.

(b) Mr. Payne's common stock ownership includes 47,906 shares arising from
participation in the Corporation's Savings Investment Plan and 722,890
shares which could be received upon the exercise of options within 60 days.
The weighted average exercise price of such options is $12.7344. In
addition, Mr. Payne owns 3,000 shares of $.732 Series A Convertible
Preferred Stock.

(c) Mr. Bridwell's common stock ownership includes 36,676 shares arising from
participation in the Corporation's Savings Investment Plan and 273,839
shares which could be received upon the exercise of options within 60 days.
The weighted average exercise price of such options is $13.5447.

(d) Mr. Boyt's common stock ownership includes 6,455 shares arising from
participation in the Company's Savings Investment Plan and 225,245 shares
which could be received upon the exercise of options within 60 days. The
weighted average exercise price of such options is $11.5275.

(e) Mr. Whaling's common stock ownership includes 1,459 shares arising from
participation in the Corporation's Savings Investment Plan.

(f) The common stock ownership described includes 115,977 shares arising from
participation in the Company's Savings Investment Plan as of February 1,
1997 and 1,649,805 shares which could be received upon the exercise of
options within 60 days.

REPORT OF THE COMPENSATION AND BENEFITS COMMITTEE

The Compensation and Benefits Committee (the "Committee") has been
chartered by the Board to review salaries and other compensation of officers,
including Mr. Payne, the Company's Chief Executive Officer, and key employees on
an annual basis. Following review, the Committee submits recommendations to the
Board regarding such salaries and compensation. In addition, the Committee
selects officers and key employees for participation in incentive compensation
plans, establishes performance goals for those officers and key employees who
participate in such plans and reviews and monitors benefits under all employee
plans of the Company.

Although Mrs. Wriston appears below as a member of the Committee, she was
appointed as such in December 1996 and did not participate as a member in any
meetings held during 1996.

COMPENSATION POLICIES FOR EXECUTIVE OFFICERS

As a result of an extensive review undertaken in 1995 with the assistance
of Hay Management Consultants, a performance-based executive compensation
program was developed. The Committee believes the program is competitive,
reinforces the Company's business strategy and supports objectives for enhanced
shareholder value. It is designed to attract, retain and motivate key employees
by providing total compensation opportunities consistent with those maintained
by the Company's peer group. The group used for this purpose includes companies
from the peer graph on page 58 which the Committee believes approximate the
Company's size and asset mix. The program allows compensation to vary
significantly based on performance results, balance objectives for short-term
operating performance with longer term performance, and encourage stock
ownership among key employees.

Base salaries for the executive group are maintained near the median
competitive position for comparable positions among the peer group. Annual
incentive opportunities are targeted to provide compensation between a median
and upper quartile of the Company's peer group described above. Long-Term
incentive opportunities are provided through grants of stock options and Phantom
Units made pursuant to the Stock Plan and are targeted between median and upper
quartile award levels with upside opportunities based on sustained performance
and creation of shareholder value.

As a result of the review of the peer group undertaken in 1996 and in light
of the proposed Spin-Off to Monterey Resources it was determined that no salary
increases be given to the executive officers in 1996. Mr. Whaling's salary was
increased in November 1996 by action of the Monterey Resources board in
recognition of his assumption of the duties of the Chairman of the Board and
Chief Executive Officer of that company.

Annual incentives are provided through the Incentive Compensation Plan (the
"ICP Plan"). Goals are established which, if met at the target objective, will
result in the executive officer being paid 50 percent of the maximum amount for
which the individual is eligible. All executive officers participate in the ICP
Plan with maximum payout percentages in 1996 (before the possible adjustments
discussed below) of base salary ranging from 100 percent for Mr. Payne through
50 percent for all other executive officers. The Committee may increase or
decrease the ultimate award by 25 percent at its discretion. In addition, by
electing to forgo all or a portion of the cash segment of the award a
participant may elect to receive an amount of Restricted Stock under the Stock
Plan equal to an additional $1 in value for each $2 of cash given up.

The goals established for 1996 were based upon discretionary cash flow per
share, production, reserve replacement, the performance of the Company's common
stock as compared to the peer group shown in the table on page 58, general and
administrative expense and a discretionary award. The awards were subject to
reduction by 50 percent in the event the Company failed to achieve net income to
common shareholders. Discretionary cash flow per share is defined as net cash
provided by operating activities before changes in operating assets and
liabilities minus exploration dry hole costs plus total exploration expense
minus capitalized interest minus preferred dividends by the average number of
common shares outstanding. Each goal was weighted equally with the exception of
general

and administrative expense and the discretionary award and with the exception of
the stock performance goal and discretionary award were compared against profit
plan projections. The discretionary cash flow, reserve replacement, production
and stock price performance goals were met in full. After deducting expenses
relating to the reconfiguration program undertaken in 1996 the general and
administrative expense goal was met in full and the entire amount of the
discretionary award was granted. Although the Company did not achieve net income
to common shareholders the Committee decided not to reduce the ultimate payout
since a positive net income would have resulted but for non-recurring expenses
relating to the reconfiguration program.

The payout of the awards under the ICP Plan were initially set to be made
75 percent in cash and 25 percent in Bonus Stock granted pursuant to the Stock
Plan. Participants were allowed to elect prior to the beginning of the 1996 Plan
year to forgo all or a portion of the cash payment in return for the receipt of
Restricted Stock on the basis of an additional $1 in value for each $2 of cash
given up. These shares are subject to forfeiture in certain events and will vest
one-third per year over a three-year period. The number of shares of Restricted
Stock granted to Mr. Payne and other executive officers listed in the Summary
Compensation Table on page 54 are described in a footnote to that table.

In addition to the above described cash and stock payments, the executive
officers and key employees are eligible to participate in other grants made
under the Stock Plan. In order to further the identity of interest of employees
with that of its stockholders, all forms of compensation under the Stock Plan
relate to the Company's common stock.

Prior to the Initial Public Offering of Monterey the Committee took action
to cause the acceleration of vesting of certain outstanding Non-Qualified Stock
Options ("NQSO's") and the payout of Phantom Units. NQSO's granted to
executive officers and key employees under the 1990 Incentive Stock Compensation
Plan prior to the July 1996 grant described below vested in full in September
1996. In addition, the Performance Units granted in 1996 paid out in shares of
the Company's common stock at the target level in November 1996.

As a result of this acceleration Mr. Payne received early vesting on
300,000 NQSO's with a strike price of $9.5625. The other executive officers
received early vesting on NQSO's ranging in amounts from 62,500 with a strike
price of $8.00 in the case of Mr. Whaling, 100,000 each with a strike price of
$9.5625 to several other executive officers to 12,666 each with a strike price
of $7.875 to several other executive officers. The early payout of the Phantom
Units resulted in the receipt by Mr. Payne of 34,355 shares of the Company's
common stock with the other individuals listed in the Summary Compensation Table
on page 54 receiving 9,375 shares of stock and the remaining individuals
participating in the grant receiving amounts ranging from 9,375 to 5,833.

In July 1996, as part of the strategy discussed above the Committee granted
Mr. Payne, the executive officers and other key employees NQSO's as noted in the
table located on page 56. In December 1996 the Company granted additional NQSO's
to Mr. Payne, selected executive officers and key employees in the amounts noted
in the table. All grants were made at fair market value and vest as to one-third
of the grant per year over a three-year period. The Committee did not accelerate
the vesting of these grants and the Proposed Spin Off of Monterey will not do
so.

Finally, also as part of the strategy discussed above in December 1996 the
Committee granted a total of 81,787 Performance Units to seventeen individuals
including Mr. Payne and the executive officers. Mr. Payne received 23,679
Phantom Units, the executive officers listed in the Summary Compensation Table
on page 54 (other than Messrs. Whaling and Rosinski) received 6,610 and the
remaining individuals participating in the grant received Units in amounts
ranging from 6,610 to 2,414. The Units are earned over a three-year period
commencing January 1, 1997 with ultimate payout if any to be made in an
equivalent number of shares of the Company's common stock. The Committee
established four equally weighted goals which must be attained over this
three-year period. Full payout will result if discretionary cash flow (as
described above) and production volumes equal the three-year projected levels
established by the 1997 profit plan, the Company's common stock price
performance (after deletion at the outset of the implied value of Monterey)
equals the S&P 500 Index over the three-

year period and the Company's common stock price at the end of the three years
equals an established target. If the above goals are substantially exceeded
possible payouts may increase by 100 percent. Failure to meet a threshold goal
level will result in the reduction or total elimination of a payout.

CHIEF EXECUTIVE COMPENSATION

The review of executive compensation discussed above included a review of
Mr. Payne's compensation. As in the case of the executive officers as a result
of the review of the peer group and in light of the Proposed Spin Off of
Monterey it was determined that Mr. Payne's salary not be increased in 1996. Mr.
Payne did receive a grant of 100,000 NQSOs with a strike price of $11.625 in
July and another grant of 125,000 NQSOs with a strike price of $13.75 in
December. Further as a result of the Committee action described above, the
vesting on 300,000 NQSOs with a strike price of $9.5625 was accelerated in
September and 34,355 Performance Units paid out early in the amount of an equal
number of shares of the Company's common stock.

SECTION 162 (M) OF THE INTERNAL REVENUE CODE OF 1986, AS AMENDED

The Committee continues to review implications of the $1 million pay cap
rules set forth in Section 162 (m) of the Internal Revenue Code of 1986, as
amended, and takes this into account when establishing and reviewing
compensation policies.

COMPENSATION AND BENEFITS COMMITTEE

William E. Greehey, Chairman
Reuben F. Richards
Kathryn D. Wriston

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

No member of the Compensation and Benefits Committee was an officer or
employee of the Company in 1994, 1995 or 1996. Mr. Greehey is Chairman of the
Board and Chief Executive Officer of Valero Energy Corporation. During 1996, an
affiliate of Valero paid the Company $635,841 for compression of natural gas.
These fees were determined on an arm's length basis. Mr. Greehey did not have a
direct or personal interest in the above transactions and his interest in the
above transactions and his interest arises only because of his position as an
officer and director of Valero and as a director of the Company.

Mr. Richards is the retired Chairman of the Board, Chief Executive Officer
and President of Minorco (USA) and is a director of its parent Minorco. On March
8, 1996, Minorco (USA) disposed of 8,712,327 shares of the Company's common
stock which it held. Pursuant to the terms of a registration rights agreement
dated December 10, 1991, and effective as of May 19, 1992, the Company paid
substantially all expenses incidental to the registration of these shares,
excluding underwriting discounts and commissions. Mr. Richards did not have a
direct or personal interest in this transaction and his interest arises only
because of his former position as an officer and director of Minorco (USA) and a
director of Minorco and the Company.

SUMMARY COMPENSATION TABLE

LONG-TERM
COMPENSATION
-------------
AWARDS PAYOUTS
SECURITIES ---------
ANNUAL COMPENSATION UNDERLYING LTIP ALL OTHER
NAME AND --------------------------------- OPTIONS/SARS PAYOUTS COMPENSATION
PRINCIPAL POSITION YEAR SALARY $ BONUS $(A) # $(B) $(C)
- ------------------------------------- --------- --------- ---------- ------------- --------- ------------

James L. Payne....................... 1996 515,000 708,125 225,000 515,025 30,900
Chairman of the Board, Chief 1995 433,250 284,922 -- -- 24,150
Executive Officer and 1994 406,000 300,000 -- -- 18,983
President
R. Graham Whaling.................... 1996(d) 236,538 243,930 35,000 140,625 19,993
Senior Vice President and 1995 225,000 109,766 250,000 -- 6,000
Chief Financial Officer 1994 -- -- -- -- --
Hugh L. Boyt......................... 1996 230,000 215,625 70,000 140,625 13,800
Senior Vice President -- 1995 210,731 103,938 -- -- 9,432
Production 1994 204,308 102,971 -- -- 10,489
Jerry L. Bridwell.................... 1996 230,000 172,500 70,000 140,625 12,420
Senior Vice President -- 1995 207,080 107,000 -- -- 11,246
Exploration and Land 1994 199,440 100,518 -- -- 10,295
Michael J. Rosinski.................. 1996 200,000 206,250 17,500 140,625 455,750
Senior Vice President -- 1995 194,675 91,200 -- -- 11,026
Marketing and Environmental 1994 192,900 97,222 -- -- 9,912

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

(a) The bonus amounts shown, while determined on a cash basis, were actually
paid partially in shares of the Company's common stock pursuant to the Stock
Plan. For 1994 Messrs. Payne, Boyt, Bridwell and Rosinski received 17,911;
6,148; 6,002 and 5,805 shares, respectively. For 1995, Messrs. Payne,
Whaling, Boyt, Bridwell and Rosinski received 14,898; 1,818; 5,435; 5,595
and 4,769 shares, respectively. For 1996, participants in the ICP Plan,
pursuant to which these bonuses were paid, received 25 percent of the bonus
earned in Bonus Stock under the Stock Plan and had the right to receive the
balance in cash. Alternatively participants could elect to forgo all or a
portion of the cash payment in return for the receipt of Restricted Stock on
the basis of an additional $1 in value for each $2 of cash given up. These
shares are subject to forfeiture in certain events and will vest one-third
per year over a three year period. The bonus amounts for 1996 reflect that
additional value received as a result of such elections. Messrs. Payne,
Whaling, Bridwell and Boyt received 6,460, 1,836, 3,067, and 2,084 shares of
Bonus Stock and 41,200, 14,192, 0, and 9,200 shares of Restricted Stock,
respectively. Mr. Rosinski, whose employment with the Company terminated on
December 31, 1996, received all cash.

(b) The amounts shown reflect the value the Company's common stock received as a
result of the accelerated payout of Performance Units granted as of January
1, 1996. See the Report of the Compensation and Benefits Committee.

(c) Amounts shown reflect matches made by the Company for employee contributions
to the Santa Fe Energy Resources, Inc. Savings Investment Plan as well as
the performance match. (See "Benefit Plans -- Savings Plan" for a
description of the Savings Investment Plan as well as the performance
match.) The performance match is contributed in the year following the
performance and therefore total amounts shown for 1994, 1995 and 1996
include the match made for 1993, 1994 and 1995 results, respectively. The
Company made a performance match in February 1997 for 1996 results for
Messrs. Payne, Whaling, Boyt, Bridwell and Rosinski in the amount of $3,000
for each individual. In addition, amounts shown for 1996 also include the
match made by the Corporation relating to deferrals under the Deferred
Compensation Plan. (See "Benefit Plans -- Savings Plan" for a description
of the Deferred Compensation Plan.) These amounts are also subject to the
performance match outlined in the Savings Investment Plan. In February 1997
the Company allocated to accounts maintained by Messrs. Payne, Whaling,
Boyt, Bridwell and Rosinski $7,300, $1,750, $1,600, $1,140 and $1,000,
respectively as a performance match.

Amounts shown for 1996 for Mr. Whaling also include grossed up tax payments
made to him relating to his relocation from Houston, Texas to Bakersfield,
California.

(FOOTNOTES CONTINUED ON FOLLOWING PAGE)

Finally, the amounts shown in 1996 for Mr. Rosinski also include $443,750
which he will receive pursuant to the terms of a severance arrangement.

(d) Mr. Whaling served as Senior Vice President and Chief Financial Officer
until November 1996 when he resigned to assume the position of Chairman of
the Board and Chief Executive Officer of Monterey Resources.

AGGREGATED OPTION/SAR EXERCISES IN 1996 AND 1996 YEAR-END OPTION/SAR VALUES

NUMBER OF
SECURITIES VALUE OF
UNDERLYING UNEXERCISED
UNEXERCISED IN-THE-MONEY
SHARES OPTIONS/SARS AT OPTIONS/SARS AT
ACQUIRED YEAR-END 1996 YEAR-END 1996
ON EXERCISES VALUE EXERCISABLE/ EXERCISABLE/
NAME DURING 1996 REALIZED UNEXERCISABLE UNEXERCISABLE(A)
- ------------------------------------- ------------ --------- ---------------- ------------------
(#) $ (#) $

James L. Payne....................... -0- 722,890/225,000 1,832,812/240,625
R. Graham Whaling (b)................ -0- 250,000/35,000 1,468,750/78,750
Hugh L. Boyt......................... -0- 225,245/70,000 625,312/83,125
Jerry L. Bridwell.................... -0- 273,839/70,000 625,312/83,125
Michael J. Rosinski (c).............. 20,000 111,250 120,000/17,500 517,500/39,375

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

(a) The closing price of the Company's common stock on December 31, 1996 was
$13.875.

(b) See footnote (1) under OPTION/SAR GRANTS IN LAST FISCAL YEAR for information
concerning the cancellation of these options by the Company in return for
the grant of options to Mr. Whaling by Monterey Resources.

(c) Mr. Rosinski's employment with the Company terminated on December 31, 1996.
Pursuant to the terms of a severance arrangement Mr. Rosinski received
$43,750 (the difference between the average of the high and low sales prices
of the Company's common stock on December 31, 1996 and the strike price of
$11.625 per share multiplied by his unexercisable options) in return for the
cancellation of his unexercised options.

OPTION/SAR GRANTS IN LAST FISCAL YEAR

INDIVIDUAL GRANTS
----------------------------- POTENTIAL REALIZABLE
NUMBER OF PERCENT OF VALUE AT ASSUMED
SECURITIES TOTAL RATES OF STOCK PRICE
UNDERLYING OPTIONS/SARS EXERCISE APPRECIATED FOR
OPTIONS/SARS GRANTED TO OR BASE OPTION TERM
GRANTED EMPLOYEES IN PRICE EXPIRATION ------------------------
(#) FISCAL YEAR ($/SH) DATE 5% ($) 10% ($)
------------ ------------- -------- ---------- ----------- -----------

James L. Payne....................... 100,000 8% 11.625 07-02-06 731,090 1,852,720
125,000 10% 13.75 12-11-06 1,080,925 2,739,250
R. Graham Whaling(a)................. 35,000 3% 11.625 07-02-06 255,881 648,452
Hugh L. Boyt......................... 35,000 3% 11.625 07-02-06 255,881 648,452
35,000 3% 13.75 12-11-06 302,659 766,990
Jerry L. Bridwell.................... 35,000 3% 11.625 07-02-06 255,881 648,452
35,000 3% 13.75 12-11-06 302,659 766,990
Michael J. Roskinski(b).............. 17,500 3% 11.625 07-02-06 127,940 324,226

All options described above are NQSOs granted pursuant to the 1990
Incentive Stock Compensation Plan, as amended (the "Stock Plan"). The NQSOs
were granted at market on the date of grant and vest one-third per year over a
three year period. These options were not accelerated by the IPO.
- ------------

(a) Mr. Whaling resigned his position as Senior Vice President and Chief
Financial Officer in November 1996 and assumed the position of Chairman of
the Board and Chief Executive Officer of Monterey. Upon the closing of the
IPO Mr. Whaling received 112,500 NQSOs pursuant to the Monterey Resources
1996 Incentive Stock Compensation Plan (the "Monterey Stock Plan") with a
strike price of $14.50. These options vest one-fifth per year over a five
year period but may not be exercised until one year following the
consummation of the Proposed Spin Off. In addition, in December 1996
Monterey offered to replace NQSOs granted pursuant to the Company's Stock
Plans with NQSOs granted pursuant to the Monterey Stock Plans. Mr. Whaling
accepted the offer and effective January 17, 1997, the options described
above were cancelled in return for a grant of 31,496 Monterey NQSO's with a
strike price of $12.9185. In addition, 250,000 NQSOs granted in January 1995
with a strike price of $8.00 were cancelled in return for a grant of 224,969
NQSOs issued pursuant to the Monterey Stock Plan with a strike price of
$8.8901. The newly granted NQSOs contain the same vesting schedule as the
Company NQSOs they replaced but may not be exercised until one year
following the consummation of the Proposed Spin Off even if fully or partial
vested prior to that time.

(b) Mr. Rosinski's employment with the Company terminated on December 31, 1996.
Pursuant to the terms of a severance arrangement these options were
cancelled. See -- Aggregated Option/SAR Exercises in 1996 and 1996 Year-End
Option/SAR Values.

LONG-TERM INCENTIVE PLANS AWARDS IN 1996

ESTIMATED FUTURE PAYOUTS
NUMBER OF UNDER NON-STOCK
SHARES, UNITS PERFORMANCE PRICE-BASED PLANS
OR OTHER OR OTHER PERIOD ------------------------------
RIGHTS UNTIL MATURATION OR THRESHOLD TARGET MAXIMUM
NAME (#) PAYOUT (#) (#) (#)
- ------------------------------------- ------------- ------------------- --------- ------ -------

James L. Payne....................... 23,679 1/1/97-12/31/99 7,104 23,679 47,358
R. Graham Whaling.................... -0- -- -- -- --
Hugh L. Boyt......................... 6,610 1/1/97-12/31/99 1,983 6,610 13,220
Jerry L. Bridwell.................... 6,610 1/1/97-12/31/99 1,983 6,610 13,220
Michael J. Rosinski.................. -0- -- -- -- --

In December 1996, the individuals described above (as well as 14 other
executive officers and key employees) received grants of Phantom Units pursuant
to the Stock Plan in the amounts indicated. The grant was effective January 1,
1997 with the Units being earned over a three-year period. Ultimate payout, if
any, is to be made in an equivalent number of shares of the Company's common
stock. Four equally weighted goals have been established which must be attained
over the three year performance period. Full payout at the target level will
result if discretionary cash flow (as described on page 51) and production
volumes equal the three year projected levels established by the 1997 profit
plan, the Company's common stock price performance equals the S&P 500 Index over
the three year period and the Company's common stock price at the end of the
three years equals an established target. If the above goals are substantially
exceeded possible payouts may increase to the maximum shown. Failure to meet a
threshold level, shown above as the combined threshold level of all four goals,
will result in a reduction or total elimination of a payout.

Mr. Whaling did not receive a grant of Phantom Units but did receive 37,500
shares of Monterey Resources, Inc. Restricted Stock pursuant to the Monterey
Resources Stock Plan. These shares vest as to one-fifth of the grant per year
over a five year period. The grant is not contingent upon the attainment of
goals but is subject to forfeiture in the event of termination of employment
under certain circumstances.

PERFORMANCE GRAPH

The following performance graph compares the performance of the
Corporation's common stock to the S&P 500 Index and to an index composed of 21
Independent Oil and Gas Companies selected by Goldman, Sachs & Co. from time to
time.(a) Although Goldman, Sachs & Co. does not represent that these companies
comprise a "peer group," the Corporation believes that its asset base and
operations are best compared to this group and that they are its peers.

COMPARISON OF FIVE YEAR CUMULATIVE TOTAL RETURN* AMONG
SANTA FE ENERGY RESOURCES INC., THE S & P 500 INDEX AND A PEER GROUP

[LINEAR GRAPH PLOTTED FROM DATA IN TABLE BELOW]

12/91 12/92 12/93 12/94 12/95 12/96
----- ----- ----- ----- ----- -----
SANTA FE ENERGY RESOURCES INC. 100 98 106 92 110 159
PEER GROUP 100 117 141 127 152 202
THE S & P 500 100 108 118 120 165 203

* $100 invested on 12/31/91 in stock or index -- including reinvestment of
dividends. Fiscal year ending December 31.

(a) This group of companies, which includes the Corporation, also currently
includes Anadarko Petroleum Corp., Apache Corp., Barrett Resources Corp.,
Burlington Resources, Cabot Oil & Gas, Cross Timbers Oil Co., Devon Energy,
Enron Oil & Gas, Louisiana Land & Exploration, Mitchell Energy &
Development, Noble Affiliates, Inc., Oryx Energy Co., Parker & Parsley
Petroleum, Pennzoil Co., Pogo Producing Company, Seagull Energy Corp., Union
Texas Petroleum Holdings, Inc., Vastar Resources, Inc., Vintage Petroleum
and United Meridian Corp. Due to activities such as reorganizations and
mergers, additions and deletions were made to the group from time to time.
Goldman Sachs & Co. has discontinued its past practice of selecting this
group.

BENEFIT PLANS

The Company maintains a 401(k) savings plan and a retirement income plan.
In addition, the Company has entered into employment agreements with certain
officers and key employees and maintains a severance program for all full-time
salaried employees. These plans and agreements are briefly described below.

SAVINGS PLAN. The Company has adopted the Santa Fe Energy Resources
Retirement and Savings Plan, which became operative and was restated and renamed
the Santa Fe Energy Resources Savings Investment Plan, effective November 1,
1990 (the "Savings Investment Plan"). The Savings Investment Plan offers
eligible employees an opportunity to make long-term investments on a regular
basis through salary contributions, which are supplemented by matching employer
contributions. Substantially all salaried employees are eligible to participate
on the first day of the month after their date of hire. The Company will match
up to 4% of an employee's compensation and the employee's contribution could not
exceed $9,500 in 1996. The limit amount is indexed each year to reflect cost-of-
living increases.

In addition to the employer match described above, at the end of each
fiscal year, the Company's performance is evaluated using the same performance
measures used in the ICP Plan. If the performance meets or exceeds the goals for
that year, participants will receive up to another fifty cents on each regular
matching dollar contributed by the Company. The regular employer matching
contributions as well as the performance match are made in the Company's common
stock. The goals were 100 percent met in 1996 and a performance match was made
in March 1997.

The Savings Investment Plan is intended to qualify as a Section 401(k) cash
or deferred compensation arrangement whereby an employee's contributions and the
employer's matching contributions are not subject to federal income taxes at the
time of the contribution to the Savings Investment Plan, and the Savings
Investment Plan is subject to the restrictions imposed by the Code. Investment
alternatives to which contributions may be allocated by the participants include
a fixed income fund, an equities fund, a balanced fund, a growth equity fund and
a fund which is invested in the Company's common stock.

The Company also maintains a supplemental deferred compensation arrangement
whereby employees earning in excess of $95,000 per year are allowed to defer all
or a portion of their salary until any future year or retirement. These amounts
are not matched by the Company. Employees earning in excess of $160,000 per year
may also defer up to 4 percent of such excess and the amount will be matched by
the Company. The amount contributed is also subject to the performance match
described above in the Savings Investment Plan. All amounts are contributed in
cash and earn interest at the rate paid on the fixed income fund of the Savings
Investment Plan.

RETIREMENT PLANS. The Company has adopted the Santa Fe Energy Resources
Retirement Income Plan, a qualified defined benefit plan for substantially all
salaried employees (the "Retirement Plan"), and the Santa Fe Energy Resources
Supplemental Retirement Plan (the "Nonqualified Plan"). The Nonqualified Plan
will pay benefits to Retirement Plan participants where the Retirement Plan
formula produces a benefit to members in excess of limits imposed by ERISA and
applicable government regulations. It also includes amounts deferred under the
Santa Fe Energy Resources, Inc. Deferred Compensation Plan as pensionable
compensation. Benefits which have accrued to the Corporation's participants
under the Santa Fe Pacific Retirement Plan ("SFP Retirement Plan") are
protected under the Retirement Plan. Total approximate benefits under both the
Retirement Plan and supplemental plan are shown below for selected compensation
levels and years of service. As of December 31, 1996, Payne, Whaling, Bridwell,
Boyt, and Rosinski were credited with 14.8, 2.0, 22.8, 13.2 and 4.3 years of
service under the plans, respectively.

PENSION PLAN TABLE

AVERAGE YEARS OF SERVICE
YEARLY ---------------------------------------------------------------
COMPENSATION 15 20 25 30 35
- ------------ ----------- ----------- ----------- ----------- -----------
$125,000 $ 22,000 $ 29,000 $ 36,000 $ 54,000 $ 63,000
$150,000 $ 26,000 $ 35,000 $ 44,000 $ 66,000 $ 77,000
$175,000 $ 31,000 $ 41,000 $ 52,000 $ 77,000 $ 90,000
$200,000 $ 36,000 $ 48,000 $ 59,000 $ 89,000 $ 104,000
$225,000 $ 40,000 $ 54,000 $ 67,000 $ 101,000 $ 118,000
$250,000 $ 45,000 $ 60,000 $ 75,000 $ 112,000 $ 131,000
$300,000 $ 54,000 $ 72,000 $ 90,000 $ 136,000 $ 158,000
$400,000 $ 73,000 $ 97,000 $ 121,000 $ 182,000 $ 212,000
$450,000 $ 82,000 $ 110,000 $ 137,000 $ 205,000 $ 240,000
$500,000 $ 91,000 $ 122,000 $ 152,000 $ 229,000 $ 267,000
$600,000 $ 110,000 $ 147,000 $ 183,000 $ 275,000 $ 321,000
$650,000 $ 119,000 $ 159,000 $ 199,000 $ 298,000 $ 348,000

Benefit figures shown are amounts payable based on a straight life annuity
assuming retirement by the participant at age 62 in 1996 without a joint
survivorship provision. The benefits listed in the above table are not subject
to any deduction for social security or other offset amounts.

Benefits under the plans are computed based on a participant's total
compensation during this period of covered employment, for the 60 consecutive
months during the ten-year period immediately prior to the termination of his
covered employment for which his total compensation is the highest, divided by
60. If a participant has not received compensation for 60 consecutive months
during such ten-year period, his compensation shall equal the total of his
compensation for the longest period of consecutive months during such ten-year
period divided by the total number of months of compensation so considered.

Compensation recognized under the plans is the total basic compensation,
including any elective salary deferral amounts excluded from income pursuant to
Section 125 or 402 of the code, plus overtime, shift differentials and bonuses
(whether cash or stock) paid pursuant to recurring bonus programs, including
compensation deferred under the Santa Fe Energy Resources, Inc. Deferred
Compensation Plan, but excluding any special or extraordinary bonuses and any
other items of compensation. A participant's basic compensation is the regular
rate of pay specified for his position and does not include automobile
allowances, imputed income under any group term life insurance program, moving
expense or other reimbursements, fringe benefits, or similar items.

The pension compensation therefore differs from the compensation listed in
the Summary Compensation Table in several respects. Pension compensation is
based on average compensation as explained above. It does not include restricted
stock awards, stock options, and other compensation in the "All Other
Compensation" column (i.e., employer matching contributions to the Savings
Investment Plan and the performance match). It also does not include special or
extraordinary bonuses.

The pension compensation of officers whose pension compensation differs
from the compensation contained in the Summary Compensation Table is listed
below:

PENSION COMPENSATION
NAME (FINAL AVERAGE PAY)
- ---------------------------------------------------------
James L. Payne....................... $662,206
R. Graham Whaling.................... $302,058
Jerry L. Bridwell.................... $313,165
Hugh L. Boyt......................... $293,705
Michael J. Rosinski.................. $305,591

EMPLOYMENT AGREEMENTS. The Company has entered into employment agreements
("Employment Agreements") covering 11 employees of the Company (including each
of the individuals named in the Cash Compensation Table except Messrs. Whaling
and Rosinski. Mr. Whaling has entered into an employment agreement with Monterey
Resources similar to Mr. Payne's Employment Agreement. Mr. Rosinski's employment
with the Company terminated on December 31, 1996.) The Employment Agreements,
which replaced similar agreements with several of these employees originally
entered into in 1990, are intended to encourage such employees to remain in the
employ of the Company. The initial term of each Employment Agreement, with the
exception of Messrs. Payne's and Whaling's expires on December 31, 1998;
however, beginning January 1, 1998 and on each January thereafter the term of
the Employment Agreements will automatically be extended for additional one-year
periods, unless by September 30 of the preceding year the Company gives notice
that the Employment Agreements will not be so extended. The term of each
Employment Agreement, with the exception of Messrs. Payne's and Whaling's is
automatically extended for a period of two years following a Change in Control
(as defined herein). Messrs. Payne's and Whaling's Employment Agreement have an
initial term which expires on December 31, 1999, are automatically extended for
one-year periods beginning January 1, 1999 and are automatically extended for a
three-year period following a Change in Control.

In the event following a Change in Control employment is terminated by the
employee for "Good Reason" or the employee is involuntarily terminated by the
Company other than for "Cause" (as those terms are defined in the Employment
Agreements), or if during the six months preceding a Change in Control, the
employee's employment is terminated by the employee for Good Reason or by the
Company other than for Cause, and such termination is demonstrated to be
connected with the Change in Control, the Employment Agreements provide for
payment of certain amounts to the employee based on the employee's salary and
bonus under the Company's Incentive Compensation Plan; payout of non-vested
restricted stock, phantom units, stock options, if any, and continuation of
certain insurance benefits on a tax neutral basis for the Company employees for
a period of up to 24 months (36 months in the case of Messrs. Payne and
Whaling). The payments and benefits are payable pursuant to the Employment
Agreements only to the extent they are not paid out under the terms of any other
plan of the Company. The payments and benefits provided by the Employment
Agreements for all individuals except Messrs. Payne and Whaling may be further
limited by the Parachute Payment Limit described in the discussion of the
Company's Stock Plan below. In the event Messrs. Payne's or Whaling's payments
would exceed the Parachute Payment Limit, they will be made "whole" on a net
after-tax basis for any excise tax incurred. Without giving effect to such
limitation, the estimated value of the payments and benefits that Messrs. Payne,
Whaling, Boyt and Bridwell and all executive officers as a group would be
entitled to receive if any qualifying termination occurred on February 1, 1997
would be $2,694,711, $1,300,000, $743,326, $734,492 and $6,319,817,
respectively.

SEVERANCE PROGRAM. The Company has adopted a Severance Program for all
full-time, salaried employees who are terminated by the Company or terminated or
constructively terminated by an acquiring company, other than for Cause (as
defined in the Severance Program). However, following a Change in Control
(defined substantially the same as in the Stock Compensation Plan), an executive
officer or key employee who has entered into an Employment Agreement is not
eligible to receive duplicate benefits under the Employment Agreement and the
Severance Program. As noted above, the merger of Adobe with the Company
constituted a Change of Control. A participant in the Severance Program is
generally entitled to an amount of up to one year's pay based upon a
participant's age, length of service and highest rate of base salary in effect
during the 24-month period preceding his termination, provided that the
aggregate of such payment does not exceed two times the participant's actual
salary for the 12-month period preceding the date of termination. In addition, a
participant is entitled to continuation of health and life insurance benefits
for up to a period of two years.

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 ..................................... 63

Consolidated Statement of Operations
for the years ended December
31, 1996, 1995 and 1994 ............................................... 64

Consolidated Balance Sheet -- December 31,
1996 and 1995 ......................................................... 65

Consolidated Statement of Cash Flows
for the years ended December 31, 1996,
1995 and 1994 ......................................................... 66

Consolidated Statement of Shareholders'
Equity for the years ended December 31,
1996, 1995 and 1994 ................................................... 67

Notes to Consolidated Financial Statements ............................ 68

2. Financial Statement Schedules:

Schedule VIII -- Valuation and Qualifying
Accounts .............................................................. 100

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 of Exhibits on page 101 for a description of the exhibits
filed as a part of this report.

(b) Reports on Form 8-K

DATE ITEM
----------------- ----
February 28, 1997 5

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 62 present fairly, in all material
respects, the financial position of Santa Fe Energy Resources, Inc. and its
subsidiaries at December 31, 1996 and 1995, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 1996, 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.

PRICE WATERHOUSE LLP

Houston, Texas
February 21, 1997

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

YEAR ENDED DECEMBER 31,
-------------------------------
1996 1995 1994
--------- --------- ---------
Revenues
Sales of crude oil and liquids
produced...................... $ 455.4 $ 352.4 $ 305.2
Sales of natural gas produced... 105.8 77.1 83.4
Sales of crude oil purchased.... 21.1 6.7 11.9
Other........................... 1.0 13.2 3.7
--------- --------- ---------
583.3 449.4 404.2
--------- --------- ---------
Costs and Expenses
Production and operating........ 188.4 155.8 151.1
Cost of crude oil purchased..... 20.8 6.5 11.7
Exploration, including dry hole
costs......................... 34.5 23.4 20.4
Depletion, depreciation and
amortization.................. 148.2 133.2 121.3
Impairment of oil and gas
properties.................... 57.4 30.2 --
General and administrative...... 30.1 26.9 27.3
Taxes (other than income)....... 26.5 19.2 25.8
Restructuring charges........... -- -- 7.0
Loss (gain) on disposition of
assets........................ (12.1) 0.3 (8.6)
--------- --------- ---------
493.8 395.5 356.0
--------- --------- ---------
Income from Operations............... 89.5 53.9 48.2
Interest income................. 1.9 10.7 2.8
Interest expense................ (37.6) (32.5) (27.5)
Interest capitalized............ 5.2 5.8 3.6
Other income (expense).......... (1.0) (1.6) (4.0)
--------- --------- ---------
Income Before Income Taxes, Minority
Interest and Extraordinary Items... 58.0 36.3 23.1
Income taxes.................... (14.3) (9.7) (6.0)
--------- --------- ---------
Income Before Minority Interest and
Extraordinary Items................ 43.7 26.6 17.1
Minority Interest in Monterey
Resources, Inc................ (1.3) -- --
--------- --------- ---------
Income Before Extraordinary Items.... 42.4 26.6 17.1
Extraordinary item -- debt
extinguishment costs............ (6.0) -- --
--------- --------- ---------
Net Income........................... 36.4 26.6 17.1
Preferred dividend
requirement................... (13.5) (14.8) (11.7)
Convertible preferred repurchase
premium....................... (33.7) -- --
--------- --------- ---------
Earnings (Loss) Attributable to
Common Shares...................... $ (10.8) $ 11.8 $ 5.4
========= ========= =========
Earnings (Loss) Attributable to
Common Shares Per Share
Earnings (loss) before
extraordinary items........... $ (0.05) $ 0.13 $ 0.06
Extraordinary items -- debt
extinguishment costs.......... (0.07) -- --
--------- --------- ---------
Earnings (loss) to common
shares........................ $ (0.12) $ 0.13 $ 0.06
========= ========= =========
Weighted Average Number of Common
Shares Outstanding
(in millions)...................... 90.6 90.2 89.9
========= ========= =========

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

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

DECEMBER 31,
------------------------
1996 1995
----------- -----------
ASSETS
Current Assets
Cash and cash equivalents....... $ 14.6 $ 42.6
Accounts receivable............. 109.1 89.0
Inventories..................... 13.6 10.5
Other current assets............ 35.2 17.2
----------- -----------
172.5 159.3
----------- -----------
Properties and Equipment, at cost
Oil and gas (on the basis of
successful efforts
accounting)................... 2,539.8 2,336.3
Other........................... 34.4 35.6
----------- -----------
2,574.2 2,371.9
Accumulated depletion,
depreciation, amortization and
impairment.................... (1,664.4) (1,482.4)
----------- -----------
909.8 889.5
----------- -----------
Other Assets
Receivable under gas balancing
arrangements.................. 4.5 5.8
Other........................... 33.2 10.2
----------- -----------
37.7 16.0
----------- -----------
$ 1,120.0 $ 1,064.8
=========== ===========

LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable................ $ 115.4 $ 73.1
Income taxes payable............ 21.4 3.0
Interest payable................ 6.0 7.9
Other current liabilities....... 36.6 25.6
----------- -----------
179.4 109.6
----------- -----------
Long-Term Debt....................... 278.5 344.4
----------- -----------
Deferred Revenues.................... 4.0 4.9
----------- -----------
Other Long-Term Obligations.......... 27.5 24.2
----------- -----------
Deferred Income Taxes................ 53.8 64.0
----------- -----------
Minority Interest in Monterey
Resources, Inc..................... 30.3 --
----------- -----------
Commitments and Contingencies (Note
14)................................ -- --
----------- -----------
Convertible Preferred Stock, 7%
Series, $0.01 par value, 5.0
million shares authorized and
issued; 1.2 million and 5.0 million
outstanding
at December 31, 1996 and 1995,
respectively....................... 19.7 80.0
----------- -----------
Shareholders' Equity
Preferred stock, $0.01 par
value, 38.1 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................. 601.3 501.4
Accumulated deficit............. (166.5) (155.7)
Foreign currency translation
adjustment.................... (0.3) (0.3)
----------- -----------
526.8 437.7
----------- -----------
$ 1,120.0 $ 1,064.8
=========== ===========

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

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

YEAR ENDED DECEMBER 31,
-------------------------------
1996 1995 1994
--------- --------- ---------
Operating Activities:
Net income...................... $ 36.4 $ 26.6 $ 17.1
Adjustments to reconcile net
income to net cash provided by
operating activities:
Depletion, depreciation and
amortization............. 148.2 133.2 121.3
Impairment of oil and gas
properties............... 57.4 30.2 --
Restructuring charges...... -- -- 1.0
Deferred income taxes...... (11.2) 7.7 11.3
Loss (gain) on disposition
of assets................ (12.1) 0.3 (8.6)
Exploratory dry hole
costs.................... 11.2 5.5 6.5
Minority interest in
Monterey Resources,
Inc...................... 1.3 -- --
Equity in losses and
adjustment to valuation
of investment in Hadson
Corporation.............. -- -- 6.1
Hadson Corporation
preferred dividends
received in-kind......... -- -- (4.5)
Other...................... 6.7 2.4 3.0
Changes in operating assets and
liabilities:
Decrease (increase) in
accounts receivable...... (20.1) (12.8) 1.3
Decrease (increase) in
inventories.............. (3.1) (1.3) (0.5)
Increase (decrease) in
accounts payable......... 20.0 (4.5) (8.6)
Increase (decrease) in
interest payable......... (1.9) (0.6) (1.7)
Increase (decrease) in
income taxes payable..... 18.4 1.5 0.2
Net change in other assets
and liabilities.......... (23.6) (13.7) (19.4)
--------- --------- ---------
Net Cash Provided by Operating
Activities......................... 227.6 174.5 124.5
--------- --------- ---------
Investing Activities:
Capital expenditures, including
exploratory dry hole costs.... (185.7) (189.4) (136.6)
Acquisitions of producing
properties, net of related
debt.......................... (37.8) (33.8) (2.2)
Proceeds from sale of investment
in Hadson Corporation......... -- 55.2 --
Net proceeds from sales of
properties.................... 16.7 7.2 81.1
--------- --------- ---------
Net Cash Used in Investing
Activities......................... (206.8) (160.8) (57.7)
--------- --------- ---------
Financing Activities:
Issuance of Monterey Resources,
Inc. common stock............. 123.6 -- --
Issuance of Santa Fe Energy
Resources, Inc. common
stock......................... 2.4 -- --
Purchase of 7% Series
convertible preferred stock... (94.0) -- --
Principal payments on long-term
borrowings.................... (70.0) (10.0) (144.7)
Net change in revolving credit
agreement..................... 4.0 -- (50.0)
Issuance of 11% senior
subordinated debentures....... -- -- 96.1
Issuance of $.732 Series A
convertible preferred stock... -- -- 91.4
Cash dividends paid............. (14.8) (14.8) (10.7)
--------- --------- ---------
Net Cash Used in Financing
Activities......................... (48.8) (24.8) (17.9)
--------- --------- ---------
Net Increase (Decrease) in Cash and
Cash Equivalents................... (28.0) (11.1) 48.9
Cash and Cash Equivalents at
Beginning of Year.................. 42.6 53.7 4.8
--------- --------- ---------
Cash and Cash Equivalents at End of
Year............................... $ 14.6 $ 42.6 $ 53.7
========= ========= =========

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

SANTA FE ENERGY RESOURCES, INC.
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
(SHARES AND DOLLARS IN MILLIONS)

$.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
------ ------ ------ ------ ------- ----------- ----------- ----------

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 translation
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)
Issuance of common stock
Employee stock compensation and
savings plans.................. -- -- 0.7 -- 6.4 -- -- --
Issuance of Monterey Resources,
Inc. common stock................ -- -- -- -- 93.5 -- -- --
Purchase of 7% Series convertible
preferred stock.................. -- -- -- -- -- -- (33.7) --
Net income......................... -- -- -- -- -- -- 36.4 --
Dividends declared................. -- -- -- -- -- -- (13.5) --
------ ------ ------ ------ ------- ----------- ----------- ----------
Balance at December 31, 1996......... 10.7 $91.4 91.0 $0.9 $ 601.3 $-- $(166.5) $ 0.3
====== ====== ====== ====== ======= =========== =========== ==========

TOTAL
SHAREHOLDERS'
EQUITY
--------------
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
Issuance of common stock
Employee stock compensation and
savings plans.................. 6.4
Issuance of Monterey Resources,
Inc. common stock................ 93.5
Purchase of 7% Series convertible
preferred stock.................. (33.7)
Net income......................... 36.4
Dividends declared................. (13.5)
--------------
Balance at December 31, 1996......... $526.8
==============

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

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 and Monterey Resources, Inc. ("Monterey"). Prior
to its initial public offering in November 1996, the Company owned 100% of the
outstanding common stock of Monterey. At December 31, 1996, the Company owned
82.8% of the outstanding common stock of Monterey (See Note 2). References
herein to the "Company" or "Santa Fe" relate to Santa Fe Energy Resources,
Inc., individually or together with its consolidated subsidiaries.

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,
proved properties are reviewed to determine if the carrying value of the
property exceeds the expected undiscounted future net cash flows from the
operation of the property. Based on this review and the continuing evaluation of
development plans, production data, 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 fair value of the
property based on discounted future net cash flows. In accordance with its
policy, the Company recorded impairments of $57.4 million in 1996 and $30.2
million in 1995. 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 $39.0
million and such amount is being accrued over the expected life of the
properties. At December 31, 1996 and 1995 Accumulated Depletion, Depreciation,
Amortization and Impairment includes $16.6 million and $15.5 million,
respectively, with respect to such costs.

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, 1996 the Company's deferred revenues for sales proceeds received in
excess of the Company's entitlement was $3.2 million with respect to 2.5 MMcf
and the asset related to the Company's share of sales taken by others was $4.5
million with respect to 3.2 MMcf.

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

Revenues from sales of crude oil purchased relate to the sales of low
viscosity crude oil purchased and blended with certain of the Company's high
viscosity, low gravity crude oil production, either to facilitate pipeline
transportation or to realize higher margins. The cost to purchase such crude oil
is reflected as an expense.

EARNINGS PER SHARE

Earnings per share are based on the weighted average number of common and
common equivalent 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, 1996 and 1995 the Company's allowance for doubtful accounts
receivable, which is reflected in the consolidated balance sheet as a reduction
in accounts receivable, totalled $2.5 million and $2.0 million, respectively.
Accounts receivable totalling $1.1 million and $3.8 million were written off as
uncollectible in 1995 and 1994, 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, 1996 and 1995 were
$4.5 million and $2.7 million, respectively, and materials and supplies
inventories at such dates were $9.1 million and $7.8 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 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

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

In 1996 Santa Fe formed Monterey to assume the operations of the Company's
Western Division (the "Western Division") which conducted the Company's oil
and gas operations in the State of California. In November 1996, prior to the
initial public offering (the "IPO") discussed below, pursuant to a
contribution and conveyance agreement (the "Contribution Agreement"), among
other things: (i) Santa Fe contributed to Monterey substantially all of the
assets and properties of the Western Division, subject to the retention by Santa
Fe of a production payment, as defined below, and certain other assets; (ii)
Santa Fe retained a $30.0 million production payment (the "Production
Payment") with respect to certain properties in the Midway-Sunset field; (iii)
Monterey assumed all obligations and liabilities of Santa Fe associated with or
allocated to the assets and properties of the Western Division, including $245.0
million of indebtedness in respect of Santa Fe's 10.23% Series E Notes due 1997,
10.27% Series F Notes due 1998 and 10.61% Series G Notes due 2005 (the "Series
E Notes", "Series F Notes" and "Series G Notes", respectively) and (iv)
Monterey agreed to purchase from Santa Fe an $8.3 million promissory note
receivable related to the sale to a third party of certain surface acreage
located in Orange County, California. Also prior to the IPO, Monterey and Santa
Fe entered into a $75.0 million revolving credit facility with a group of banks
(the "Monterey Credit Facility") and borrowed $16.0 million which was retained
by Santa Fe.

In November 1996 Monterey sold 9,335,000 shares of its common stock for
total consideration of $123.6 million (after deducting underwriting discounts of
$9.1 million and other related costs of $2.6 million). The proceeds from the IPO
were used in part to (i) repay the Series E Notes and Series F Notes ($70.0
million) and pay a prepayment penalty thereon of $2.5 million; (ii) retire the
Production Payment ($30.0 million); (iii) repay the $16.0 million outstanding
under the Monterey Credit Facility; and (iv) pay a $2.0 million fee with respect
to a supplement to the indenture relating to Santa Fe's 11% Senior Subordinated
Debentures due 2004. Subsequent to the IPO, Monterey issued $175.0 million in
aggregate principal amount of 10.61% Senior Notes due 2005 (the "Monterey
Senior Notes") to holders of the Series G Notes in exchange for the
cancellation of such notes and paid a $1.3 million consent fee in connection
therewith.

The costs and expenses related to the retirement of Santa Fe's outstanding
debt, as discussed above, and approximately $3.4 million of deferred debt issue
costs and related transaction costs are reflected in the Statement of Operations
as an extraordinary item, net of $3.2 million in income taxes.

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

At December 31, 1996, Santa Fe owned 82.8% of the Monterey's outstanding
common stock. Santa Fe has announced that it intends to distribute pro rata to
its common shareholders all of the shares of Monterey's common stock that it
owns by means of a tax-free distribution (the "Proposed Spin Off"). Santa Fe's
final determination to proceed will require a declaration of the Proposed Spin
Off by Santa Fe's Board of Directors. Such declaration is not expected to be
made until certain conditions, many of which are beyond the control of Santa Fe,
are satisfied, including: (i) receipt by Santa Fe of a ruling from the Internal
Revenue Service as to the tax-free nature of the Proposed Spin Off; (ii)
approval of the Proposed Spin Off by Santa Fe's shareholders; and (iii) the
absence of any future change in market or economic conditions (including
developments in the capital markets) or Santa Fe's or Monterey's business and
financial condition that causes Santa Fe's Board to conclude that the Proposed
Spin Off is not in the best interests of Santa Fe's shareholders. The Company
does not expect the Proposed Spin Off to occur prior to July 1997.

Pursuant to the terms of a letter agreement dated as of June 13, 1996, a
fee will be payable by Monterey to Chase Securities Inc. and Petrie Parkman &
Co., Inc. upon consummation of the Proposed Spin Off. The total amount of such
fee is equal to the product of (a) the sum of the market value of the shares of
Monterey distributed in the Proposed Spin Off (based upon the average closing
price of Monterey's common stock during the ten trading days after the Proposed
Spin Off) PLUS the aggregate principal amount of long-term indebtedness assumed
by Monterey in connection with the Proposed Spin Off (which totalled $175.0
million) TIMES (b) 0.5%, LESS $1.0 million. If the market value of the Monterey
common stock distributed is $16.00 per share, the Company estimates the total
fee payable would be approximately $3.5 million, of which $1.75 million would be
payable to each of Chase Securities and Petrie Parkman. In addition, a fee of
$400,000 will be payable to GKH Partners, L.P., of which $200,000 will be
payable by each the Company and Monterey. Certain of the Company's directors are
associated with Chase Securities and GKH Partners.

Monterey has agreed to indemnify the Company if at any time during the
one-year period after the consummation of the Proposed Spin Off (or if certain
tax legislation is enacted and is applicable, such longer period as is required
for the Proposed Spin Off to be tax free to Santa Fe) Monterey takes certain
actions the effects of which result in the Proposed Spin Off being taxable to
Santa Fe.

Santa Fe provides various administrative and financial services to
Monterey, including administration of certain employee benefits plans, access to
telecommunications, corporate legal assistance and certain other corporate staff
and support services. Santa Fe and Monterey have entered into a Services
Agreement, terminable by either party on thirty day's notice, under which
Monterey pays a fee of $120,000 per month for such services until such time as
Monterey assumes full responsibility during 1997 for each of the services
covered by the agreement. During 1996 Santa Fe charged Monterey $240,000 under
the terms of the Services Agreement.

Certain Monterey employees are participants in Santa Fe's employee benefit
and pension plans. Subsequent to the IPO Santa Fe charged Monterey $0.2 million
in connection with Monterey employees' participation in such plans.

(3) CORPORATE RESTRUCTURING PROGRAM

In 1993 the Company adopted a corporate restructuring program which
included, among other things, a cost reduction program which consisted of a
reduction in the Company's salaried work force, an improvement in the efficiency
of information systems and a reduction in other general and administration and
production and operating costs. The Company's income from operations for 1994
includes restructuring charges of $7.0 million, comprised of severance, benefits
and relocation expenses associated with the cost reduction program.

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

(4) INVESTMENT IN HADSON CORPORATION

In December 1993 the Company completed a transaction with Hadson
Corporation ("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 was accounted for on the equity basis.

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 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. Subsequent to the sale Hadson's name was changed to
LG&E Natural Marketing Inc. ("LG&E").

(5) 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. Through December 31, 1996 the Company had made additional royalty
payments, net of recoupments, totalling $1.2 million.

At December 31, 1996 and 1995, Accounts Payable included $3.1 million and
$2.6 million, respectively, due to the Trust.

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

(6) CASH FLOWS

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

In December 1996 the Company sold the surface rights to approximately 116
surface acres in Orange County, California for total consideration of $24.2
million and recognized a $12.3 million gain. The Company received $15.9 million
in cash and an $8.3 million note which was purchased by Monterey for cash.

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, $10.5 million of which was collected in 1994.

In April 1994 the Company completed the sale of certain Mid-Continent and
Rocky Mountain producing and nonproducing oil and gas properties for net
proceeds totalling $46.7 million. The Company's income from operations for 1994
includes $2.2 million attributable to the assets sold. In the first quarter of
1994 the Company sold its interest in certain oil and gas properties, in which
it had no remaining basis, for $8.3 million.

The Company made interest payments of $38.6 million, $37.6 million and
$47.9 million in 1996, 1995 and 1994, respectively. In 1996, 1995 and 1994, the
Company made tax payments of $2.0 million, $1.6 million and $1.8 million,
respectively, and in 1996 and 1995 received tax refunds of $11.2 million and
$1.3 million, respectively, primarily related to the audit of prior years'
returns.

(7) INCOME TAXES

In December 1990 SFP distributed all of the shares of the Company it held
to its shareholders (the "SFP Spin Off"). Through the date of the SFP 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. The Company, in conjunction with the SFP Spin
Off, agreed to indemnify SFP should the transaction be determined to be taxable
to SFP because of the Company's actions. The Company does not believe it has
taken any action that would have such an effect. Accounts Receivable at December
31, 1995 included $12.0 million with respect to a refund related to the audit of
the years 1981 through 1985 which was collected in 1996. The Company has filed
separate consolidated federal income tax returns for periods subsequent to the
SFP 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
favorably resolved in 1994. The years 1984 through 1986 have been audited and no
significant Company issues were raised. The years 1987 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 $71.4 million will expire beginning in 2004.

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

Total pretax income for the years ended December 31, 1996, 1995 and 1994
was taxed under the following jurisdictions (in millions of dollars):

1996 1995 1994
--------- --------- ---------
Domestic............................. 46.4 40.5 22.0
Foreign.............................. 2.4 (4.2) 1.1
--------- --------- ---------
48.8 36.3 23.1
========= ========= =========

The Company's total income tax expense (benefit) for the years ended
December 31, 1996, 1995 and 1994 consisted of (in millions of dollars):

1996 1995 1994
--------- --------- ---------
Current
U.S. federal.................... 13.6 1.5 (3.5)
State........................... 5.1 (2.1) (3.2)
Foreign......................... 3.6 2.6 1.4
--------- --------- ---------
22.3(a) 2.0 (5.3)
--------- --------- ---------
Deferred
U.S. federal.................... 4.7 13.3 8.6
State........................... 1.3 (0.6) 2.4
Foreign......................... (17.2)(b) (5.0) 0.3
--------- --------- ---------
(11.2) 7.7 11.3
--------- --------- ---------
11.1(a) 9.7 6.0
========= ========= =========

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

(a) Includes $3.2 million income tax benefit which is reflected in extraordinary
item - debt extinguishment costs (see Note 2).

(b) Includes benefit of $8.3 million related to certain prior period foreign
expenditures.

The Company's deferred income tax liabilities (assets) at December 31, 1996
and 1995 are composed of the following differences between financial and tax
reporting (in millions of dollars):

1996 1995
--------- ---------
Capitalized costs and write-offs..... 99.9 138.5
State deferred liability............. 10.5 7.6
Foreign deferred liability........... (8.1) 9.1
--------- ---------
Gross deferred liabilities........... 102.3 155.2
--------- ---------
Accruals not currently deductible for
tax purposes....................... (0.7) (16.7)
Alternative minimum tax
carryforwards...................... (13.6) (12.7)
Net operating loss carryforwards..... (25.0) (54.7)
Other................................ (9.2) (7.1)
--------- ---------
Gross deferred assets................ (48.5) (91.2)
--------- ---------
Deferred tax liability............... 53.8 64.0
========= =========

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

A reconciliation of the Company's total U.S. income tax expense computed by
applying the statutory U.S. federal income tax rate to the Company's total
income (loss) before income taxes for the years ended December 31, 1996, 1995
and 1994 is presented in the following table (in millions of dollars):

1996 1995 1994
--------- --------- ---------
U.S. federal income taxes at
statutory rate..................... 17.1 12.7 8.1
Increase (reduction) resulting from:
State income taxes, net of federal
effect.......................... 4.3 0.6 0.9
Foreign income taxes in excess of
(less than) U.S. rate........... (14.4) (0.9) 1.4
U.S. tax on foreign reinvested
earnings........................ 2.8 0.8 1.2
Benefit of tax losses.............. (1.8) (0.3) (4.3)
Prior period adjustments........... 1.7 (2.7) (1.6)
Other.............................. 1.4 (0.5) 0.3
--------- --------- ---------
11.1 9.7 6.0
========= ========= =========

(8) FINANCING AND DEBT

Long-term debt at December 31, 1996 and 1995 consisted of (in millions of
dollars):

DECEMBER 31,
--------------------------------------------
1996 1995
-------------------- --------------------
CURRENT LONG-TERM CURRENT LONG-TERM
------- --------- ------- ---------
Santa Fe
Senior Notes................. -- -- -- 245.0
11% Senior Subordinated
Debentures................ -- 99.5 -- 99.4
Short-term lines of credit... -- 4.0 -- --
------- --------- ------- ---------
-- 103.5 -- 344.4
Monterey
Senior Notes................. -- 175.0 -- --
------- --------- ------- ---------
-- 278.5 -- 344.4
======= ========= ======= =========

Aggregate total maturities of long-term debt during the next five years are
as follows: 1997 -- none; 1998 -- none; 1999 -- $25.0 million; 2000 -- $25.0
million; and 2001 -- $29.0 million.

Effective November 13, 1996 Santa Fe entered into a revolving credit
agreement (the "Santa Fe Credit Agreement") which matures November 13, 2001.
The Santa Fe Credit Agreement permits the Company to obtain revolving credit
loans and issue letters of credit up to an aggregate amount of $150.0 million,
with the aggregate amount of letters of credit outstanding at any time limited
to $30.0 million. Borrowings under the Santa Fe Credit Agreement are unsecured
and interest rates are tied to the bank's prime rate or eurodollar offering
rate, at the option of the Company. At December 31, 1996, no loans or letters of
credit were outstanding under the terms of the Santa Fe Credit Agreement.

SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
or eurodollar offering rate, at the option of Monterey. At December 31, 1996, no
loans or letters of credit were outstanding under the terms of the Monterey
Credit Agreement.

In November 1996 Monterey issued the Monterey Senior Notes which were
exchanged for $175.0 million of senior notes previously issued by Santa Fe. The
Monterey Senior Notes bear interest at 10.61% per annum and mature in 2005.
Monterey is required to repay $25.0 million of the principal amount each year
from 1999 through 2005.

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 11), to retire $132.3 million of its then outstanding
long-term debt.

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.

Santa Fe has three short-term uncommitted lines of credit totalling $60.0
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 Santa Fe Credit Agreement. At December 31, 1996 $4.0 million was outstanding
under these lines of credit. The amount outstanding at December 31, 1996 is
classified as long-term since the Santa Fe Credit Agreement is available to
refinance such amount on a long-term basis.

At December 31, 1996 the Company had outstanding letters of credit
totalling $6.0 million, $2.3 million of which relate to the operations of
Monterey.

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

(9) 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):

OIL AND GAS
------------------------------------------
OTHER GENERAL
U.S. ARGENTINA INDONESIA FOREIGN CORPORATE TOTAL
--------- --------- --------- ------- --------- ---------

1996
Revenues........................... 517.9 35.8 29.6 -- -- 583.3
Income (Loss) from Operations...... 126.0 17.6 (11.3) (17.4) (25.4) 89.5
Depletion, Depreciation,
Amortization and Impairment..... 164.9 7.9 24.6 5.0 3.2 205.6
Additions to Property and
Equipment....................... 190.0 20.2 15.3 9.4 10.8 245.7
Identifiable Assets at December
31.............................. 854.7 87.3 72.6 6.2 99.2 1,120.0
1995
Revenues........................... 398.6 19.2 31.6 -- -- 449.4
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........................... 359.5 12.9 31.8 -- -- 404.2
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

Crude oil and liquids and natural gas accounted for more than 93% of
revenues in 1996, 1995 and 1994. 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,
------------------------
1996 1995 1994
----- ----- ----
Celeron Corporation.................. 66.7 62.1 58.7
Coastal States Trading, Inc.......... 56.4 (a) (a)
Shell Oil Company.................... 105.7 100.4 94.5

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

(a) Sales represented less than 10% of crude oil and liquids revenues.

In 1996, 1995 and 1994 the only purchaser of the Company's natural gas to
account for more than 10% of natural gas revenues was LG&E (see Note 4 with
respect to the Company's gas sales contract with LG&E).

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

(10) CONVERTIBLE PREFERRED STOCK, 7% SERIES

The Company's Convertible Preferred Stock, 7% Series, which was issued in
connection with the Company's merger with Adobe Resources Corporation
("Adobe") in 1992, is non-voting and entitled to receive cumulative cash
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 an ownership change, as defined, 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.

In November 1996 the Company purchased 3,770,110 of the outstanding shares
for $24.50 per share. The excess of the cost of the acquired shares ($94.0
million, including related costs of $1.7 million) over the book value of such
shares, $33.7 million, is reflected in the Statement of Operations as a
preferred dividend. At December 31, 1996, 1,229,890 shares were outstanding.

(11) SHAREHOLDERS' EQUITY

$.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 which decline from $9.058
per share on May 15, 1997 to $8.875 per share on May 14, 1998, 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

SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
event of any voluntary liquidation, dissolution or winding up of the affairs of
the Company; conversion rights, if any; and voting powers, if any.

SHAREHOLDER RIGHTS PLAN

The Company has adopted a shareholder rights plan (the "Rights Plan")
whereby preferred stock purchase rights (the "Rights") will be distributed to
holders of the Company's common stock. The Rights will expire two years after
the Proposed Spin Off or on March 3, 2000, whichever occurs first. The Rights
will be exercisable only if a person acquires beneficial ownership of 15 percent
or more of the Company's common stock (an "Acquiring Person"), or commences a
tender offer which would result in ownership of 15 percent or more of such
stock. Under the Rights Plan, one Right to purchase one one-hundredth of a share
of a new series of junior preferred stock of the Company at an exercise price of
$42.00 per one one-hundredth of a share (subject to adjustment) will be issued
for each outstanding share of the Company's common stock held at the close of
business on March 3, 1997.

If any person becomes an Acquiring Person, each Right will entitle the
holder to purchase, at the Right's then current exercise price, shares of the
Company's common stock having a value of twice the Right's exercise price. In
addition, if, after a person becomes an Acquiring Person, the Company is
involved in a merger or other business combination transaction with another
person in which the Company is not the surviving corporation, or under certain
other circumstances, each Right will entitle its holder to purchase, at the
Right's then current exercise price, shares of common stock of the other person
having a value of twice the Right's exercise price.

The Company will generally be entitled to redeem the Rights in whole, but
not in part, at $0.01 per Right payable in cash or common stock, subject to
adjustment, at any time until 10 business days (subject to extension) after the
first public announcement that an Acquiring Person has become such.

The terms of the Rights may be amended by the Company without the approval
of the holders of the Rights at any time the Rights are redeemable. At any time
the Rights are no longer redeemable the terms may be amended only to (i) cure
any ambiguity; (ii) correct or supplement any provision which may be defective
or inconsistent with other provisions; (iii) shorten or lengthen any time
period; or (iv) change or supplement the provisions in any manner which the
Company deems necessary or desirable, so long as such change does not adversely
affects the interests of the holders of the Rights.

(12) STOCK OPTION PLANS

Under the terms of the Santa Fe Energy Resources 1990 Incentive Stock
Compensation Plan (the "1990 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. Under the terms of the Santa Fe Energy Resources
1995 Incentive Stock Compensation Plan (the "1995 Plan") 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. Awards
made under the terms of the 1990 Plan and the 1995 Plan (collectively the
"Plans") may be made in the form of Restricted Stock, Bonus Stock, Phantom
Units and Stock Appreciation Rights, as such terms are defined in the Plans.

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

Options under the terms of the Plans are granted at the average market
price on the date of grant and have a ten-year term with vesting periods ranging
from six months to three years. The following table summarizes the activity with
respect to options outstanding under the Plans during 1996 and 1995:

1996 1995
-------------------------------- --------------------------------
WEIGHTED AVERAGE WEIGHTED AVERAGE
SHARES EXERCISE PRICE SHARES EXERCISE PRICE
(THOUSANDS) ($/SHARE) (THOUSANDS) ($/SHARE)
------------ ---------------- ------------ ----------------

Outstanding at beginning of year..... 4,441.7 11.85 4,039.7 12.23
Grants............................... 1,240.5 12.07 472.7 8.75
Cancellations........................ (27.9) 11.31 (61.3) 13.47
Exercises............................ (280.3) 8.73 (9.4) 9.41
------------ ------------
Outstanding at end of year........... 5,374.0 12.07 4,441.7 11.85
============ ============
Exercisable at end of year........... 4,265.6 4,218.6
Weighted average fair value of
options granted during year
($/share).......................... 6.67 4.80

The fair value of each option grant is estimated on the date of grant using
the Black-Scholes option-pricing model with the following assumptions: (i)
expected dividend yield -- 0.0%; (ii) expected stock price volatility -- 22 to
27%; (iii) risk-free interest rate -- 5 to 7%; and (iv) expected life of
options -- 10 years.

The following table summarizes certain information with respect to options
outstanding under the Plans at December 31, 1996:

OPTIONS OUTSTANDING OPTIONS EXERCISABLE
-------------------------------------------------------------------------- ---------------------------------
RANGE OF WEIGHTED AVERAGE WEIGHTED AVERAGE WEIGHTED AVERAGE
EXERCISE PRICES SHARES REMAINING LIFE EXERCISE PRICE SHARES EXERCISE PRICE
($/SHARE) (THOUSANDS) (YEARS) ($/SHARE) (THOUSANDS) ($/SHARE)
--------------- ----------- ----------------- ---------------- ----------- -----------------

7-10 2,714.6 7 9.06 2,685.2 9.05
11-15 2,186.7 7 13.31 1,107.7 14.29
23-25 472.7 4 23.62 472.7 23.62
-----------
5,374.0 4,265.6
===========

In December 1995 the Company granted 0.1 million Phantom Units to certain
executive officers which were to be earned over a three-year period commencing
January 1, 1996. The Phantom Units vested as a result of the IPO. The Company
recognized $1.6 million in expense in 1996 with respect to such Phantom Units.

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

In December 1996 the Company granted 0.2 million Phantom Units to certain
executive officers and key personnel which are to be earned over a three-year
period commencing January 1, 1997. During 1996 and 1995 the Company granted 0.1
million and 0.2 million, respectively, shares of restricted stock to certain
executive officers and other employees. At December 31, 1996 1.4 million shares
were available for options or awards under the 1990 Plan and 1.0 million shares
were available under the 1995 Plan.

Under the terms of the Monterey Resources, Inc. 1996 Incentive Stock
Compensation Plan (the "Monterey Plan"), Monterey may grant options and awards
with respect to up to 3.0 million shares of common stock to officers, directors
and key employees, including up to 0.5 million shares of restricted stock.
During 1996 Monterey granted options on 0.2 million shares at an average
exercise price of $14.59 per share, with each option granted having an average
fair value of $7.77 per share. The grants were made at the market price at the
date of grant, have a ten year term and vest one year from the date of grant.
The fair value of each option grant is estimated on the date of grant using the
Black-Scholes option-pricing model with the following assumptions: (i) expected
dividend yield -- 0.0%; (ii) expected stock price volatility -- 24%; (iii)
risk-free interest rate -- 6.4%; and (iv) expected life of options -- 10 years.

During 1996 Monterey also issued 0.1 million restricted shares which vest
over a five-year period from the date of grant.

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 method prescribed by
Accounting Principles Board Opinion No. 25 "Accounting for Stock Issued to
Employees" ("APB 25"). The Company has elected to continue to account for
stock-based compensation costs based on the fair value of options granted as
prescribed by FAS 123. Earnings (loss) attributable to common shares and the
related per share amounts would have been reduced as is reflected by the
proforma amounts in the following table (in millions of dollars, except per
share data):

YEAR ENDED DECEMBER
31,
--------------------
1996 1995
--------- ---------
As Reported:
Earnings (loss) attributable to
common shares................. (10.8) 11.8
Earnings (loss) attributable to
common shares per share....... (0.12) 0.13
Proforma:
Earnings (loss) attributable to
common shares................. (12.6) 10.9
Earnings (loss) attributable to
common shares per share....... (0.14) 0.12

During the initial phase-in period, the effects of applying FAS 123 for
recognizing compensation cost on a proforma basis may not be representative of
the effects on reported earnings for future periods since the options granted
vest over several periods and additional awards will be made in future periods.

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

(13) 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.

The following table sets forth the funded status of the SFER Plan and the
Supplemental Plan at December 31, 1996 and 1995 (in millions of dollars):

SFER PLAN SUPPLEMENTAL PLAN
-------------------- --------------------
1996 1995 1996 1995
--------- --------- --------- ---------

Plan assets at fair value, primarily
invested in common stocks and U.S.
and corporate bonds................ 36.1 32.5 -- --
Actuarial present value of projected
benefit obligations:
Accumulated benefit obligations
Vested.................... (30.8) (30.4) (1.6) (0.7)
Nonvested................. (1.7) (1.3) (0.2) --
Effect of projected future
salary
increases.................... (8.3) (7.3) (1.4) (1.3)
--------- --------- --------- ---------
Excess of projected benefit
obligations over plan assets....... (4.7) (6.5) (3.2) (2.0)
Unrecognized net loss from past
experience different from that
assumed and effects of changes in
assumptions........................ 1.2 3.0 (1.1) (2.1)
Unrecognized prior service cost...... (1.9) (2.0) 1.9 2.0
Unrecognized net (asset) obligation
being recognized over plan's
average remaining
service life....................... (0.8 (0.9) 0.2 0.2
--------- --------- --------- ---------
Accrued pension liability............ (6.2) (6.4) (2.2) (1.9)
========= ========= ========= =========
Major assumptions at year-end
Discount rate................... 7.50% 7.50% 7.50% 7.50%
Long-term asset yield........... 9.50% 9.50% -- --
Rate of increase in future
compensation................. 5.25% 5.25% 5.25% 5.25%

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

The following table sets forth the components of pension expense for the
SFER Plan and Supplemental Plan for 1996, 1995 and 1994 (in millions of
dollars):

SFER PLAN SUPPLEMENTAL PLAN
---------------------- ----------------------
1996 1995 1994 1996 1995 1994
---- ---- ---- ---- ---- ----

Service cost......................... 1.6 1.3 1.7 0.1 0.4 --
Interest cost........................ 2.9 2.7 2.8 0.2 0.4 0.1
Return on plan assets................ (4.1) (5.5) 0.5 -- -- --
Net amortization and deferral........ 0.8 2.5 (3.3) -- 0.3 --
---- ---- ---- ---- ---- ----
1.2 1.0 1.7 0.3 1.1 0.1
==== ==== ==== ==== ==== ====

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.

The following table sets forth the funded status of the Hourly Plan at
December 31, 1996 and 1995 (in millions of dollars):

1996 1995
--------- ---------
Plan assets at fair value, primarily
invested in fixed-rate securities.... 9.5 8.7
Actuarial present value of projected
benefit obligations
Accumulated benefit obligations
Vested.................... (10.9) (10.4)
Nonvested................. (0.4) (0.4)
--------- ---------
Excess of projected benefit
obligation over plan assets........ (1.8) (2.1)
Unrecognized net (gain) loss from
past experience different from that
assumed and effects of changes in
assumptions........................ (0.4) (0.3)
Unrecognized prior service cost...... 0.4 0.4
Unrecognized net obligation.......... 1.0 1.2
Additional minimum liability......... (1.1) (1.3)
--------- ---------
Accrued pension liability....... (1.9) (2.1)
========= =========
Major assumptions at year-end
Discount rate................... 7.50% 7.50%
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 1996, 1995 and 1994 (in millions of dollars):

YEAR ENDED DECEMBER 31,
-------------------------------
1996 1995 1994
--------- --------- ---------
Service cost.................... 0.2 0.2 0.2
Interest cost................... 0.8 0.8 0.8
Return on plan assets........... (0.9) (1.4) (0.4)
Net amortization and deferral... 0.4 0.9 --
--------- --------- ---------
0.5 0.5 0.6
========= ========= =========

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

The Company sponsors 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, 1996 and 1995 (in millions of
dollars):

1996 1995
--------- ---------
Plan assets.......................... -- --
Actuarial present value of projected
benefit obligations:
Accumulated benefit
obligations..................
Vested.......................... (0.1) --
Nonvested....................... (0.2) (0.2)
Effect of projected future
salary increases............. (0.1) --
--------- ---------
Excess of projected benefit
obligations over plan assets....... (0.4) (0.2)
Unrecognized prior service costs..... 0.1 0.1
--------- ---------
Accrued pension liability............ (0.3) (0.1)
========= =========
Major assumptions at year-end:
Discount rate................... 7.50% 7.50%
Rate of increase in future
compensation................. 5.00% 5.00%

The following table sets forth the components of pension expense for the
Foreign Plan for 1996, 1995 and 1994 (in millions of dollars):

YEAR ENDED DECEMBER 31,
-------------------------------
1996 1995 1994
--------- --------- ---------
Service cost......................... 0.1 0.1 --
Interest cost........................ -- -- --
Net amortization and deferral........ -- -- --
--------- --------- ---------
0.1 0.1 --
========= ========= =========

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

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 retiree. The
following table sets forth the plan's funded status at December 31, 1996 and
1995 (in millions of dollars):

DECEMBER 31,
--------------------
1996 1995
--------- ---------
Plan assets, at fair value........... -- --
Accumulated postretirement benefit
obligation
Retirees........................... (4.2) (4.6)
Eligible active participants....... (1.0) (1.4)
Other active participants.......... (2.1) (1.2)
--------- ---------
Accumulated postretirement benefit
obligation in excess of plan
assets............................. (7.3) (7.2)
Unrecognized transition obligation... 3.7 3.8
Unrecognized net loss (gain) from
past experience different from that
assumed and from changes in
assumptions........................ (0.2) 0.3
--------- ---------
Accrued postretirement benefit
cost............................... (3.8) (3.1)
========= =========
Assumed discount rate................ 7.50% 7.75%
Assumed rate of compensation
increase........................... 5.25% 5.25%

The Company's net periodic postretirement benefit cost for 1996, 1995 and
1994 includes the following components (in millions of dollars):

YEAR ENDED DECEMBER 31,
------------------------
1996 1995 1994
---- ---- ----
Service costs........................ 0.5 0.3 0.4
Interest costs....................... 0.5 0.5 0.5
Amortization of unrecognized
transition obligation.............. 0.3 0.3 0.3
---- ---- ----
1.3 1.1 1.2
==== ==== ====

Estimated costs and liabilities have been developed assuming trend rates
for growth in future health care costs beginning with 8.0% for 1996 graded to
6.0% (5.5% for post age 65) by the year 2000 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, 1996 by $0.4 million and the aggregate of the service cost and interest cost
components of the net periodic postretirement benefit cost for 1997 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 made in
the form of the Company's common stock and charged to expense, totalled $1.2
million in 1996, $1.3 million in 1995 and $1.2 million in 1994.

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

The Company also has a savings plan with respect to certain personnel
employed in foreign locations. The plan is an unsecured creditor of the Company
and at December 31, 1996 and 1995 the Company's liability with respect to the
plan totalled $0.3 million and $0.1 million, respectively.

(14) COMMITMENTS AND CONTINGENCIES

OIL AND GAS HEDGING

Crude oil sales hedges resulted in a $13.4 million decrease in revenues in
1996 and a $2.4 million increase in revenues in 1995. At December 31, 1996 the
Company had open crude oil sales hedges on an average of 2,000 barrels per day
for the period January to June 1997. Under the terms of the instruments, if the
average of the applicable daily settlement prices is below $21.00 per barrel,
the Company will receive a settlement based on the difference, and if the
average of the applicable daily settlement prices is above $26.10, the Company
will be required to pay an amount based on the difference.

Subsequent to year end, the Company entered into additional agreements
which increased the number of barrels hedged to an average of approximately
7,700 barrels per day for the period January to July 1997. The instruments used
have floors ranging from $21.00 to $23.00 per barrel and ceilings ranging from
$24.00 to $27.00 per barrel. Under the terms of the instruments, if the
aggregate average of the applicable daily settlement prices is below the floor,
the Company will receive a settlement based on the difference, and if the
aggregate average of the applicable daily settlement prices is above the
ceiling, the Company will be required to pay an amount based on the difference.

At December 31, 1996 the Company had no open natural gas sales hedges.
Natural gas sales hedges resulted in a decrease in revenues of $21.4 million in
1996, $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 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. Such
hedges resulted in a $3.2 million increase in production and operating costs.

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
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

SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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
Environmental Protection Agency (the "EPA") and, in some cases, third parties
to take actions in response to threats to the public health or the environment
and to seek to recover from the responsible classes of 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. Certain
properties owned or used by the Company or its predecessors have been
investigated under state and Federal Superfund statutes, and the Company has
been and could be named a potentially responsible party ("PRP") for the
cleanup of some of these sites.

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

Pursuant to the Contribution Agreement, Monterey agreed to indemnify and
hold harmless Santa Fe from and against any costs incurred in the future
relating to environmental liabilities of the Western Division assets (other than
those retained by Santa Fe), including any costs or expenses incurred at any of
the OII Site, the Santa Fe Springs Site and the Eastside Site, and any costs or
liabilities that may arise in the future that are attributable to laws, rules or
regulations in respect to any property or interest therein located in California
and formerly owned or operated by the Western Division or its precedessors.

EMPLOYMENT AGREEMENTS

The Company has entered into employment agreements with eleven employees.
The initial term of ten of the agreements expire on December 31, 1998; however,
beginning January 1, 1998 and on each January 1 thereafter, the term is
automatically extended for one-year periods, unless by September 30 of the
preceding year the Company gives notice that the agreement will not be extended.
The term of the agreements is automatically extended for a period of two years
following a change of control. The initial term of the other agreement expires
December 31, 1999 and beginning January 1, 1999, is automatically extended for
one-year periods and is automatically extended for a three-year period following
a change of control.

In the event following a change in control employment is terminated by the
employee for "good reason" or the employee is involuntarily terminated by the
Company other than for "cause" (as those terms are defined in the employment
agreements), or if during the six months preceding a change in control, the
employee's employment is terminated by the employee for good reason or by the
Company other than for cause, and such termination is demonstrated to be
connected with the change in control, the employment agreements provide for
payment of certain amounts to the employee based on the employee's salary and
bonus under the Company's incentive compensation plan; payout of non-vested
restricted stock, phantom units, stock options, if any, and continuation of
certain insurance benefits on a tax neutral basis for a period of up to 36
months. The payments and benefits are payable pursuant to the employment
agreements only to the extent they are not paid out under the terms of any other
plan of the Company. The payments and benefits provided by the employment
agreements may be limited, with the exception of those made to Mr. Payne, by
certain provisions of the Internal Revenue Code.

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

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: 1997 -- $6.2 million,1998 -- $5.7 million,
1999 -- $3.7 million,2000 -- $1.9 million, 2001 -- $1.5 million and $6.1 million
thereafter. Rental expense under the terms of noncancellable agreements totalled
$5.9 million in 1996, $6.1 million in 1995 and $6.2 million in 1994.

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 operations in Kern County, California. In the
aggregate, these contracts involve a minimum commitment on the part of the
Company of approximately $18.6 million per year (based on prices and
transportation charges in effect for December 1996). In connection with the
development of a gas field in Argentina in which the Company has a 19.9% working
interest, a gas contract 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.

(15) 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, 1996 and 1995 balance sheets (in millions of dollars):

1996 1995
------------------- -------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
-------- ----- -------- -----

Liabilities
Long-Term Debt.................. 278.5 315.4 344.4 378.5
Convertible Preferred Stock, 7%
Series....................... 19.7 28.4 80.0 95.6
Shareholders' Equity
$.732 Series A Convertible
Preferred Stock.............. 91.4 131.1 91.4 105.7

The fair value of the Company's 11% Senior Subordinated Debentures,
Convertible Preferred Stock, 7% Series and $.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
the carrying amount approximates fair value.

At December 31, 1996 the Company had open oil sales hedging contracts (see
Note 14). Based on the year-end 1996 settlement prices of the applicable NYMEX
futures contracts, the Company would recognize no gain or loss with respect to
such hedges in 1997. The actual gains or losses realized by the Company from
these hedges may vary significantly due to the volatility of the futures markets
and other indices.

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

(16) SUMMARIZED QUARTERLY FINANCIAL DATA (UNAUDITED)

1 QTR 2 QTR 3 QTR 4 QTR YEAR
------ ------ ------ ------ -----
(IN MILLIONS OF DOLLARS EXCEPT PER SHARE DATA)

1996(A)
Revenues........................ 123.7 137.5 149.4 172.7 583.3
Gross profit (b)................ 35.5 33.9 40.3 9.9 119.6
Impairment of oil and gas
properties.................... -- 10.4 -- 47.0 57.4
Loss (gain) on sale of assets... 0.2 0.3 -- (12.6) (12.1)
Income (loss) from operations... 29.5 26.0 33.9 0.1 89.5
Income (loss) before
extraordinary items........... 12.6 17.4 16.5 (4.1) 42.4
Extraordinary item -- debt
extinguishment costs.......... -- -- -- 6.0 6.0
Net income (loss)............... 12.6 12.4 16.5 (10.1) 36.4
Earnings (loss) attributable to
common shares................. 8.9 13.7 12.8 (46.2) (10.8)
Earnings (loss) attributable to
common shares per share
Earnings (loss) before
extraordinary items...... 0.10 0.15 0.14 (0.44) (0.05)
Extraordinary items........ -- -- -- (0.07) (0.07)
Earnings (loss) to common
shares................... 0.10 0.15 0.14 (0.51) (0.12)
Average shares outstanding
(millions).................... 90.4 90.6 90.6 90.9 90.6
1995
Revenues........................ 100.3 111.4 113.4 124.3 449.4
Gross profit (b)................ 18.4 29.4 26.9 6.1 80.8
Income (loss) from operations... 12.5 22.5 19.8 (0.9) 53.9
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

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

(a) The fourth quarter of 1996 includes impairments of oil and gas properties of
$47.0 million (see Note 1), a $12.3 million gain on the sale of certain
surface lands (see Note 6), a $6.0 million extraordinary item with respect
to debt extinguishment costs (see Note 2) and a $33.7 million convertible
preferred redemption premium (see Note 10).

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

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, 1993, 1994, 1995 and 1996 and the changes in net proved
oil and gas reserves for the years ended December 31, 1994, 1995 and 1996.

CRUDE OIL AND LIQUIDS (MMBBLS) NATURAL GAS (BCF)
---------------------------------------- ---------------------------------------------
U.S. ARGENTINA INDONESIA TOTAL U.S. ARGENTINA INDONESIA TOTAL
--------- --------- --------- ----- --------- --------- ---------- ---------

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
Revisions to previous estimates.... 15.6 (0.2) 2.3 17.7 25.9 (2.4) (0.2) 23.3
Improved recovery techniques....... 14.4 -- -- 14.4 -- -- -- --
Extensions, discoveries and other
additions........................ 0.6 1.3 0.3 2.2 40.8 1.1 -- 41.9
Purchases of minerals-in-place..... 10.7 2.8 -- 13.5 11.7 0.6 -- 12.3
Sales of minerals-in-place......... (0.3) -- -- (0.3) (2.1) -- -- (2.1)
Production......................... (24.3) (1.4) (1.5) (27.2) (53.4) (7.6) (0.1) (61.1)
--------- --------- --------- ----- --------- --------- ---------- ---------
Proved reserves at December 31,
1996................................ 275.3 15.3 8.9 299.5 232.8 26.4 0.2 259.4
========= ========= ========= ===== ========= ========= ========== =========

(TABLE CONTINUED ON FOLLOWING PAGE)

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

CRUDE OIL AND LIQUIDS (MMBBLS) NATURAL GAS (BCF)
----------------------------------------- ---------------------------------------------
U.S. ARGENTINA INDONESIA TOTAL U.S. ARGENTINA INDONESIA TOTAL
--------- --------- ---------- ----- --------- --------- ---------- ---------

Proved developed reserves at
December 31
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
1996............................ 224.1 8.5 6.5 239.1 193.6 25.9 0.2 219.7

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, 1996, the quantities include 0.6 million barrels which the Company is
contractually obligated to sell for $.20 per barrel.

The Company has certain commitments with respect to the delivery of natural
gas (see Note 14) which the Company believes it can fulfill from its proved
reserves and supply contracts with other companies.

At December 31, 1996 U.S. proved reserves included 216.4 MMBbls of crude
oil and liquids (171.0 MMBbls of which were proved developed) and 12.2 Bcf of
natural gas (9.5 Bcf of which were proved developed) attributable to Monterey.

At December 31, 1996, 2.0 million barrels of crude oil reserves and 14.1
billion cubic feet of natural gas reserves were subject to a 90% net profits
interest held by Santa Fe Energy Trust.

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, 1996, 1995 and 1994 are presented in the following
table (in millions of dollars, except as noted):

U.S. ARGENTINA INDONESIA TOTAL
---------- --------- --------- ----------

1996
Future cash inflows............. 6,393.6 377.7 191.8 6,963.1
Future production costs......... (2,792.7) (138.8) (135.2) (3,066.7)
Future development costs........ (286.7) (53.0) (22.5) (362.2)
Future income tax expenses...... (999.2) (33.4) (11.9) (1,044.5)
---------- --------- --------- ----------
Net future cash flows..... 2,315.0 152.5 22.2 2,489.7
Discount at 10% for timing of
cash flows................... (951.2) (54.3) (7.1) (1,012.6)
---------- --------- --------- ----------
Present value of future net cash
flows from
proved reserves.............. 1,363.8 98.2 15.1 1,477.1
========== ========= ========= ==========
Present value of pretax future
net cash flows from proved
reserves..................... 1,952.3 119.6 23.6 2,095.5
========== ========= ========= ==========
Average sales prices
Oil ($/Barrel)............ 20.35 22.62 21.67 20.51
Natural gas ($/Mcf)....... 3.47 1.20 1.05 3.24
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 ($/Barrel)............ 14.75 15.66 17.51 14.87
Natural gas ($/Mcf)....... 1.88 1.27 1.03 1.79
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 ($/Barrel)............ 13.18 14.06 15.21 13.28
Natural gas ($/Mcf)....... 1.63 1.25 0.97 1.57

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

The following tables sets forth the changes in the present value of
estimated future net cash flows from proved reserves during 1996, 1995 and 1994
(in millions of dollars):

U.S. ARGENTINA INDONESIA TOTAL
------ --------- --------- ---------

1996
Balance at beginning of year....... 841.9 58.1 30.2 930.2
------ --------- --------- ---------
Increase (decrease) due to:
Sales of oil and gas, net of
production costs of $210.8
million...................... (311.7) (25.6) (13.9) (351.1)
Net changes in prices and
production costs............. 552.1 35.0 (8.3) 578.8
Extensions, discoveries and
improved recovery............ 169.1 16.4 0.8 186.3
Purchases of
minerals-in-place............ 92.5 19.2 -- 111.7
Sales of minerals-in-place...... (3.3) -- -- (3.3)
Development costs incurred...... 145.4 19.5 12.9 177.8
Changes in estimated volumes.... 152.3 6.6 3.1 162.0
Changes in estimated development
costs........................ (100.8) (23.4) (22.8) (147.0)
Interest factor -- accretion of
discount..................... 113.7 6.6 3.0 123.2
Income taxes.................... (287.4) (14.2) 10.1 (291.5)
------ --------- --------- ---------
521.9 40.1 (15.1) 546.9
------ --------- --------- ---------
1,363.8 98.2 15.1 1,477.1
====== ========= ========= =========

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 $172.6
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
====== ========= ========= =========

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

U.S. ARGENTINA INDONESIA TOTAL
------ --------- --------- ---------

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 $172.2
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
====== ========= ========= =========

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.

At December 31, 1996 approximately $126.0 million of the Company's
estimated present value of future net cash flows were attributable to the
minority interest in Monterey.

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):

OTHER
U.S. ARGENTINA INDONESIA FOREIGN TOTAL
--------- --------- --------- -------- ------

1996
Property acquisition costs
Unproved........................ 31.6 -- -- 1.8 33.4
Proved.......................... 30.2 7.4 -- 0.2 37.8
Exploration costs.................. 29.5 0.1 2.4 11.4 43.4
Development costs.................. 115.2 12.1 12.9 3.9 144.1
--------- --------- --------- -------- ------
206.5 19.6 15.3 17.3 258.7
========= ========= ========= ======== ======
1995
Property acquisition costs
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.......................... 1.9 0.3 -- -- 2.2
Exploration costs.................. 19.3 1.2 7.5 6.8 34.8
Development costs.................. 81.6 13.0 9.3 0.1 104.0
--------- --------- --------- -------- ------
107.3 14.6 17.4 7.1 146.4
========= ========= ========= ======== ======

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, 1996 and 1995 related to the Company's oil and gas operations (in
millions of dollars):

1996 1995
---------------------------------------------------------- --------------------
OTHER
U.S. ARGENTINA INDONESIA FOREIGN TOTAL U.S. ARGENTINA
--------- ---------- --------- ------- --------- ------- ---------

Oil and gas properties
Unproved......................... 63.8 4.5 11.8 1.9 82.0 41.7 4.5
Proved........................... 2,236.8 90.3 113.9 5.3 2,446.3 2,090.6 70.8
Other............................ 11.5 -- -- -- 11.5 12.8 --
Accumulated amortization of unproved
properties......................... (18.9) (2.4) (4.4) (1.4) (27.1) (12.8) (2.4)
Accumulated depletion, depreciation
and impairment of proved
properties......................... (1,523.9) (23.4) (63.8) (3.5) (1,614.6) (1,385.9) (15.9)
Accumulated depreciation of other oil
and gas properties................. (4.4) -- -- -- (4.4) (5.3) --
--------- ---------- --------- ------- --------- ------- ---------
764.9 69.0 57.5 2.3 893.7 741.1 57.0
========= ========== ========= ======= ========= ======= =========

OTHER
INDONESIA FOREIGN TOTAL
--------- ------- ---------
Oil and gas properties
Unproved......................... 12.0 3.0 61.2
Proved........................... 99.1 1.8 2,262.3
Other............................ -- -- 12.8
Accumulated amortization of unproved
properties......................... (3.8) (1.8) (20.8)
Accumulated depletion, depreciation
and impairment of proved
properties......................... (39.7) -- (1,441.5)
Accumulated depreciation of other oil
and gas properties................. -- -- (5.3)
--------- ------- ---------
67.6 3.0 868.7
========= ======= =========

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, 1996, 1995 and
1994 (in millions of dollars):

OTHER
U.S. ARGENTINA INDONESIA FOREIGN TOTAL
------ --------- --------- ------- ---------

1996
Revenues........................... 517.9 35.8 29.6 -- 583.3
Production costs
Production and operating
costs........................ (162.4) (10.0) (15.7) (0.3) (188.4)
Taxes (other than income)....... (22.2) (0.2) -- -- (22.4)
Cost of crude oil purchased........ (20.8) -- -- -- (20.8)
Exploration, including dry hole
costs........................... (21.9) (0.1) (0.6) (11.9) (34.5)
Depletion, depreciation,
amortization and impairments.... (164.9) (7.9) (24.6) (5.0) (202.4)
Gain (loss) on disposition of
properties...................... 0.3 -- -- (0.2) 0.1
------ --------- --------- ------- ---------
126.0 17.6 (11.3) (17.4) 114.9
Income taxes....................... (49.6) (5.3) 2.9 3.5 (48.5)
------ --------- --------- ------- ---------
76.4 12.3 (8.4) (13.9) 66.4
====== ========= ========= ======= =========
1995
Revenues........................... 398.6 19.2 31.6 -- 449.4
Production costs
Production and operating
costs........................ (130.6) (7.1) (17.7) (0.4) (155.8)
Taxes (other than income)....... (16.5) (0.3) -- -- (16.8)
Cost of crude oil purchased........ (6.5) -- -- -- (6.5)
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........................... 359.5 12.9 31.8 -- 404.2
Production costs
Production and operating
costs........................ (130.8) (5.5) (14.6) (0.2) (151.1)
Taxes (other than income)....... (21.0) (0.1) -- -- (21.1)
Cost of crude oil purchased........ (11.7) -- -- -- (11.7)
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
====== ========= ========= ======= =========

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.

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/ JANET F. CLARK
JANET F. CLARK
VICE PRESIDENT AND CHIEF
FINANCIAL OFFICER
(PRINCIPAL FINANCIAL AND
ACCOUNTING OFFICER)

Dated: March 11, 1997

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)

JANET F. CLARK, Vice President
and Chief Financial Officer
(PRINCIPAL FINANCIAL AND ACCOUNTING OFFICER)

DIRECTORS
-----------
William E. Greehey By: /s/ JANET F. CLARK
Melvyn N. Klein JANET F. CLARK
Allan V. Martini VICE PRESIDENT AND
Marc J. Shapiro CHIEF FINANCIAL OFFICER
Kathryn D. Wriston ATTORNEY IN FACT

Dated: March 11, 1997

SANTA FE ENERGY RESOURCES, INC.
SCHEDULE VIII -- VALUATION AND QUALIFYING ACCOUNTS
THREE YEARS ENDED DECEMBER 31, 1996
(IN MILLIONS OF DOLLARS)

===================================================================
1996 1995 1994
- -------------------------------------------------------------------
Accounts receivable
Balance at the beginning of
period........................ 2.0 3.1 6.3
Charge (credit) to
income.................. 0.5 -- 0.6
Net amounts written off... -- (1.1) (3.8)
----- ----- -----
Balance at the end of period.... 2.5 2.0 3.1
===== ===== =====

100

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, Preferences and
Rights of the 7% Convertible Preferred Stock of SFER,
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) -- Rights Agreement dated as of March 3, 1997, between
SFER, Inc. and First Chicago Trust Company of New York,
as Rights Agent (incorporated by reference to Exhibit 1
to SFER, Inc.'s Form 8-A filed February 28, 1997.)

4(c) -- Form of Amended Certificate of Designations of Series A
Junior Participating Preferred Stock of SFER, Inc.
(incorporated by reference to Exhibit 1 to SFER, Inc.'s
Form 8-A filed February 28, 1997).

4(d) -- Note Agreement dated as of November 19, 1996 by and
among Monterey Resources, Inc. and various institutional
investors relating to the issuance of $175,000,000 of
Senior Notes maturing in 2005 (incorporated by reference
to Exhibit 10.15 to Monterey Resources, Inc.'s
[Commission File No. 1-12311] Annual Report on Form 10-K
for the year ended December 31, 1996).

4(e) -- Form of Certificate of Designation of the Dividend
Enhanced Convertible Stock, $.732 Series A Convertible
Preferred Stock of SFER, 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 SFER, Inc.'s 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).

4(g) -- First Supplemental Indenture, dated as of October 21,
1996, between SFER, Inc. and State Street Bank and Trust
Company, as Trustee, relating to SFER Inc.'s 11% Senior
Subordinated Debentures due 2004 (incorporated by
reference to Exhibit 10.1 to SFER Inc.'s Quarterly
Report on Form 10-Q for the quarter ended September 30,
1996).

10(a) -- Agreement for the Allocation of the Consolidated Federal
Income Tax Liability Among the Members of the Santa Fe
Pacific Corporation 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) -- SFER, Inc. Incentive Compensation Plan, as amended
(incorporated by reference to Exhibit 10(b) to SFER,
Inc.'s Annual Report on Form 10-K for the year ended
December 31, 1995).

10(c) -- SFER, Inc. 1990 Incentive Stock Compensation Plan, Third
Amendment and Restatement (incorporated by reference to
Exhibit 10(a) to SFER Inc.'s Quarterly Report on Form
10-Q for the quarter ended March 31, 1996).

*10(d) -- Examples of Employment Agreements entered into with
executive officers of SFER, Inc.

*10(e) -- Example of Indemnification Agreements with SFER Inc.'s
directors and officers.

*10(f) -- Spin-Off Tax Indemnification Agreement between SFER,
Inc. and Santa Fe Pacific Corporation.

*10(g) -- Agreement Concerning Taxes among SFER, Inc., certain
subsidiaries of SFER, Inc. and Santa Fe Pacific
Corporation.

101

INDEX OF EXHIBITS -- (CONTINUED)

EXHIBIT
NUMBER DESCRIPTION

*10(h) -- Santa Fe Energy Resources Supplemental Retirement Plan
effective as of December 4, 1990.

10(i) -- SFER, 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) -- Gas Marketing Agreement, dated as of December 14, 1993,
between SFER, 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(k) -- Credit Agreement dated as of November 13, 1996 among
SFER, Inc., the banks signatory thereto, and The Chase
Manhattan Bank, as Administrative Agent and ABN AMRO
Bank, N.V., as Co-Agent.

10(l) -- Credit Agreement dated as of November 13, 1996 among
Monterey Resources, Inc., the Banks signatory thereto
and The Chase Manhattan Bank, as Administrative Agent
(incorporated by reference to Exhibit 10.16 to Monterey
Resources, Inc.'s [Commission File No. 1-12311] Annual
Report on Form 10-K for the year ended December 31,
1996).

10(m) -- Agreement for the Allocation of Consolidated Federal
Income Tax Liability and State and Local Taxes among the
members of the SFER, Inc. affiliated Group dated
November 19, 1996 (incorporated by reference to Exhibit
10.2 to Monterey Resources Inc.'s [Commission File No.
1-12311] Annual Report on Form 10-K for the year ended
December 31, 1996).

10(n) -- Agreement Concerning Taxes and Tax Indemnifications upon
Spin-Off, dated November 19, 1996, between Monterey
Resources, Inc. and SFER, Inc. (incorporated by
reference to Exhibit 10.3 to Monterey Resources, Inc.'s
[Commission File No. 1-12311] Annual Report on Form 10-K
for the year ended December 31, 1996).

10(o) -- Registration Rights and Indemnification Agreement dated
November 19, , 1996, between Monterey Resources, Inc.
and SFER, Inc. (incorporated by reference to Monterey
Resources, Inc.'s [Commission File No. 1-12311] Annual
Report on Form 10-K for the year ended December 31,
1996).

10(p) -- Agreement Regarding Shelf Registration Statement dated
March 24, 1995 between SFER, 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 (incorporated by
reference to Exhibit 10(o) to SFER Inc.'s Annual Report
on Form 10-K for the year ended December 31, 1995).

10(q) -- Conveyance and Contribution Agreement dated as of
November 1, 1996, between Monterey Resources, Inc. and
SFER, Inc. (incorporated by reference to Monterey
Resources, Inc.'s [Commission File No. 1-12311] Annual
Report on Form 10-K for the year ended December 31,
1996).

*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, 33-59255 and
333-07949).

*23(b) -- Consent of Ryder Scott Company with respect to
Registration Statements on Form S-8 (Nos. 33-37175,
33-44541, 33-4452, 33-58613, 33-59253, 33-59255 and
333-07949).

*24 -- Powers of Attorney.

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

* Included in this report

B. REPORTS ON FORM 8-K.

DATE ITEM
------------------ -----
February 28, 1997 5

102