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

                                    FORM 10-K

    [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 1-12311
                            ------------------------

                            MONTEREY RESOURCES, INC.
             (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)

                  DELAWARE                         76-0511993
          (STATE OF INCORPORATION)    (I.R.S. EMPLOYER IDENTIFICATION NO.)

                               5201 TRUXTUN AVENUE
                          BAKERSFIELD, CALIFORNIA 93309
          (ADDRESS OF PRINCIPAL EXECUTIVE OFFICES, INCLUDING ZIP CODE)

       REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (805) 322-3992
                            ------------------------
           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 March 3, 1997 was approximately $144.8 million.

       Shares of Common Stock outstanding at March 3, 1997 -- 54,769,499.

                      DOCUMENTS INCORPORATED BY REFERENCE:

            PROXY STATEMENT DATED MARCH 24, 1997 .......... PART III

<PAGE>
                                TABLE OF CONTENTS

                                        PAGE
PART I
Items  1 and 2.  Business and
Properties...........................     1
           General...................     1
           Reserves..................     2
           Strategy..................     3
           Development Activities....     4
           Significant Producing
Properties...........................     5
           Development, Exploration
and Acquisition Activities...........     6
           Drilling Activities.......     7
           Producing Wells...........     7
           Acreage...................     7
           Current Markets for Oil
and Gas..............................     7
           Customers.................     8
           Relationship Between the
Company and SFR......................     9
           Other Business Matters....    11

Item  3.  Legal Proceedings..........    15
Item  4.  Submission of Matters to a
Vote of Security Holders.............    16
           Executive Officers of
Monterey.............................    16

PART II
Item  5.  Market for Registrant's
  Common Equity and Related
  Stockholder Matters................    16
Item  6.  Selected Financial Data....    18
Item  7.  Management's Discussion and
          Analysis of Financial
          Condition and Results Of
          Operations.................    20
Item  8.  Financial Statements and
  Supplementary Data.................    25
Item  9.  Changes in and
          Disagreements with
          Accountants on Accounting
          and Financial Disclosure...    26

PART III
Item 10.  Directors and Executive
  Officers of the Registrant.........    26
Item 11.  Executive Compensation.....    26
Item 12.  Security Ownership of
  Certain Beneficial Owners and
  Management.........................    26
Item 13.  Certain Relationships and
  Related Transactions...............    26

PART IV
Item 14.  Exhibits, Financial
          Statement Schedules and
          Reports on Form 8-K........    26
Signatures...........................    49

                                       i
<PAGE>
<PAGE>
                                     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 legal pressure base of the
state or area in which the reserves are located and at 60 degrees Fahrenheit.
"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, and include waterfloods, thermal techniques
(including cyclic steam, steam flood and in situ combustion operations) and CO2
(carbon dioxide) injection. "Heavy oil" or "heavy crude" is low gravity, high
viscosity crude oil. "Working interest" means an operating interest which gives
the owner the right to drill, produce and conduct operating activities on a
property and to a share of production and requires the owner to bear a
proportionate share of related expenses. "Net revenue interest" means the
percentage of production to which the owner of a working interest is entitled.
"Net acres" and "net wells" refer to the sum of the fractional working interests
owned in gross acres and gross wells, respectively. Unless otherwise indicated,
references to "reserves" means net proved reserves and references to "wells"
means gross wells.

ITEMS 1 AND 2.  BUSINESS AND PROPERTIES

GENERAL

     Monterey Resources, Inc. (the "Company" or "Monterey") is an independent
oil and gas company engaged in the production, development and acquisition of
oil and natural gas in the State of California. The Company was formed in 1996
to own the properties and conduct the business of the Western Division of Santa
Fe Energy Resources, Inc. (the "Western Division"). At December 31, 1996, Santa
Fe Energy Resources, Inc. ("SFR") owned 82.8% of the Company's outstanding
common stock. SFR has announced that, subject to certain conditions, it intends
to distribute pro rata to its common shareholders all of the shares of the
Company's common stock that it owns by means of a tax-free distribution (the
"Spin Off"). See " -- Relationship Between the Company and SFR".

     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 the Company for November and December.

     In November 1996, prior to the initial public offering (the "IPO")
discussed below, pursuant to a Contribution and Conveyance Agreement (the
"Contribution Agreement") (i) SFR contributed to the Company substantially all
of the assets and properties of the Western Division, subject to the retention
by SFR of a $30.0 million production payment; (ii) the Company assumed all
obligations and liabilities of SFR associated with or allocated to the assets
and properties of the Western Division, including $245.0 million of indebtedness
in respect of SFR'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 the "SFR Senior Notes", collectively);
(iii) the Company agreed to purchase from SFR an $8.3 million promissory note
receivable related to the sale to a third party of certain surface acreage
located in Orange County, California, and (iv) Monterey agreed to pay certain
investment advisory fees which approximate $3.5 million on behalf of SFR,
payable only upon the occurrence of the Spin Off. Also prior to the IPO, the
Company and SFR entered into a $75.0 million revolving credit facility with a
group of banks (the "Credit Facility") and borrowed $16.0 million which was
retained by SFR.

     In November 1996 the Company 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 costs of $2.6 million). The

                                       1
<PAGE>
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 Credit Facility; and (iv) pay a $2.0 million
fee with respect to a supplement to the indenture relating to SFR's 11% Senior
Subordinated Debentures due 2004 to permit the IPO and the Spin Off to proceed
without the occurrence of a breach or default under such indenture. Subsequent
to the IPO, the Company issued $175.0 million in aggregate principal amount of
10.61% Senior Notes due 2005 (the "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 the Company purchased the
previously mentioned $8.3 million note receivable from SFR for cash.

     At December 31, 1996 the Company had net proved reserves of approximately
218 MMBOE with a pre-tax net present value, discounted at 10%, of approximately
$1.05 billion ($680.7 million after tax), according to estimates prepared by
Ryder Scott. In 1996, the Company's operations generated total revenues of
approximately $292.9 million and net income of approximately $50.3 million.
During the year ended December 31, 1996, the Company's average production was
approximately 47.4 MBOE per day, resulting in a reserve-to-production ratio of
12.6 years.

     The Company owns and operates properties in four major oil producing fields
located in the San Joaquin Valley of California: Midway-Sunset, Kern River,
South Belridge and Coalinga. These fields are among the most prolific oil fields
in the United States, particularly the Midway-Sunset, Kern River, and South
Belridge fields which are the three largest producing oil fields in the lower 48
states. The Midway-Sunset field accounted for approximately 75% of the Company's
total proved reserves at December 31, 1996 and 74% of its average daily
production for 1996. An additional 18% of the Company's total proved reserves as
of December 31, 1996, and 21% of its average daily production for 1996 were
attributable to the Kern River, South Belridge and Coalinga fields. The Company
initiated production from the San Joaquin Valley fields in 1905 and nearly all
of the reserves in these fields have been characterized by low gravity and high
viscosity or "heavy" oil, the production of which depends primarily on thermally
enhanced recovery techniques. The Company holds an interest in approximately
16,000 gross acres in these fields with an average working interest in these
properties of approximately 99%.

RESERVES

     The table set forth below demonstrates the growth in the Company's proved
reserve base, as estimated by Ryder Scott Company, independent petroleum
engineers:

<TABLE>
<CAPTION>
                                                                           INCREASES (DECREASES)
                                                     -----------------------------------------------------------------
                                         BALANCE                                                 NET
                                           AT        REVISION                 EXTENSIONS,     PURCHASES                   BALANCE
                                        BEGINNING       OF                    DISCOVERIES     (SALES) OF                   AT END
                                           OF        PREVIOUS     IMPROVED        AND          MINERALS                      OF
                                         PERIOD      ESTIMATES    RECOVERY     ADDITIONS       IN PLACE     PRODUCTION     PERIOD
                                        ---------    ---------    --------    ------------    ----------    ----------    --------
<S>                                       <C>            <C>        <C>                           <C>          <C>          <C>  
PROVED RESERVES AT DECEMBER 31, 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
PROVED RESERVES AT DECEMBER 31, 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
PROVED RESERVES AT DECEMBER 31, 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
</TABLE>

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

                                       2
<PAGE>
     In 1996 the Company began to implement its plan to accelerate growth in
both production and reserves by increasing its investment in development
opportunities on its existing properties and tactical acquisitions to $52.2
million, an increase of $17.3 million above the $34.9 million per year average
of the previous four years. The 1996 investment program added 34.2 MMBOE of
proved reserves at a cost of $1.53 per BOE. Reserve additions were 197% of the
Company's 1996 production of 17.3 MMBOE. During the five years ended December
31, 1996, the Company spent a total of $172.9 million (an average of $34.6
million per year) on development activities on its properties. Cumulative
production from the Company's 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, the Company
believes that it can continue to make significant additions to proved reserves
on its properties through additional EOR and development projects, and the
Company has developed a large inventory of such projects from which it expects
to make such additions. The Company 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 the Company's 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 Company's prior
experience or expectations.

     During 1996 SFR filed Energy Information Administration Form 23 which
reported natural gas and oil reserves for the year 1995. The reserve estimates
reported on Form 23 are not comparable with the reserve estimates reported
herein because Form 23 requires that reserves be reported on a gross operated
basis rather than on a net interest basis. 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.

STRATEGY

     The Company's strategy is to efficiently and consistently increase its
production rates and proved reserves while maximizing total return to
stockholders. The Company intends to achieve its objectives by developing its
existing fields through the deployment of advanced production techniques, by
pursuing reserve acquisition opportunities which are consistent with its
geographic and operational strengths, and by maintaining a dividend policy that
will provide a significant current return to stockholders. Key elements of the
Company's production and reserve growth strategy include:

     AGGRESSIVE EXPLOITATION OF ITS LARGE DEVELOPMENT INVENTORY. During 1996 the
Company completed 317 well operations (which include development and injection
wells, workovers, and recompletions) on relatively low risk development and
infill drilling opportunities at a cost of $48.7 million, adding 26.6 MMBOE at a
finding and development cost of $1.83 per BOE. This activity level compares with
an average of 222 well operations per year over the previous four years. The
Company expects to complete more than 380 well operations in 1997 with budgeted
capital expenditures of approximately $71 million. The Company believes that its
sizable project inventory will allow it to continue to increase its production
and reserves over the next several years.

     INCREASED HORIZONTAL DRILLING. In order to increase production and ultimate
reserve recovery on its existing properties, the Company began utilizing
horizontal drilling in 1995 and expanded its use in 1996. As of December 31,
1996 the Company had a total of eight horizontal wells on production, including
seven wells that were drilled in 1996. These wells, which are all in the
Midway-Sunset field and incorporate several methods of steam assisted gravity
drainage, are currently producing at rates ranging from 20 to 200 Bbls per day
per well compared to a range of 5 to 25 Bbls per day for the typical vertical
wells. Performance of both vertical and horizontal wells are directly related to
the temperature of the formation in the immediate wellbore area with the higher
performance being exhibited by the wells that are hotter due to steam input to
the formation. The Company expects to complete 45 additional horizontal wells by
the end of 1997 at an expected capital cost of approximately $20 million,
although the actual number of horizontal wells drilled could be increased or
decreased based upon the results realized from the horizontal wells

                                       3
<PAGE>
completed. The Company believes that this technology represents a significant
opportunity for more cost effective development, increased reserves and
increased production and total recovery rates from its properties.

     LOW COST PRODUCER. The Company believes that its finding costs and
producing costs are among the lowest for heavy crude producers in the United
States. Due to the reservoir characteristics of the Company's producing
properties and the extensive development activities conducted to date thereon,
such properties are well suited to low cost development and exploitation
drilling. For example, the Company's average finding cost for the three years
ended December 31, 1996 was $1.58 per BOE. In addition, continuing cost control
efforts have contributed to the reduction of its non-fuel production and
operating costs from $3.56 per BOE in 1995 to $3.53 per BOE in 1996. This
reduction continues a long-term trend in which the Company has reduced non-fuel
production and operating expenses about 20% since 1992. The 1996 fuel-related
costs were $2.69 per BOE, up from $1.98 per BOE in 1995, largely due to higher
natural gas prices. The Company plans to continue to pursue operational
efficiencies, including facilities upgrades and process consolidations with
adjoining producers, to further reduce both finding and producing costs.

     APPLICATION OF ADVANCED TECHNOLOGIES. The Company will continue to utilize
its growing technology base, including increasing use of 3-D seismic surveys,
waterfloods, thermal EOR techniques including applications to substantial
deposits of heavy oil in Diatomite formations on its Midway-Sunset properties,
new fracturing techniques and reservoir modeling. The Company believes that 3-D
seismic techniques may identify significant additional reserves. As part of a
joint venture with Chevron U.S.A., Inc., the Company began 3-D seismic data
acquisition in late 1996 on a large acreage block that includes a portion of its
Midway-Sunset properties. The Company has extensive experience with EOR
techniques which it has improved over time and has conducted various types of
steam and in situ combustion operations on its properties since the 1960s. The
Company is currently focusing on efficient reservoir heat management techniques,
which are intended to optimize recoveries and minimize fuel costs. Technologies
as diverse as down-hole steam generation and microbial production enhancement
are part of the Company's ongoing pursuit of better technology. The Company
believes that its expertise in utilizing advanced technologies will allow it to
identify and recover additional reserves in its existing properties.

DEVELOPMENT ACTIVITIES

     The Company 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. The Company has
conducted thermal EOR projects in the San Joaquin Valley since the mid-1960s and
employs two principal techniques: cyclic steam stimulation, which involves the
injection of steam through a wellbore for a period of days or weeks after which
the same wellbore is used to produce oil, typically for a period of months; and
steam flooding, a process by which steam is injected into the center of a well
pattern and oil is produced from surrounding producing wells. In addition, the
Company has begun to utilize horizontal drilling in conjunction with the steam
projects already deployed. Based on results to date the Company believes that
horizontal wells can achieve production rates up to 10 times greater than the
typical vertical well and drain portions of reservoirs that cannot be
economically drained by vertical wells. The Company also employs a third
technique, referred to as in situ combustion, in which air is injected into a
dedicated wellbore, a combustion zone is established within a reservoir to heat
the oil and reduce its viscosity and oil is produced from surrounding wellbores.
In addition to these thermal techniques, 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.

     In 1996 the Company spent $48.7 million in 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. Development work was also done in 1996 in the Coalinga, South
Belridge and Beta fields.

                                       4
<PAGE>
SIGNIFICANT PRODUCING PROPERTIES

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

     MIDWAY-SUNSET. The Company 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 Midway-Sunset field is the largest
producing oil field in the lower 48 states and 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. Producing formations include (in order of increasing depth) the
Tulare and Etchegoin formations as well as the Potter, Spellacy and Diatomite
horizons of the Monterey formation.

     During 1996, the Company'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 the Company's 1996 crude
production. Total December 31, 1996 proved reserves for the Company's
Midway-Sunset properties were approximately 164.5 MMBOE, representing
approximately 75% of the Company's total proved reserves. The Company's
investment in development drilling, cyclic steam injection, steamflood, in situ
combustion and horizontal drilling in Midway-Sunset was approximately $35
million in 1996 compared to an average of $23 million per year over the previous
four years and production has increased from approximately 29.5 MBbls per day in
1992 to over 35.8 MBbls per day in December 1996.

     Despite record levels of production, the Company believes, based on
reservoir engineering studies prepared by Ryder Scott, that it can continue to
make significant additions to its proved reserves in this field through
additional EOR and development projects. While most of the Company's EOR efforts
in this field have concentrated on the Potter horizon, the Company believes that
these techniques may generate similar production and reserve additions in each
of the Spellacy, Tulare and Diatomite horizons. The Company 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. The Company owns and operates a 100% working interest (91%
average net revenue interest) in four properties in the Kern River field. The
Kern River field is the second largest producing oil field in the lower 48
states and the Company has operated there continuously since 1905. Most of the
oil produced from the 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 the Company's total crude production. As of
December 31, 1996, the Company's total proved reserves in the Kern River field
were approximately 19.1 MMBOE, or approximately 9% of its total proved reserves.

     The Company's production from the Kern River field has increased from
approximately 2 MBbls per day in 1990 to approximately 5 MBbls per day in 1996.
Capital expenditures over the same period of time have increased from $2.0
million in 1991 to $6.0 million in 1996.

     As with the Midway-Sunset field, management believes, based on engineering
studies prepared by Ryder Scott, that the Company can continue to make
significant additions to its proved reserves in the Kern River field through
additional thermal development projects. The Company has identified 94 well
operations (including 4 horizontal wells) that could be undertaken in the field
and anticipates completing 22 of these operations in 1997 at an estimated
capital cost of $3.0 million.

     SOUTH BELRIDGE. The Company 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. The Company acquired
interests in the South Belridge field in 1987 and expanded its holdings in 1991.
The South Belridge field is the third highest producing oil field in the lower
48 states. The field produces both heavy and light crude from Tulare, Etchegoin
and Diatomite formations equivalent to those

                                       5
<PAGE>
found in the Midway-Sunset field, generally at depths of less than 2,000 feet.
During 1996, the South Belridge field accounted for approximately 5% of the
Company's total crude production. As of December 31, 1996, the Company's total
proved reserves in the South Belridge field were approximately 13.8 MMBOE, or
approximately 6% of its total proved reserves.

     The Company has identified 106 additional drilling and remediation projects
(including one horizontal well) in the South Belridge field and anticipates
completing 48 of the projects by the end of 1997 at an estimated cost of
approximately $6.0 million.

     COALINGA. The Company 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 the Company's crude production. As of December 31, 1996,
the Company's total proved reserves in the Coalinga field were approximately 5.6
MMBOE, or approximately 3% of its total proved reserves.

     The Company acquired its interest in the Coalinga field in 1977. The
Company has identified 167 additional drilling and remediation projects
(including two horizontal wells) in the Coalinga field and anticipates
completing 32 of the projects by the end of 1997 at an estimated cost of
approximately $4.0 million.

     LA BASIN. The Company has an average 30% working interest (24% average net
revenue interest) in four producing properties in Los Angeles and Orange
Counties and the Federal Outer Continental Shelf in southern California (the "LA
Basin"). During 1996, the Company's LA Basin properties accounted for
approximately 5% of the Company's total crude production. As of December 31,
1996, the Company's total proved reserves in the LA Basin were approximately
14.7 MMBOE, or approximately 7% of its total proved reserves.

DEVELOPMENT, EXPLORATION AND ACQUISITION ACTIVITIES

     The following table shows the Company's total oil and gas development,
exploration and acquisition expenditures (including capitalized interest and
allocated exploratory support costs), whether capitalized or charged to expense,
since the beginning of 1992 through December 31, 1996.

<TABLE>
<CAPTION>
                                                         YEAR ENDED DECEMBER 31,
                                          -----------------------------------------------------
                                            1996       1995       1994       1993       1992
                                          ---------  ---------  ---------  ---------  ---------
                                                              (IN MILLIONS)
<S>                                       <C>        <C>        <C>        <C>        <C>      
Development costs(1)....................  $    47.1  $    47.7  $    22.7  $    38.4  $    17.0
Exploration costs.......................        1.6        2.6        1.4        1.7        2.8
Acquisition costs:
  Unproved leasehold....................        0.1        0.1         --         --         --
  Proved properties.....................        3.4        1.3         --        3.6        0.1
                                          ---------  ---------  ---------  ---------  ---------
          Total costs...................  $    52.2  $    51.7  $    24.1  $    43.7  $    19.9
                                          =========  =========  =========  =========  =========
</TABLE>

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

(1) Development expenditures include costs of EOR projects, infill drilling and
    primary development drilling of offset wells.

     The Company continually evaluates acquisitions of producing and
non-producing oil and gas properties that would add to its reserve base and
present additional development opportunities at attractive prices. From 1994
through 1996, the Company spent approximately $4.7 million to purchase an
estimated 7.9 MMBOE of proved oil and gas reserves in California. Although the
Company may pursue opportunities in other areas, the Company plans to focus
primarily on areas contiguous with, or in close proximity to, its existing
operations. Future acquisitions will depend upon, among other things, the
availability of opportunities to purchase reserves that would complement the
Company's existing properties and that would meet or exceed the Company's
economic criteria with respect to, among other things, cost of reserve
additions, the availability of funding on acceptable terms and other projects to
which the Company may be committed that

                                       6
<PAGE>
would compete with the personal or capital resources required to be dedicated to
a particular acquisition opportunity.

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,
no wells were in progress.

<TABLE>
<CAPTION>
                                                         YEAR ENDED DECEMBER 31,
                                           --------------------------------------------------
                                                1996              1995              1994
                                           --------------    --------------    --------------
                                           GROSS     NET     GROSS     NET     GROSS     NET
                                           -----    -----    -----    -----    -----    -----
<S>                                         <C>     <C>       <C>     <C>        <C>     <C> 
Development wells:
     Completed..........................    224     215.2     224     209.2      78      70.2
     Dry holes..........................      3       3.0      --        --       1       1.0
                                           -----    -----    -----    -----    -----    -----
          Total.........................    227     218.2     224     209.2      79      71.2
Exploration wells:
     Dry holes..........................      1       0.4       3       3.0      --        --
                                           -----    -----    -----    -----    -----    -----
Total...................................    228     218.6     227     212.2      79      71.2
                                           =====    =====    =====    =====    =====    =====
</TABLE>
PRODUCING WELLS

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

                                           TOTAL PRODUCING
                                                WELLS
                                           ----------------
                                           GROSS      NET
                                           -----    -------
Oil.....................................   5,639    5,102.7
Natural gas.............................       2        0.2
                                           -----    -------
          Total.........................   5,641    5,102.9
                                           =====    =======

ACREAGE

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

<TABLE>
<CAPTION>
                                              DEVELOPED         UNDEVELOPED           TOTAL
                                           ----------------    --------------    ----------------
                 FIELD                     GROSS      NET      GROSS     NET     GROSS      NET
----------------------------------------   ------    ------    -----    -----    ------    ------
<S>                                        <C>       <C>         <C>      <C>    <C>       <C>   
Midway-Sunset...........................   12,795    12,787      320      320    13,115    13,107
Kern River..............................      755       755       --       --       755       755
South Belridge..........................      919       710       --       --       919       710
Coalinga................................    1,474     1,474       --       --     1,474     1,474
LA Basin................................    1,244     1,241      229      229     1,473     1,470
Other...................................   19,809     4,603    6,053    6,053    25,862    10,656
                                           ------    ------    -----    -----    ------    ------
          Total.........................   36,996    21,570    6,602    6,602    43,598    28,172
                                           ======    ======    =====    =====    ======    ======
</TABLE>

CURRENT MARKETS FOR OIL AND GAS

     The Company's profitability is determined in large part by the difference
between the prices received for the oil and natural gas that it produces and the
costs of finding, developing and producing such reserves. Prices for oil and
natural gas have been subject to wide fluctuations, which continue to reflect
imbalances in supply and demand as well as other market conditions and the world
political situation as it affects OPEC,

                                       7
<PAGE>
the Middle East, the former Soviet Union and other producing countries.
Moreover, the price of oil and natural gas may be affected by the price and
availability of alternative sources of energy, weather conditions and the
general state of the economy. Even relatively modest changes in oil and natural
gas prices may significantly change the Company's revenues, results of
operations, cash flows and proved reserves. Based on operating results for 1996,
the Company estimates that on an annualized basis a $1.00 per barrel increase
(or decrease) in its average crude oil sales price would result in a $17.1
million increase (or decrease) in income from operations, a $10.1 million
increase (or decrease) in net income and a $12.2 million increase (or decrease)
in cash flow from operating activities. Because the Company is a relatively
small producer of natural gas, it consumes more gas in its EOR operations than
it produces. As a result, an increase in natural gas prices adversely affects
the Company's results of operations. Based on operating results for 1996, the
Company estimates that on an annualized basis a $0.10 per Mcf increase (or
decrease) in the average domestic natural gas sales price would result in a $1.6
million decrease (or increase) in income from operations, a $1.0 million
decrease (or increase) in net income and a $1.2 million decrease (or increase)
in cash flow from operating activities. The foregoing estimates do not give
effect to changes in any other factors, such as the effect of depreciation and
depletion that would result from a change in oil and natural gas prices.

     The market for heavy crude oil produced in California differs substantially
from the remainder of the domestic crude oil market, due principally to the
transportation and refining requirements associated with heavy crude. Although
the prices realized for heavy crude oil are generally lower than those realized
from the sale of light crude oil, several economic trends have favorably
affected the market for the Company's production in recent years. See "--
Strategy". In addition to the current favorable economic trends in California
heavy crude prices, the Company has facilities in place that it believes will
allow it to adapt to changes in pricing trends to a greater extent than many of
its competitors. For example, the Company owns and operates a large gathering,
blending and transportation system on its properties in the San Joaquin Valley.
At this terminal up to 30 MBbls of heavy oil per day can be mixed or blended
with lighter grades, a capability which enables the Company to upgrade the
majority of its heavy oil into a lighter crude which can be sold at a higher
price. The terminal also directly connects the Company's production with five
major pipelines serving refineries throughout California and gives the Company
the ability to meet the product specifications of multiple pipelines and inter-
and intra-state markets.

     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 "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- General" for a discussion of the Company's hedging
activities.

CUSTOMERS

     During 1996, affiliates of Shell Oil Company ("Shell") and Celeron
Corporation ("Celeron") accounted for approximately 35% and 22%, respectively,
of the Company's crude oil and liquids sales (which with respect to certain
properties includes royalty and working interest owners' share of production).
The Company has sales contracts with several customers, including Shell and
Celeron, which generally provide for sales of the Company's crude oil and
liquids at market responsive prices and are cancellable by either party thereto
upon short notice (generally 60 days or less). Because the Company's markets are
characterized by a number of potential customers who are willing to purchase the
Company's crude oil and liquids at market responsive prices, the Company does
not believe that the loss or cancellation of its contracts with Shell or Celeron
would have a material adverse effect on its financial condition or results of
operations. No other individual customer accounted for more than 10% of the
Company's crude oil and liquids revenues during 1996. Substantially all of the
Company's oil production is currently sold at market prices that approximate
posted field prices. Availability of a ready market for the Company's oil
production depends on numerous factors, including the level of consumer demand,
the level 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.

                                       8
<PAGE>
RELATIONSHIP BETWEEN THE COMPANY AND SFR

     OWNERSHIP OF COMMON STOCK. As of December 31, 1996, SFR owned 82.8% of the
Company's outstanding shares of common stock. Through its ability to elect all
directors of the Company, SFR has the ability to control all matters affecting
the Company, including any determination with respect to acquisition or
disposition of Company assets, future issuance of common stock or other
securities of the Company, any dividends payable on its common stock, and the
Company's exploration, development, capital, operating and acquisition budgets.

     Pursuant to Rule 144 promulgated under the Securities Act, SFR may not,
prior to the expiration in August 1998 of the two year holding period required
by Rule 144, sell any of the shares of the Company's common stock it owns
without registration under the Securities Act. The SEC has approved revisions to
Rule 144 which, when effective, will shorten the holding period to one year. The
Company has agreed that upon the request of SFR, the Company will register under
the Securities Act and applicable state securities laws the sale of the shares
of common stock owned by SFR which SFR requests to be registered.

     INTENDED SPIN OFF. SFR has announced that it intends to distribute pro rata
to its common stockholders all of the shares of the Company's common stock that
it owns by means of a tax-free distribution. SFR's final determination to
proceed will require a declaration of the Spin Off by SFR's board of directors.
Such a declaration is not expected to be made until certain conditions, many of
which are beyond the control of SFR, are satisfied, including: (i) receipt by
SFR of a ruling from the Internal Revenue Service as to the tax-free nature of
the Spin Off; (ii) approval of the Spin Off by SFR's stockholders; (iii) the
redemption or conversion of all or a substantial portion of the shares of each
outstanding series of SFR preferred stock; and (iv) the absence of any future
change in market or economic conditions (including developments in the capital
markets) or SFR's or the Company's business and financial condition that causes
SFR's board to conclude that the Spin Off is not in the best interests of SFR's
stockholders. The Company has been advised by SFR that it does not expect the
Spin Off to occur prior to August 1997. If SFR consummates the Spin Off, the
increased shares available in the market may have an adverse effect on the
market price of the Common Stock. The Company has been advised by SFR that as of
December 31, 1996, SFR had approximately 38,500 common stockholders of record.

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

     SPIN OFF TAX INDEMNITY AGREEMENT. To protect SFR from Federal and state
income taxes, penalties, interest and additions to tax that would be incurred by
it if the Spin Off by SFR were determined to be a taxable event, the Company and
SFR have entered into an agreement under which the Company has agreed to
indemnify SFR with respect to tax liabilities resulting primarily from actions
taken by the Company at any time during the Restricted Period. The Company has
also agreed that, unless it obtains an opinion of counsel or a supplemental
ruling from the Internal Revenue Service that such action will not adversely
affect the qualification of the Spin Off as tax-free, the Company will not merge
or consolidate with another corporation, liquidate or partially liquidate, sell
or transfer all or substantially all of its assets or redeem or otherwise
repurchase any of its stock or issue additional shares of the Company's capital
stock during such Restricted Period. The Company's obligations under this
agreement could possibly deter offers or other efforts by third parties to
obtain control of the Company during such Restricted Period, which could deprive
the Company's stockholders of opportunities to sell their shares of Common Stock
at prices higher than prevailing market prices.

     The Company has retained the right to contest, at its expense, any
determination by taxing authorities that the Spin Off has failed to qualify as
tax-free by reason of an action by the Company; provided, however, that if SFR
reasonably perceives, either at the commencement or during the course of any
proceeding challenging the tax-free nature of the Spin Off, that the Company
could not pay the indemnified amounts if the taxing authorities were successful
and the Company fails to furnish a guarantee or performance bond satisfactory to
SFR in an amount equal to the indemnified liability being asserted by the

                                       9
<PAGE>
taxing authority, SFR may assume the defense of any such challenge, at the
Company's expense, and may compromise, concede, or settle the taxing
authorities' claim. SFR's assumption of the conduct of such defense would not
relieve the Company of its financial responsibility to SFR under this agreement.
The indemnity agreement will apply if the Spin Off occurs prior to December 31,
1997.

     The Company believes that if the Company is required to make payments
pursuant to such agreement, the amount that the Company would pay to SFR would
have a material adverse effect on the Company's financial condition. The actions
for which the Company is required to indemnify SFR pursuant to this agreement
are within the Company's control, and the Company has no intention of taking any
actions during the Restricted Period that would have such an effect.

     The Spin Off Tax Indemnity Agreement also contains provisions covering
certain other tax matters between SFR and the Company. Under the tax sharing
agreements and arrangements between SFR and Santa Fe Pacific Corporation
("SFP"), the former parent company of SFR, SFR and its subsidiaries receive
benefits from and are responsible for liabilities directly attributable to audit
adjustments for California franchise taxes with respect to all California
properties or operations owned or conducted by SFR and its subsidiaries prior to
the spin off of SFR by SFP. The Company now owns substantially all of the
California properties and operations that would relate to such audit matters.
Accordingly, the Company will receive the benefits and be responsible for the
obligations attributable to California franchise tax liabilities under SFR's
agreements with SFP for any of the tax years ending on or after December 31,
1984 (the years for which the audits have not been conducted by California). SFR
prepares and files all consolidated Federal, combined state and local income and
franchise tax returns required to be filed while the Company is a member of
SFR's affiliated group and the Company will not be compensated for the carryback
after Spin Off to SFR's affiliated group of any Company tax items realized after
the Company ceases to be a member of SFR's affiliated group. The Company will
not be compensated for such carryback both because it is anticipated that the
Company will make the necessary election to forego any such carryback and
because management of both SFR and the Company desire to minimize, to the extent
possible, continuing relationships and obligations between the two companies.

     SERVICES AGREEMENT. SFR provides various administrative and financial
services to the Company, including administration of certain employee benefit
plans, access to telecommunications, corporate legal assistance and certain
other corporate staff and support services. The Company and SFR have entered
into a Services Agreement to formalize this existing arrangement. The agreement
is intended to be flexible (for example, on short notice the Company may take
responsibility for some or all of the services currently being provided by SFR)
and may be easily terminated by either party on 30 days' notice. As a result, no
assurance is given that this service arrangement will be maintained for any
specific period in the future. Whether SFR continues to provide some or all of
these services will depend on many factors, including the continuing agreement
of the parties on the appropriate amounts of compensation and reimbursement, the
ability of the Company to provide the services for itself and the continued
willingness of SFR to provide the services. The agreement provides that the
Company will pay SFR a monthly fee for certain listed services at specified
rates. The total monthly fee for all listed services is $120,000. Because the
Services Agreement was not the result of arm's-length negotiations, the costs
charged thereunder may exceed costs otherwise available from an unaffiliated
third party. Payments to SFR thereunder are expected to decline as the Company
assumes full responsibility during 1997 for each of the services covered by such
agreement.

     TAX ALLOCATION AGREEMENT. The Company will continue to be included in the
consolidated Federal income tax return filed by SFR as the common parent for
itself and its subsidiaries. Consistent therewith and pursuant to the Tax
Allocation Agreement, the Company has agreed to pay to SFR an amount
approximating the Federal tax liability and state and local tax liability it
would have paid if it and its subsidiaries were a separate consolidated group.
This amount will be payable regardless of whether the SFR consolidated group, as
a whole, has any current Federal, state or local tax liability. In determining
amounts payable to SFR in accordance with the foregoing formula, the Company and
its subsidiaries may take into account only their losses and credits (including
carryforwards) to reduce amounts they would owe if they were a separate
consolidated group. Such amounts must first be used by the SFR consolidated
group. Any

                                       10
<PAGE>
of the Company's carryforwards not used by the SFR consolidated group will be
available for use by the Company if it leaves the SFR consolidated group. If the
Company or its subsidiaries cease to be members of the SFR consolidated group,
the Tax Allocation Agreement will continue to apply to prior periods, and
additional payments to or receipts from SFR could be required if there is an
audit or similar adjustment subsequently made that impacts the computation of
amounts to be paid or received from SFR as described above. In addition, if the
Company and its subsidiaries cease to be members of the SFR consolidated group,
they will not be entitled to any compensation or reimbursement with respect to
any tax refund, benefit or other similar item realized by the SFR group after
the Company leaves the SFR group or with respect to any carryforwards not used
by the Company prior to the Company leaving the SFR group.

     REGISTRATION RIGHTS AND INDEMNIFICATION AGREEMENT. The Company has entered
into a Registration Rights and Indemnification Agreement with SFR pursuant to
which SFR has the right to require the Company to effect three registrations
under the Securities Act of all or any part of the Common Stock owned by SFR and
to bear the expenses of such registration. In addition, the Registration Rights
and Indemnification Agreement gives SFR the right to include its shares of
Common Stock in any registration of shares of Common Stock initiated by the
Company. The Registration Rights and Indemnification Agreement also contains
provisions whereby the Company and SFR agree to indemnify each other and their
respective subsidiaries as well as their respective directors, officers,
employees, agents and representatives for certain costs and liabilities relating
to violations of Federal and state securities laws in connection with any such
registration of shares of common stock owned by SFR.

     CONFLICTS OF INTEREST; TRANSACTIONS WITH AFFILIATES. The nature of the
respective businesses of the Company and SFR is such as to give rise to
conflicts of interest between the two companies. Conflicts could arise, for
example, with respect to allocation of capital, dividends, incurrence of
indebtedness, tax matters, financial commitments, registration rights,
administration of benefit plans, service arrangements, potential acquisitions of
businesses or oil and gas properties and other corporate opportunities, the
issuance and sale of capital stock of the Company and the election of directors.

     SFR has advised the Company that it does not currently intend to engage in
the exploration, development and production of oil and gas in California except
through its ownership of common stock of the Company, nor does it currently
intend to compete with the Company in the acquisition of California oil and gas
properties. Circumstances may arise in the future, however, that would cause SFR
to engage in the exploration, development and production of oil and gas in
competition with the Company. Although SFR has no current intention to do so,
there can be no assurances that it will not engage in the oil and gas
exploration, development and production business in competition with the
Company.

     The Company and SFR and its affiliates have in the past entered into
intercompany transactions and agreements incident to their respective
businesses, and the Company and SFR may be expected to enter into transactions
and agreements from time to time in the future. The Company intends that the
terms of any future transactions and agreements between the Company and SFR will
be on terms at least as favorable to the Company as it could obtain from third
parties.

OTHER BUSINESS MATTERS

  COMPETITION

     The Company faces competition in all aspects of its business, including,
but not limited to, acquiring reserves, leases and licenses; 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, other independent producers, oil and gas syndication programs
and individual producers and operators. Many competitors have greater financial
and other resources than the Company and ready access to more favorable markets
for their production. The Company believes that the well-defined nature of the
reservoirs in its long-lived oil fields, its expertise in EOR methods, its
extensive fee and leasehold acreage position, its regional focus, its active
development position and its experienced management may give it a competitive
advantage over some other producers, and management believes that the Company
effectively competes in its markets. Availability of a ready market for the
Company's oil and gas production depends on numerous factors, including the
level of consumer demand, the extent of worldwide oil

                                       11
<PAGE>
production, the cost and availability of alternative fuels, 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.

  REGULATION OF CRUDE OIL AND NATURAL GAS PRODUCTION

     The petroleum industry is subject to various types of regulation, including
regulation by state and Federal agencies. State and Federal 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. California
statutes and regulations require permits for drilling operations, drilling bonds
and reports concerning operations. The Company does not appear to be affected by
these burdens to any greater or lesser extent than other companies in the
industry with similar types and amounts of production. Set forth below is a
general description of certain Federal and state regulations which have an
effect on the Company's operations.

     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).

     Federal legislation and regulatory controls in the United States have
historically affected the price of the natural gas produced and consumed by the
Company. Proposals and proceedings that might affect the natural gas industry
are considered from time to time by Congress, the FERC, state regulatory bodies
and the courts. The Company cannot predict when or if any such proposals might
become effective, or their effect, if any, on the Company's financial condition
or results of operations.

     Sales of crude oil, condensate and gas liquids by the Company are not
regulated and are made at market prices. The price the Company receives from the
sale of these products is, however, affected by the cost of transporting the
products to market. The Company transports its products on both interstate and
intrastate pipelines. Transportation rates on these pipelines are regulated by
the FERC and the California Public Utility Commission, respectively. The Company
is not able to predict what effect, if any, these rules and regulations of these
two agencies will have on its business.

  ENVIRONMENTAL REGULATION

     GENERAL. The Company's operations are subject to Federal, state and local
laws and regulations governing the discharge of materials into the environment
or otherwise relating to environmental protection. Environmental laws and
regulations carry substantial penalties for failure to comply. These laws and
regulations may require the acquisition of a permit before drilling commences,
restrict the types, quantities and concentration of various substances that can
be released into the environment in connection with drilling and production
activities, limit or prohibit drilling activities on certain lands lying within
wilderness, wetlands and other protected areas, and impose substantial
liabilities for pollution resulting from the Company's operations. State laws
often require some form of remedial action to prevent pollution from former
operations, such as pit closure and plugging abandoned wells.

     These laws and regulations increase the Company's cost of doing business
and consequently affect its profitability. The Company anticipates that it will
expend significant resources, both financial and managerial, to comply with
environmental regulations and permitting requirements in order to comply with
stricter industry and regulatory environmental and health and safety standards
such as those described below. The Company estimates that capital expenditures
necessary for foreseeable environmental control facilities are within normal
provisions for maintenance capital expenditures. Although the Company believes
that its operations and facilities are in compliance in all material respects
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 cost and liabilities will not be incurred in the future.

                                       12
<PAGE>
     Other developments, such as increasingly strict environmental laws and
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. Currently, the Company does not believe that such costs will have a
material adverse effect on its financial condition or results of operations.

     SOLID AND HAZARDOUS WASTE. The Company currently owns or leases 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 wastes may have been
disposed or released on or under these properties. The Company could be required
to remove or remediate previously disposed wastes and any related contamination
or to perform remedial plugging operations to prevent future contamination.

     SUPERFUND. The Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA"), also known as the "Superfund" law, imposes joint and
several 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
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.

     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 OII Site in several phases,
which include site monitoring and leachate control, gas control and final
remediation. In 1989 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 Company's 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 that its share of the
final costs of the closure will be approximately $0.8 million, which amount has
been provided for by the Company. The Company has entered into a Joint Defense
Agreement with the other PRPs to defend against a lawsuit filed September 7,
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 against the Company and the other PRPs alleging
similar damages and wrongful death. The Company has entered into a Joint Defense
Agreement with the other PRPs and 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 seven
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.

                                       13
<PAGE>
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 that the total past and
future costs for remediation will approximate $8 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 the total cost to complete the final
remediation to be $3 million and the Company has provided $250,000 for such
costs in its financial statements.

     In 1995 the Company and 12 other companies received notice that they have
been identified as PRPs by the California Department of Toxic Substances Control
(the "DTSC") as having generated and/or transported hazardous waste to the
Environmental Protection Corporation ("EPC") Eastside Landfill during its
fourteen-year operation from 1971 to 1985 (the "Eastside Site"). 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 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 for the Eastside Site 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.

     Pursuant to the Contribution Agreement, the Company agreed to indemnify and
hold harmless SFR from and against any costs incurred in the future relating to
environmental liabilities of the Western Division assets (other than the assets
retained by SFR), 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 of any property or interest therein located in California
and formerly owned or operated by the Western Division or its predecessors. SFR
agreed to indemnify the Company from and against any costs relating to
environmental liabilities of any assets or operations of SFR (whether or not
currently owned or operated by SFR) to the extent not attributable to the
Western Division (other than the assets retained by SFR).

     AIR EMISSIONS. The operations of the Company are subject to Federal, state
and local regulations for the control of emissions from sources of air
pollution. The Company's properties have been and may in the future be the
subject of administrative enforcement actions for failure to comply 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, although the Company
believes that in the latter cases it would have enough permitted or permitable
capacity to continue its operations without a material adverse effect on any
particular producing field.

     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 require the Company to organize information about
hazardous materials used or produced in its operations. Certain of this
information must be provided to employees, Federal, 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

                                       14
<PAGE>
intentionally exposing any individual to such chemicals through ingestion,
inhalation or other exposure pathways without first giving a clear and
reasonable warning.

  EMPLOYEES

     At March 1, 1997 the Company had 326 employees, 176 of whom are covered by
a collective bargaining agreement, the current term of which expires on January
31, 1999. The Company believes that its relations with its employees are
satisfactory. The Company's hourly employees are represented by the Oil,
Chemical and Atomic Workers Union.

ITEM 3.  LEGAL PROCEEDINGS

     The Company and other related companies are defendants in several lawsuits
and named parties in certain governmental proceedings arising in the ordinary
course of business. In addition, in 1996 the MMS announced that it would seek to
recover additional royalties for past production from producers on certain
Federal leases. Because the Company's operations include Federal lease sites in
California, the Company may be required to pay such "back royalties" but does
not believe that any amounts so paid would have a material impact on its
financial condition or results of operations. For a description of certain
proceedings in which the Company is involved, see Items 1 and 2 "Business and
Properties. -- Other Business Matters -- Environmental Regulation". While the
outcome of lawsuits or other proceedings against the Company cannot be predicted
with certainty, management does not expect these matters to have a material
adverse effect on the business, financial condition, liquidity or results of
operations of the Company.

                                       15
<PAGE>
ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     None.

EXECUTIVE OFFICERS OF MONTEREY

     R. Graham Whaling, 42. Chairman and Chief Executive Officer since November
1996. Mr. Whaling was Senior Vice President and Chief Financial Officer of SFR
from January 1995 until November 1996. Prior to that time he was with CS First
Boston Corporation, an investment banking firm, as Vice President, Corporate
Finance from 1991 to 1994 and Director, Corporate Finance from 1994 to 1995.
Prior to joining First Boston, Mr. Whaling served as a petroleum engineer for
Sun Oil Company and petroleum reservoir consulting engineer for Ryder Scott.

     David B. Kilpatrick, 46. President and Chief Operating Officer since
November 1996. Mr. Kilpatrick was Division Manager -- Production for SFR's
Western Division from January 1990 until November 1996.

     Gerald R. Carman, 32. Vice President, Chief Financial Officer and
Treasurer. Mr. Carman was Treasurer of SFR from January 1995 until December
1996. Prior to 1995, Mr. Carman was Director of Corporate Planning and Manager
of Tax Planning for SFR.

     C. Ed Hall, 54. Vice President -- Public Affairs since November 1996. Mr.
Hall was Vice President -- Public Affairs of SFR from March 1991 until November
1996.

     Jeffrey B. Williams, 51. Vice President -- Development since November 1996.
Mr. Williams was Corporate Production Manager of SFR from July 1996 until
November 1996. Prior to that time, Mr. Williams was employed by SFR as Regional,
Corporate or Division Production Manager, a position he assumed in 1983.

     Lou E. Shuflin, 42. Director -- Administration since November 1996. Mr.
Shuflin was Manager -- Strategic Analysis of SFR from September 1994 until
November 1996. Mr. Shuflin also served as SFR's Corporate Manager -- Production
from May 1993 to August 1993 and District Manager -- Production beginning in
1987.

     Terry L. Anderson, 49. General Counsel and Secretary since November 1996.
Mr. Anderson was Manager -- Business Development of SFR from December 1994 until
November 1996. Prior to that time and beginning in 1988, Mr. Anderson was Senior
Counsel of SFR.

                                    PART II

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

     Monterey's common stock is listed on the New York Stock Exchange and trades
under the symbol MRC. The following table sets forth information as to the last
sales price per share of Monterey's common stock as quoted on the Consolidated
Tape System.

                                        LOW    HIGH
                                        ---    ----
1996
     4th Quarter (since November
      14)............................   15 5/8 16 3/4

                                       16
<PAGE>
     The Company currently intends to pay to its stockholders a quarterly
dividend of $0.15 per share of Common Stock ($0.60 annually). The first dividend
has been declared, and will be paid in April 1997, consisting of a prorated
dividend of $0.22 in respect of the Company's first partial quarter ended
December 31, 1996 and for its first full quarter of operations ending March 31,
1997. Although the Company currently intends to pay quarterly dividends, the
determination of the amount of future cash dividends, if any, to be declared and
paid will depend upon declaration by the Company's board of directors and upon
the Company's financial condition, earnings and funds from operations, the level
of its capital and exploration expenditures, dividend restrictions contained in
the Credit Facility and the Senior Notes, future business prospects and such
other matters as the Company's directors deem relevant. For a description of
certain restrictions on the Company's ability to pay dividends, see Item 7
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources".

     At December 31, 1996 the Company had approximately 25 shareholders of
record.

                                       17
<PAGE>
ITEM 6.  SELECTED FINANCIAL DATA

<TABLE>
<CAPTION>
                                                       YEAR ENDED DECEMBER 31, (1)
                                          -----------------------------------------------------
                                            1996       1995       1994       1993       1992
                                          ---------  ---------  ---------  ---------  ---------
                                                (IN MILLIONS OF DOLLARS, EXCEPT AS NOTED)
<S>                                           <C>        <C>        <C>        <C>        <C>  
SELECTED 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
          Interest income...............        0.1     --         --            0.2        0.2
          Interest expense..............      (25.0)     (25.8)     (26.4)     (27.2)     (27.6)
          Interest capitalized..........        1.1        0.7        0.6        0.3        0.1
          Other income (expense)........     --           (0.6)      (0.1)      (0.4)       0.4
                                          ---------  ---------  ---------  ---------  ---------
     Income (Loss) Before Income Taxes
       and Extraordinary Items..........       83.1       50.4       16.2      (62.0)      18.6
          Income taxes benefit
             (expense)..................      (28.3)     (16.0)      (4.7)      26.9       (6.1)
                                          ---------  ---------  ---------  ---------  ---------
     Income (Loss) Before Extraordinary
       Items............................       54.8       34.4       11.5      (35.1)      12.5
          Extraordinary items...........       (4.5)    --         --         --         --
                                          ---------  ---------  ---------  ---------  ---------
     Net Income (Loss)..................       50.3       34.4       11.5      (35.1)      12.5
                                          =========  =========  =========  =========  =========
     Pro Forma per share data (in
       dollars, except share data) (2)
          Income (loss) before
             extraordinary items........       1.00       0.63       0.21      (0.64)      0.22
          Net income (loss).............       0.92       0.63       0.21      (0.64)      0.22
          Number of shares used in
             computing per share amounts
             (in millions)..............       54.8       54.8       54.8       54.8       54.8
  STATEMENT OF CASH FLOWS DATA
     Net cash provided by operating
       activities.......................       86.3       75.7       45.5       47.5       59.0
     Net cash used in investing
       activities.......................       54.6       54.2       18.2       18.2       17.4
     Net cash used in financing
       activities.......................       22.4       21.5       27.3       29.3       41.6
  BALANCE SHEET DATA (AT PERIOD END)
     Properties and equipment, net......      379.0      367.3      349.5      356.3      445.5
     Total assets.......................      447.2      391.3      376.1      387.3      476.2
     Long-term debt.....................      175.0      245.0      245.0      257.6      263.0
     Shareholders' Equity and Division
       Equity...........................      176.7       45.0       32.1       35.3       93.5
</TABLE>

                                             (TABLE CONTINUED ON FOLLOWING PAGE)

                                       18
<PAGE>

<TABLE>
<CAPTION>
                                                       YEAR ENDED DECEMBER 31, (1)
                                          -----------------------------------------------------
                                            1996       1995       1994       1993       1992
                                          ---------  ---------  ---------  ---------  ---------
                                                (IN MILLIONS OF DOLLARS, EXCEPT AS NOTED)
<S>                                           <C>        <C>        <C>        <C>        <C>  
SELECTED OPERATING DATA
  AVERAGE DAILY 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)............      218.4      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
     After income taxes.................      680.7      426.4      366.1      143.0      275.4
  PRODUCTION COSTS PER BOE (including
     related production, severance and
     ad valorem taxes) (in dollars).....       6.64       5.98       6.19       6.85       7.23
</TABLE>

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

(1) 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 the Company for November and December.

(2) Common shares outstanding at November 19, 1996, the closing date of the
    Company's IPO, have been included in the pro forma net income per share
    calculation as if such shares were outstanding for all periods prior to
    November 19, 1996.

                                       19
<PAGE>
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

GENERAL

     The discussion presented herein relates to the operations of the Western
Division for the years ended December 31, 1995 and prior. The discussion with
respect to 1996 relates to the operations of the Western Division for January
through October and the Company for November and December.

     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. The Company produces most
of its oil and gas from long-lived fields in the San Joaquin Valley of
California utilizing various EOR methods. The market price of heavy (i.e., low
gravity, high viscosity) and sour (i.e., high sulfur content) crude oils
produced in these fields is lower than sweeter, light (i.e., low sulfur and low
viscosity) crude oils, reflecting higher transportation and refining costs. In
addition, the lifting costs of heavy crude oils are generally higher than the
lifting costs of light crude oils. As a result, even relatively modest changes
in crude oil prices may significantly affect the Company's revenues, results of
operations, cash flows and proved reserves. In addition, prolonged periods of
high or low oil prices may have a material effect on the Company's financial
condition and results of operations.

     The average realized sales price of the Company's crude oil and liquids for
1996 was $15.82 per barrel, or approximately 77% of the average posted price of
$20.44 per barrel for West Texas Intermediate ("WTI") crude oil (an industry
posted price generally indicative of prices for sweeter light crude oil).

     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 relates to OPEC, the
Middle East and various producing countries. Since the beginning of 1994, the
average sales price (unhedged) received by the Company ranged from a low of
$8.80 per barrel for the first quarter of 1994 to a high of $17.29 per barrel in
the fourth quarter of 1996. Based on operating results for 1996, the Company
estimates that a $1.00 per barrel increase or decrease in its average crude oil
sales price would result in a corresponding $17.1 million change in income from
operations and a $12.2 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 hedging or depreciation and depletion, that would result from a
change in oil prices.

     The price of natural gas fluctuates due to supply and demand, which may be
affected by weather conditions, the level of natural gas in storage and other
economic factors. Increases in the price of natural gas adversely impact the
Company's results of operations because the natural gas consumed in the
Company's EOR operations exceeds the amount of natural gas produced by the
Company. Based on operating results for 1996, the Company estimates that a $0.10
per Mcf increase (or decrease) in the average domestic natural gas sales price
would result in a $1.6 million decrease (or increase) in income from operations
and a $1.2 million decrease (or increase) in cash flow from operating
activities. The foregoing estimates do not give effect to changes in any other
factors, such as depletion and depreciation, that would result from a change in
natural gas prices.

     In February 1996 the Bureau of Land Management ("BLM") of the United
States Department of the Interior (which oversees 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 crude oil with a weighted average API
gravity of less than 20 degrees. The reduced royalty rates are based upon the
weighted average API gravity of the heavy oil produced from the subject Federal
leases and are as low as 3.9%, compared to 12.5% before the reduction. The
reduced royalty rates continue in effect for 12-month periods, after which the
operator can establish a new reduced rate for continued heavy oil production by
submitting an application. As a result of this program, the Company's royalty
rate on its Federal leases 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 1.6 MBbls per day. During the
period that such royalty reduction is in effect, the Company (and other working
interests owners, if any) will bear all of the thermal EOR costs to produce the
heavy oil from such properties. The royalty reduction will be terminated upon
the first to occur

                                       20
<PAGE>
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).

     The Company's 1996 and 1995 financial statements include the impact of oil
and gas hedging losses which were allocated by SFR. SFR from time to time enters
into such transactions in order to reduce exposure to fluctuations in market
prices of oil and natural gas. Oil hedging losses were allocated to the Company
based upon relative hedged volumes and were recognized as a reduction of oil
revenues in the period in which the hedged production was sold. Such amounts
totaled $3.1 million and $0.1 million in 1996 and 1995, respectively. Currently
the Company has no oil hedges in place and, going forward, the Company does not
expect to hedge a substantial portion of its oil production.

     Additionally, during the first six months of 1996, SFR hedged 20 MMcf per
day of the natural gas purchased for use in the Company's steam generation
operations. Such hedges, which terminated at the end of the second quarter,
resulted in a $3.2 million increase in the Company's production and operating
costs. While the Company currently has no natural gas hedges in place, the
Company's management may determine that such arrangements are appropriate in the
future in order to reduce the Company's exposure to increase in gas prices.

                                       21
<PAGE>
RESULTS OF OPERATIONS

     The following table reflects certain components of the Company's revenues
(expressed in millions of dollars) and expenses (expressed in dollars per BOE)
for the periods indicated:

                                                 YEAR ENDED
                                                DECEMBER 31,
                                       -------------------------------
                                         1996       1995       1994
                                       ---------  ---------  ---------
REVENUES:
Crude oil and liquids:
     Average realized sales prices
      ($/Bbl)
       Unhedged......................      16.00      13.79      11.77
       Hedged........................      15.82      13.79      11.77
     Sales volumes (MBbls/d).........       46.8       41.8       41.3
     Revenues ($ Millions)
       Sales.........................      274.0      210.2      177.5
       Hedging.......................       (3.1)    --         --
       Net profits payments..........       (1.0)      (0.8)      (0.4)
                                       ---------  ---------  ---------
          Total......................      269.9      209.4      177.1
                                       =========  =========  =========
Natural Gas:
     Average realized sales prices
      ($/Mcf)........................       1.03       0.98       1.14
     Sales volumes (MMcf/d)..........        3.5        5.3        3.8
     Revenues ($ Millions)...........        1.3        1.9        1.6
EXPENSES PER BOE:
Production and operating expenses:
     Steam generation................       2.69(1)    1.98       2.16
     Lease operating.................       3.53       3.56       3.55
          Total......................       6.22(1)    5.54       5.71
Exploration, including dry holes.....       0.10       0.15       0.09
Depletion, depreciation and
amortization.........................       2.16       2.08       2.09
General and administrative...........       0.44       0.47       0.51
Taxes (other than income)............       0.54       0.51       0.56
Interest, net........................       1.38       1.61       1.68

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

(1) Includes $0.18 per BOE loss on hedging, see "-- General". The hedging
    transactions which generated these losses expired on June 30, 1996.
    Excluding such hedging losses, historical steam generation costs would have
    been $2.51 per BOE and historical total production costs would have been
    $6.04 per BOE.

YEAR ENDED DECEMBER 31, 1996 COMPARED TO YEAR ENDED DECEMBER 31, 1995

     Revenues for 1996 of $293 million were 34% higher than the $219 million
reported for 1995. The variance primarily reflects greater sales volumes ($29
million) and higher sales prices ($31 million). An increase in the sales of
crude oil purchased ($14 million) accounted for most of the remaining difference
and represents purchases of higher gravity third-party crude blended with the
Company's heavy production to enhance the available transportation and marketing
opportunities. Such activity varies directly with market conditions.

     Costs and expenses totaled $186 million for the year and were 30% higher
than the $143 million reported for 1995. Production and operating costs were
higher due to greater production volumes and included fuel cost increases ($13
million) and allocated steam fuel hedging losses ($3 million). The cost of
third-party crude oil purchases increased due to greater marketing activity ($14
million) and general and administrative expenses include a non-recurring charge
of $1.3 million for employee relocation and other transition costs directly
related to the November 1996 IPO of the Company's common stock.

                                       22
<PAGE>
     Income taxes for the year were $28 million, up 75% over the $16 million
reported in 1995. In addition to a greater level of pre-tax income the Company's
effective tax rate was 34% in 1996 compared with 32% in 1995, reflecting
primarily the amount of EOR credits available to the Company relative to pre-tax
income.

     Extraordinary items in 1996 consisted of the after-tax costs of early
extinguishment of debt assumed in connection with the November 1996 IPO.

YEAR ENDED DECEMBER 31, 1995 COMPARED TO YEAR ENDED DECEMBER 31, 1994

     Revenues for 1995 of $219 million were 14% higher than the $192 million
reported in 1994. The increase primarily reflects the effects of increased sales
prices ($30 million) and increased sales volumes ($2 million), partially offset
by decreased sales of crude oil purchased ($5 million).

     Costs and expenses totaled $143 million in 1995, a decrease of 5% compared
to $150 million in 1994. Costs of crude oil purchased decreased $5 million due
to less marketing activity, and exploration costs for 1995 include $1 million
related to the drilling of two dry exploratory wells. Costs and expenses for
1994 included $1 million in restructuring costs related to SFR's 1993 corporate
restructuring program. Although other 1995 costs showed no significant change
from the 1994 levels, steam generation costs and general and administrative
costs declined $0.18 per BOE and $0.11 per BOE, respectively.

     Income taxes in 1995 were $16 million, an increase of 220% compared to $5
million in 1994 and primarily reflect higher pre-tax income. The Company's
effective tax rate in 1995 of 32% was up from 29% in 1994, primarily reflecting
the amount of EOR credits generated relative to the level of pre-tax income.

YEAR ENDED DECEMBER 31, 1994 COMPARED TO YEAR ENDED DECEMBER 31, 1993

     Revenues for 1994 of $192 million were 4% lower than the $200 million
reported in 1993. Revenues for 1993 included crude oil and liquids revenues of
$13 million (2.5 MBbls per day) and natural gas revenues of $2 million (2.3 MMcf
per day) attributable to certain producing properties which were sold to Vintage
Petroleum, Inc. ("Vintage") in the fourth quarter of 1993. Crude oil and
liquids revenues from other properties increased $6 million primarily reflecting
the effects of increased sales volumes.

     Costs and expenses totaled $150 million in 1994, a decrease of 36% compared
to $234 million in 1993. Costs and expenses in 1993 included impairments of oil
and gas properties of $49 million with regard to two properties in the LA Basin
and restructuring charges of $11.9 million. The restructuring charges were
incurred in the fourth quarter of 1993 as a result of the adoption by SFR of a
corporate restructuring program which included, among other things, (i) the
concentration of capital spending in SFR's core operating areas (one of which is
the San Joaquin Valley of California); (ii) the disposition of non-core assets;
and (iii) an evaluation of SFR's cost structures. As a result of the program,
certain of the Company's producing properties were sold to Vintage and the
Company's salaried work force was reduced. In implementing the corporate
restructuring program, the Company recorded restructuring charges of $11.9
million in 1993, comprised of losses on property dispositions of $11.3 million
and accruals for certain personnel benefits and related costs of $0.6 million.
Also, costs and expenses in 1993 included $9 million of production and operating
costs, $4 million in DD&A and $0.4 million of taxes (other than income) related
to certain producing properties sold to Vintage in the fourth quarter of 1993.
The remainder of the decrease in DD&A was primarily attributable to the effect
of the impairments taken in 1993. General and administrative expense was lower
in 1994, primarily reflecting the effect of the 1993 corporate restructuring
program.

     Income taxes in 1994 were $5 million, compared to a $27 million benefit in
1993 attributable to the net loss of $62 million incurred in that year. The
Company's effective tax rate in 1994 was 29%.

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

                                       23
<PAGE>
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 17% from December 31,
1991 to December 31, 1996; however, no assurances can be given that similar
increases will occur in the future. Historically, the Company has funded
development and exploration expenditures and working capital requirements
primarily from cash provided by operating activities; however, the future levels
of operating cash flows, which are significantly affected by oil and gas prices,
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 totaled $86.4 million in 1996; net cash used for capital
expenditures and producing property acquisitions in such period totaled $46.4
million. The Company intends to continue to meet its short-term (through 1997)
and long-term (the foreseeable future after 1997) liquidity needs with cash
provided by operating activities, supplemented from time to time with borrowings
under the Credit Facility and, if appropriate, debt and equity financing.

     The Company expects to increase its capital expenditures (including
acquisitions) from an average of $35.8 million per year over the five-year
period ended December 31, 1996 to approximately $70.2 million in 1997. However,
the actual amount expended by the Company in 1997 will be based upon numerous
factors, the majority of which are outside its control, including, without
limitation, prevailing oil and natural gas prices and the outlook therefor and
the availability of funds. The Company intends to fund such future capital
expenditures with cash provided by operating activities and borrowings under the
Credit Facility.

     In November 1996 the Company issued the Senior Notes which were exchanged
for $175.0 million of Series G Notes previously issued by SFR. The Senior Notes
bear interest at 10.61% per annum and mature $25 million per year in each of the
years 1999 through 2005.

     Effective November 13, 1996 the Company entered into the Credit Facility
which matures November 13, 2000. The Credit Facility permits the Company to
obtain revolving credit loans and issue letters of credit in 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 are unsecured and
interest rates are tied to the bank's prime rate or eurodollar rate, at the
option of the Company.

     The Credit Facility and Senior Notes include covenants that restrict the
Company's ability to take certain actions, including the ability to incur
additional indebtedness and to pay dividends on capital stock. To the extent
that the Company is restricted from incurring additional indebtedness under the
Senior Notes or the Credit Facility, the cash available for use in its
operations may be reduced. Under the most restrictive of these covenants, at
December 31, 1996, the Company could incur up to $253.4 million of additional
indebtedness, or incur a lesser amount and pay dividends of up to $61.7 million.
The Company's ability to pay dividends is limited by provisions in the Credit
Facility and the Senior Notes prohibiting the payment of more than $31.0 million
in dividends to SFR in any fiscal year prior to the Spin Off.

     At December 31, 1996, the Company had $2.3 million of outstanding letters
of credit.

DIVIDENDS

     The Company currently intends to pay to its stockholders a quarterly
dividend of $0.15 per share of common stock ($0.60 annually). The first dividend
has been declared and will be paid in April 1997, consisting of a prorated
dividend of $0.22 in respect of the Company's first partial quarter ended
December 31, 1996 and for its first full quarter of operations ending March 31,
1997. Although the Company currently intends to pay quarterly dividends, the
determination of the amount of future cash dividends, if any, to be declared and
paid will depend upon declaration by the Company's board of directors and upon
the Company's financial condition, earnings and funds from operations, the level
of its capital and exploration expenditures, dividend restrictions contained in
the Credit Facility and the Senior Notes as described in " -- Liquidity and
Capital Resources," future business prospects and such other matters as the
Company's directors deem relevant.

                                       24
<PAGE>
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.
These efforts include both Company employees responsible for environmental
compliance and paid consultants who have evaluated known sites for which the
Company may face environmental liability and who monitor the Company's
properties and waste handling and disposal practices. All oilfield wastes are
disposed of at facilities authorized to accept such wastes. 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.

     The Company has been named as a PRP with respect to certain Superfund
sites. See Items 1 and 2 "Business and Properties -- Environmental
Regulation -- Superfund."

INTERCOMPANY AGREEMENTS

     The Company has entered into certain agreements with SFR, see Items 1 and 2
"Business and Properties -- Relationship Between the Company and SFR."

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," "anticipates," "expects," "believes," "seeks," "goals,"
"intends", "plans" 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,
environmental risks, uncertainties about estimates of reserves, competition,
government regulation or action, litigation, drilling and operations
performance, labor disputes, 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..................    27
          Statement of Operations for
          the years ended December
          31, 1996, 1995 and 1994....    28
          Balance Sheet as of
          December 31, 1996 and
          1995.......................    29
          Statement of Cash Flows for
          the years ended December
          31, 1996, 1995 and 1994....    30
          Statement of Division
          Equity and Shareholders'
          Equity for the years ended
          December 31, 1996, 1995 and
          1994.......................    31
          Notes to Financial
        Statements...................    32
Unaudited Financial Information
          Supplemental Information to
        Financial Statements.........    44

                                       25
<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

     None.

                                    PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

ITEM 11.  EXECUTIVE COMPENSATION

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     Except for the portion of Item 10 relating to Executive Officers of the
Registrant which is included in Part 1 of this Report, the information called
for by Items 10 through 13 is incorporated by reference from the Company's
Notice of Annual Meeting and Proxy Statement dated March 24, 1997, which meeting
involves the election of directors, in accordance with General Instruction G to
the Annual Report on Form 10-K.

                                    PART IV

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

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

                                        PAGE
          1.  Financial Statements:
               Report of Independent
              Accountants............
                                         27
               Statement of
              Operations for the
              years ended December
              31, 1996, 1995 and
              1994...................
                                         28
               Balance Sheet as of
              December 31, 1996 and
              1995...................
                                         29
               Statement of Cash
              Flows for the years
              ended December 31,
              1996, 1995
                 and 1994............
                                         30
               Statement of Division
              Equity and
              Shareholders' Equity
              for the years ended
                 December 31, 1996,
              1995 and 1994..........
                                         31
               Notes to Financial
              Statements.............
                                         32
          2.  Financial Statement
              Schedules:
              All schedules have been
              omitted because they
              are not applicable or
              the required
              information is
              presented in the
              financial statements or
              the notes to financial
              statements.

        3.  Exhibits:

            See Index to Exhibits on page 50 for a description of the exhibits
            filed as a part of this report.

     (b)  Reports on Form 8-K

          None

                                       26

<PAGE>
                       REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Shareholders of
Monterey Resources, Inc.

In our opinion, the financial statements listed in the index appearing under
Item 14(a)(1) on page 26 present fairly, in all material respects, the financial
position of Monterey Resources, Inc. at December 31, 1996 and 1995, and the
results of its operations and its 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 20, 1997

                                       27
<PAGE>
                            MONTEREY RESOURCES, INC.
                            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......................  $   269.9  $   209.4  $   177.1
     Sales of natural gas produced...        1.3        1.9        1.6
     Sales of crude oil purchased....       21.1        6.6       11.9
     Other...........................        0.6        0.8        1.3
                                       ---------  ---------  ---------
                                           292.9      218.7      191.9
                                       ---------  ---------  ---------
Costs and Expenses
     Production and operating........      107.8       86.1       87.4
     Cost of crude oil purchased.....       20.8        6.5       11.7
     Exploration, including dry hole
       costs.........................        1.7        2.4        1.4
     Depletion, depreciation and
       amortization..................       37.4       32.4       32.0
     General and administrative......        8.9        7.3        7.8
     Taxes (other than income).......        9.4        7.9        8.7
     Restructuring charges...........     --         --            1.1
     Loss (gain) on disposition of
       properties....................     --         --           (0.3)
                                       ---------  ---------  ---------
                                           186.0      142.6      149.8
                                       ---------  ---------  ---------
Income from Operations...............      106.9       76.1       42.1
     Interest income.................        0.1     --         --
     Interest expense................      (25.0)     (25.8)     (26.4)
     Interest capitalized............        1.1        0.7        0.6
     Other income (expense)..........     --           (0.6)      (0.1)
                                       ---------  ---------  ---------
Income Before Income Taxes and
  Extraordinary Items................       83.1       50.4       16.2
     Income taxes....................      (28.3)     (16.0)      (4.7)
                                       ---------  ---------  ---------
Income Before Extraordinary Items....       54.8       34.4       11.5
     Extraordinary items.............       (4.5)    --         --
                                       ---------  ---------  ---------
Net Income...........................  $    50.3  $    34.4  $    11.5
                                       =========  =========  =========
Pro forma Per Share Data
     Income Before Extraordinary
       Items.........................  $    1.00  $    0.63  $    0.21
     Extraordinary items.............      (0.08)    --         --
                                       ---------  ---------  ---------
     Net Income......................  $    0.92  $    0.63  $    0.21
                                       =========  =========  =========
Number of shares used in computing
  per share amounts (in millions)....       54.8       54.8       54.8
                                       =========  =========  =========

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

                                       28
<PAGE>
                            MONTEREY RESOURCES, INC.
                                 BALANCE SHEET
                            (IN MILLIONS OF DOLLARS)

                                              DECEMBER 31,
                                           ------------------
                                            1996       1995
                                           -------    -------
                 ASSETS
Current Assets
     Cash and cash equivalents..........   $   9.3    $ --
     Accounts receivable................      46.4       20.6
     Inventories........................       1.7        1.4
     Other current assets...............       9.3        0.6
                                           -------    -------
                                              66.7       22.6
                                           -------    -------
Properties and Equipment, at cost
     Oil and gas (on the basis of
      successful efforts accounting)....   1,016.1      970.8
     Other..............................      14.2       20.0
                                           -------    -------
                                           1,030.3      990.8
     Accumulated depletion, depreciation
      and amortization..................    (651.3)    (623.5)
                                           -------    -------
                                             379.0      367.3
                                           -------    -------
Other Assets............................       1.5        1.4
                                           -------    -------
                                           $ 447.2    $ 391.3
                                           =======    =======
         LIABILITIES AND EQUITY
Current Liabilities
     Accounts payable...................   $  34.2    $   8.3
     Interest payable...................       4.7        6.4
     Taxes payable......................       5.8        2.0
     Accrued employee benefits..........       1.1        2.7
     Other current liabilities..........       3.0        1.5
                                           -------    -------
                                              48.8       20.9
                                           -------    -------
Long-Term Debt..........................     175.0      245.0
                                           -------    -------
Other Long-Term Obligations.............       3.5        5.7
                                           -------    -------
Deferred Income Taxes...................      43.2       74.7
                                           -------    -------
Commitments and Contingencies (Note
  11)...................................     --         --
                                           -------    -------
Shareholders' Equity
     Preferred stock, $0.01 par value,
      25,000,000 shares authorized, no
       shares issued or outstanding.....     --         --
     Common stock, $0.01 par value,
      100,000,000 shares authorized,
       54,757,499 shares issued and
      outstanding.......................       0.5      --
     Paid-in capital....................     170.8      --
     Unamortized restricted stock
      awards............................      (1.0)     --
     Retained earnings..................       6.4      --
     Division equity....................     --          45.0
                                           -------    -------
                                             176.7       45.0
                                           -------    -------
                                           $ 447.2    $ 391.3
                                           =======    =======

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

                                       29
<PAGE>
                            MONTEREY RESOURCES, INC.
                            STATEMENT OF CASH FLOWS
                            (IN MILLIONS OF DOLLARS)

                                           YEAR ENDED DECEMBER 31,
                                       -------------------------------
                                         1996       1995       1994
                                       ---------  ---------  ---------
Operating Activities:
  Net income.........................  $    50.3  $    34.4  $    11.5
  Adjustments to reconcile net income
     to net cash provided by
     operating activities:
     Depreciation, depletion and
      amortization...................       37.4       32.4       32.0
     Deferred income taxes...........        4.2        7.7        4.7
     Net loss (gain) on disposition
      of properties..................     --         --           (0.3)
     Exploratory dry hole costs......        0.3        1.0     --
     Other...........................     --           (0.2)      (0.1)
     Changes in operating assets and
      liabilities
       Decrease (increase) in
        accounts receivable..........      (25.8)       2.0       (5.5)
       Decrease (increase) in other
        current assets...............       (0.3)       0.5        0.5
       Increase (decrease) in
        accounts payable.............       17.6       (2.8)      (3.5)
       Increase (decrease) in
        interest payable.............       (1.8)    --         --
       Increase (decrease) in other
        current liabilities..........        5.8       (2.8)       4.9
       Net change in other assets and
        liabilities..................       (1.4)       3.5        1.3
                                       ---------  ---------  ---------
Net Cash Provided by Operating
  Activities.........................       86.3       75.7       45.5
                                       ---------  ---------  ---------
Investing Activities:
  Capital expenditures, including
     exploratory dry hole costs......      (43.0)     (52.9)     (27.3)
  Acquisition of producing
     properties......................       (3.4)      (1.3)    --
  Proceeds from sales of
     properties......................        0.1     --            9.1
  Other investing activities.........       (8.3)    --         --
                                       ---------  ---------  ---------
Net Cash Used in Investing
  Activities.........................      (54.6)     (54.2)     (18.2)
                                       ---------  ---------  ---------
Financing Activities:
  Net proceeds from issuance of
     common stock
       Initial public offering.......      123.6     --         --
       Issued to parent..............        0.4     --         --
  Principal payments on long-term
     borrowings......................      (70.0)    --          (12.6)
  Settlement of production payment...      (30.0)    --         --
  Net change in revolving credit
     agreement.......................      (16.0)    --         --
  Dividends to parent................      (30.4)     (21.5)     (14.7)
                                       ---------  ---------  ---------
Net Cash Used in Financing
  Activities.........................      (22.4)     (21.5)     (27.3)
                                       ---------  ---------  ---------
Net Increase in Cash and Cash
  Equivalents........................        9.3     --         --
Cash and Cash Equivalents at
  Beginning of Period................     --         --         --
                                       ---------  ---------  ---------
Cash and Cash Equivalents at End of
  Period.............................  $     9.3  $  --      $  --
                                       =========  =========  =========

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

                                       30
<PAGE>
                            MONTEREY RESOURCES, INC.
             STATEMENT OF DIVISION EQUITY AND SHAREHOLDERS' EQUITY
                        (SHARES AND DOLLARS IN MILLIONS)

<TABLE>
<CAPTION>
                                                                                                                       TOTAL
                                                                                                                      DIVISION
                                                         COMMON STOCK                 UNAMORTIZED                    EQUITY AND
                                           DIVISION    ----------------    PAID-IN     RESTRICTED     RETAINED     SHAREHOLDERS'
                                            EQUITY     SHARES    AMOUNT    CAPITAL    STOCK AWARDS    EARNINGS         EQUITY
                                           --------    ------    ------    -------    ------------    ---------    --------------
<S>                                         <C>          <C>     <C>       <C>           <C>            <C>            <C>   
Balance at December 31, 1993............    $  35.3      --      $--       $ --          $--            $--            $ 35.3
Net income..............................       11.5      --       --         --          --             --               11.5
Dividends to parent.....................      (14.7)     --       --         --          --             --              (14.7)
                                           --------    ------    ------    -------    ------------    ---------    --------------
Balance at December 31, 1994............       32.1      --       --         --          --             --               32.1
Net income..............................       34.4      --       --         --          --             --               34.4
Dividends to parent.....................      (21.5)     --       --         --          --             --              (21.5)
                                           --------    ------    ------    -------    ------------    ---------    --------------
Balance at December 31, 1995............       45.0      --       --         --          --             --               45.0
Net income..............................       43.9      --       --         --          --               6.4            50.3
Dividends to parent.....................      (30.4)     --       --         --          --             --              (30.4)
Issuance of common stock:
     Net assets contributed at book
       value............................      (58.5)     45.4      0.4        22.4       --             --              (35.7)
     Step-up in tax basis of certain
       assets...........................      --         --       --          23.9       --             --               23.9
     Initial public offering............      --          9.3      0.1       123.5       --             --              123.6
     Employee stock compensation........      --          0.1     --           1.0         (1.0)        --             --
                                           --------    ------    ------    -------    ------------    ---------    --------------
Balance at December 31, 1996............    $ --         54.8    $ 0.5     $ 170.8       $ (1.0)        $ 6.4          $176.7
                                           ========    ======    ======    =======    ============    =========    ==============
</TABLE>

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

                                       31
<PAGE>
                            MONTEREY RESOURCES, INC.
                         NOTES TO FINANCIAL STATEMENTS

(1)  ORGANIZATION AND BASIS OF PRESENTATION

     Monterey Resources, Inc. (the "Company" or "Monterey") was formed in
1996 to assume the operations of Santa Fe Energy Resources, Inc.'s ("SFR")
Western Division (the "Western Division") which conducted SFR's operations in
the state of California. The Company's financial statements include (i) the
operations of the Western Division for the years ended December 31, 1994 and
1995, and for the period January 1, 1996 through October 31, 1996, and (ii) the
operations of the Company for the two months ended December 31, 1996. The
financial statements for these periods are presented as if the Western Division
existed as a entity separate from SFR and include the historical assets,
liabilities, revenues and expenses that are directly related to the Company's
operations, and include allocations from certain SFR income statement and
balance sheet accounts. Such allocations are considered reasonable by management
and are discussed further in Note 4. Certain prior period amounts have been
reclassified to conform to current presentation.

     In November 1996, prior to the initial public offering (the "IPO")
discussed below, pursuant to a contribution and conveyance agreement, among
other things: (i) SFR contributed to Monterey substantially all of the assets
and properties of the Western Division, subject to the retention by SFR of a
$30.0 million production payment; (ii) the Company assumed all obligations and
liabilities of SFR associated with or allocated to the assets and properties of
the Western Division, including $245.0 million of indebtedness in respect of
SFR'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); (iii) Monterey agreed to purchase from SFR an $8.3
million promissory note receivable, which bears interest at prime plus 2%,
compounded quarterly, related to the sale to a third party of certain surface
acreage located in Orange County, California and secured by a Deed of Trust
thereon, and (iv) Monterey agreed to pay certain investment advisory fees which
approximate $3.5 million on behalf of SFR, payable only upon the occurrence of
the Spin Off (See Note 3). Also prior to the IPO, Monterey and SFR entered into
a $75.0 million revolving credit facility with a group of banks (the "Credit
Facility") and borrowed $16.0 million which was retained by SFR.

     In exchange for the net assets contributed, the Company issued 45,350,000
shares of its common stock to SFR. The transfer of assets resulted in a step-up
in the tax basis of certain transferred assets, and the Company recorded a $23.9
million deferred tax asset related to the step-up as a credit to paid-in
capital.

     In November 1996 Monterey completed its IPO, selling 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 costs of $2.6 million). The
proceeds from the IPO were used in part to (i) repay the Series E Notes and the
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 Credit Facility; and (iv) pay a $2.0 million
fee with respect to a supplement to the indenture relating to SFR's 11% Senior
Subordinated Debentures due 2004 to permit the IPO and the Spin Off (as defined
in Note 3) to proceed without the occurrence of a breach or default under such
indenture. Subsequent to the IPO, Monterey issued $175.0 million in aggregate
principal amount of 10.61% Senior Notes due 2005 (the "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 the
Company purchased the previously mentioned $8.3 million note receivable, which
bears interest at prime plus 2% and matures on June 30, 1997, from SFR for cash.

     The costs and expenses relating to the early extinguishment of debt assumed
in the IPO as discussed above, and $1.0 million of related transaction costs,
are reflected in the Statement of Operations as an extraordinary item, net of
$2.3 million in income taxes.

     At December 31, 1996, SFR owned 82.8% of the Company's outstanding common
stock. SFR has announced that it intends to distribute pro rata to its common
shareholders all of the shares of the Company's common stock that it owns by
means of a tax-free distribution. See Note 3.

                                       32
<PAGE>
                            MONTEREY RESOURCES, INC.
                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

(2)  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

  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
("SFAS") No. 121 "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of". In accordance with the provisions of SFAS
No. 121 individual proved properties are reviewed periodically 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, 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, based on discounted future net cash flows. No impairments were
recorded in connection with the adoption of SFAS No. 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 $19.1
million and such amount is being accrued using unit-of-production rates over the
expected life of the properties. At December 31, 1996 and 1995, Accumulated
Depletion, Depreciation and Amortization includes $6.2 million and $4.8 million,
respectively, of such costs.

     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.

     The Company's financial statements reflect its proportionate interest in
the revenues, costs, expenses and capital with respect to properties in which
its ownership is less than 100%.

  REVENUE RECOGNITION

     Revenues from the sale of crude oil and liquids produced are generally
recognized upon the passage of title (generally when the crude oil and liquids
leave the field), net of royalties and net profits interests. 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 marketing margins. The cost to purchase such crude oil is reflected as an
expense. Revenues from natural gas production are generally recorded using the
entitlement method, net of royalties and net profits interests.

     From time to time a portion of the Company's oil sales have been hedged.
See Note 11 -- Commitments and Contingencies -- Hedging.

                                       33
<PAGE>
                            MONTEREY RESOURCES, INC.
                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

  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.

  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
$0.9 million and $0.8 million, respectively, and materials and supplies
inventories at such dates were $0.8 million and $0.6 million, respectively.

  ENVIRONMENTAL EXPENDITURES

     Environmental expenditures relating to current operations are expensed or
capitalized, as appropriate, depending on whether such expenditures provide
future economic benefits. Liabilities are recognized when the expenditures are
considered probable and can be reasonably estimated. Measurement of liabilities
is based on currently enacted laws and regulations, existing technology and
undiscounted site-specific costs. Generally, such recognition coincides with the
Company's commitment to a formal plan of action.

  INCOME TAXES

     The Company is included in the consolidated tax return of SFR and records a
provision for income taxes under the terms of the Tax Allocation Agreement with
SFR (See Note 12). 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.

  PRO FORMA PER SHARE DATA

     Common shares outstanding at November 19, 1996, the closing date of the
Company's IPO, have been included in the pro forma per share calculations as if
such shares were outstanding for all periods prior to November 19, 1996.

                                       34
<PAGE>
                            MONTEREY RESOURCES, INC.
                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

(3)  INTENDED SPIN OFF

     SFR has announced that it intends to distribute pro rata to its common
shareholders all of the shares of the Company's common stock it owns by means of
a tax-free distribution (the "Spin Off"). SFR's final determination to proceed
will require a declaration of the Spin Off by SFR's board of directors. Such a
declaration is not expected to be made until certain conditions, many of which
are beyond the control of SFR, are satisfied, including: (i) receipt by SFR of a
ruling from the Internal Revenue Service as to the tax-free nature of the Spin
Off, (ii) approval of the Spin Off by SFR's stockholders; (iii) the absence of
any future change in future market or economic conditions (including
developments in the capital markets) or SFR's or the Company's business and
financial condition that causes SFR's board to conclude that the Spin Off is not
in the best interests of SFR's shareholders. The Company has been advised by SFR
that it does not expect the Spin Off to occur prior to August 1997. If SFR
consummates the Spin Off, the increased shares available in the marketplace may
have an adverse effect on the market price of the Company's common stock.
Monterey has been advised by SFR that as of December 31, 1996, SFR had
approximately 38,500 shareholders of record.

     Pursuant to the terms of a letter agreement dated as of June 13, 1996, a
fee will be payable by the Company to Chase Securities Inc. and Petrie Parkman &
Co., Inc. upon consummation of the 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 the
Company's common stock distributed in the Spin Off (based upon the average
closing price of the Company's common stock during the ten trading days after
the Spin Off) PLUS the aggregate principal amount of long-term indebtedness
assumed by the Company in connection with the Spin Off (which totalled $175.0
million) TIMES (b) 0.5%, LESS $1.0 million. If the market value of the Company's
common stock at the time of the Spin Off 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 of the Company and SFR. One of the Company's
directors is associated with GKH Partners.

(4)  RELATED-PARTY TRANSACTIONS

     The financial statements for Western Division for each of the periods
presented include certain allocations from SFR income statement and balance
sheet accounts, which are considered reasonable and necessary by management to
properly reflect the actual costs incurred of the Western Division's operations.
The Western Division's results of operations include corporate overhead
allocations as follows: (i) production and operating expense includes $2.4
million in 1996, $1.9 million in 1995 and $3.0 million in 1994; (ii) exploration
expense includes $0.3 million in 1996, $0.5 million in 1995 and $0.5 million in
1994; and (iii) general and administrative expense includes $5.3 million in
1996, $6.4 million in 1995 and $7.9 million in 1994. If the Western Division had
been a separate, unaffiliated entity, the Company estimates that general and
administrative expense would have been higher by $0.6 million, $2.1 million and
$1.2 million in 1996, 1995 and 1994, respectively. SFR provided cash management
services to the Western Division through a centralized treasury system and
therefore all intercompany accounts were settled daily and no cash balances were
maintained by the Western Division. All cash generated from the Western
Division's operations, after considering revenues and deductions for expenses
(including corporate allocations), capital expenditures and working capital
requirements, were deemed to be cash dividends to SFR.

     SFR provides various administrative and financial services to the Company,
including administration of certain employee benefits plans, access to
telecommunications, corporate legal assistance and certain other corporate staff
and support services. The Company and SFR have entered into a Services Agreement
under which the Company pays a fee of $120,000 per month for such services until
such time as the

                                       35
<PAGE>
                            MONTEREY RESOURCES, INC.
                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Company assumes full responsibility during 1997 for each of the services covered
by the agreement. General and administrative expense for 1996 includes $240,000
of such costs.

     See Note 1 for a discussion of the Company's purchase of an $8.3 million
promissory note from SFR, Note 3 for discussion of advisory fees payable upon
consummation of the Spin Off to an affiliate of one of the Company's directors
and Note 10 for discussion of the participation of certain of the Company's
employees in SFR's employee benefit and pension plans.

(5)  CASH FLOWS

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

     The Company made interest payments of $26.8 million, $25.8 million and
$26.3 million in 1996, 1995 and 1994, respectively.

(6)  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
                                    -------    ---------    -------    ---------
Senior Notes.....................     --         175.0        --         --
SFR Series E & F Notes...........     --         --           --          70.0
SFR Series G Notes...............     --         --           --         175.0
                                    -------    ---------    -------    ---------
                                      --         175.0        --         245.0
                                    =======    =========    =======    =========

     In November 1996 the Company issued the Senior Notes which were exchanged
for $175.0 million of senior notes previously issued by SFR. The Senior Notes
bear interest at 10.61% per annum and mature $25 million per year in each of the
years 1999 through 2005.

     Effective November 13, 1996 the Company entered into the Credit Facility
which matures November 13, 2000. The Credit Facility permits the Company 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 are unsecured and
interest rates are tied to the bank's prime rate or eurodollar rate, at the
option of the Company.

     The Credit Facility and Senior Notes include covenants that restrict the
Company's ability to take certain actions, including the ability to incur
additional indebtedness and to pay dividends on capital stock. Under the most
restrictive of these covenants, at December 31, 1996, the Company could incur up
to $253.4 million of additional indebtedness, or incur a lesser amount and pay
dividends of up to $61.7 million. The Company's ability to pay dividends is
limited by provisions in the Credit Facility and the Senior Notes prohibiting
the payment of more than $31.0 million in dividends to SFR in any fiscal year
prior to the Spin Off.

     At December 31, 1996, the Company had $2.3 million of outstanding letters
of credit.

     In 1994 the Company retired the $12.6 million outstanding balance of a term
loan which the Company had incurred in 1991 in connection with the purchase of
certain producing properties.

(7)  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

                                       36
<PAGE>
                            MONTEREY RESOURCES, INC.
                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
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
                                    --------   ---------   --------   ---------
Long-Term Debt...................     175.0        199.9     245.0        267.9

     The fair value of the Company's long-term debt is based upon current
borrowing rates available for financings with similar terms and maturities.

(8)  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. All such operations are located
in the United States.

     Crude oil and liquids accounted for about 99% 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
                                       -----------  -----------  -----------
Shell Oil Company....................          35           44           42
Celeron Corporation..................          22           28           31

(9)  SHAREHOLDERS' EQUITY

  COMMON STOCK

     In a public offering in November 1996 the Company issued 9,335,000 shares
of common stock. The issue price was $14.50 per share and the Company received
total proceeds of $123.6 million, after deducting underwriting costs of $9.1
million and other costs of $2.6 million. Immediately prior to the IPO the
Company issued 45,350,000 shares to SFR in exchange for the net assets of the
Western Division.

     The Company currently intends to pay to its stockholders a quarterly
dividend of $0.15 per share of common stock ($0.60 annually). The first dividend
has been declared and will be paid in April 1997, consisting of a pro rated
dividend of $0.22 in respect of the Company's first partial quarter ended
December 31, 1996, and for its first full quarter of operations ending March 31,
1997.

  1996 INCENTIVE STOCK COMPENSATION PLAN

     Under the terms of the Monterey Resources, Inc. 1996 Incentive Stock
Compensation Plan (the "Plan") the Company may grant options and awards with
respect to no more than 3,000,000 shares of common stock to officers, directors
and key employees. Up to 500,000 of such shares may be issued as Restricted
Stock. During 1996, the Company granted options on 248,500 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, which were awarded at the market
price at the date of the grant, have a ten-year term and vest 20% per year over
five years. 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%; (ii) expected stock price
volatility -- 24%; (iii) risk-free interest rate -- 6.4%; (iv) expected life of
options -- 10 years.

                                       37
<PAGE>
                            MONTEREY RESOURCES, INC.
                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

     During 1996 the Company also issued 72,499 restricted shares in accordance
with the terms of the plan, which vest over a five-year period from the date of
grant.

     Notwithstanding anything in the Plan or any Award agreement to the
contrary, generally no 1996 Award shall become exercisable or payable (even if
vested) prior to the first anniversary of the date the Company is spun off by
SFR, or during any such additional period, if any, as may be recommended by
counsel to the Company as necessary or helpful to the tax-free status of the
Spin Off.

     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
for 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 in accordance with APB 25. If the Company had elected
to recognize compensation costs based on the fair value of options granted as
prescribed by FAS 123, net income and the related per share amounts would have
been unchanged.

     During the initial phase-in period, the effects of applying FAS 123 for
recognizing compensation cost on a pro forma 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.

(10)  PENSION AND OTHER EMPLOYEE BENEFIT PLANS

  PENSION PLANS

     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%

                                       38
<PAGE>
                            MONTEREY RESOURCES, INC.
                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

     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
                                          =========  =========  =========

     The Company's salaried personnel participate in the SFR defined benefit
retirement plan (the "SFR Plan") and a nonqualified supplemental retirement
plan (the "Supplemental Plan"). The Supplemental Plan will pay benefits to
participants in the SFR Plan in those instances where the SFR Plan formula
produces a benefit in excess of limits established by ERISA and the Tax Reform
Act of 1986. Benefits payable under the SFR Plan are based on years of service
and compensation during the five highest paid years of service during the ten
years immediately preceding retirement. SFR'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 Company has been
allocated its proportionate share of the expense associated with such plans. The
Company's share of such expenses totaled $0.4 million, $0.2 million and $0.2
million in 1996, 1995, and 1994 respectively.

  POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

     SFR provides healthcare and life insurance benefits for substantially all
employees who retire under the provisions of a SFR-sponsored retirement plan and
their dependents. Participation in the plans is voluntary and requires a monthly
contribution by the employee. Effective January 1, 1993 SFR adopted the
provisions of SFAS No. 106 -- "Employers' Accounting for Postretirement
Benefits Other Than Pensions." The Statement requires the accrual, during the
years the employee renders service, of the expected cost of providing
postretirement benefits to the employee and the employee's beneficiaries and
covered dependents. The Company has been allocated its proportionate share of
SFR's expense with respect to such benefits. The Company's share of such expense
totaled $0.2 million in 1996 and $0.1 million in each of 1995 and 1994.

  SAVINGS PLAN

     SFR 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"). SFR 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 SFR'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 has been allocated its proportionate share of
contributions to the 401(k) Plan, which are charged to expense. The Company's
share of such contributions totaled $0.3 million in 1996 and $0.2 million in
each of 1995 and 1994.

(11)  COMMITMENTS AND CONTINGENCIES

  HEDGING

     The Company's 1996 and 1995 financial statements include the impact of oil
and gas hedging losses which were allocated by SFR. SFR from time to time enters
into such transactions in order to reduce exposure to fluctuations in market
prices of oil and natural gas. Oil hedging losses were allocated to the

                                       39
<PAGE>
                            MONTEREY RESOURCES, INC.
                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Company based upon relative production volumes and were recognized as a
reduction of oil revenues in the period in which the hedged production was sold.
Such amounts totaled $3.1 million and $0.1 million in 1996 and 1995,
respectively. Currently the Company has no oil hedges in place and, going
forward, the Company does not expect to hedge a substantial portion of its oil
production.

     Additionally, during the first six months of 1996, SFR hedged 20 MMcf per
day of the natural gas purchased for use in the Company's steam generation
operations. Such hedges, which terminated at the end of the second quarter,
resulted in a $3.2 million increase in the Company's production and operating
costs. While the Company currently has no natural gas hedges in place, the
Company's management may determine that such arrangements are appropriate in the
future in order to reduce the Company's exposure to increases in gas prices.

  SPIN OFF TAX INDEMNITY AGREEMENT.

     To protect SFR from Federal and state income taxes, penalties, interest and
additions to tax that would be incurred by it if the Spin Off by SFR were
determined to be a taxable event, the Company and SFR have entered into an
agreement under which the Company has agreed to indemnify SFR with respect to
tax liabilities resulting primarily from actions taken by the Company at any
time during the one-year period after the Spin Off (or if certain tax
legislation is enacted and is applicable to the Spin Off, such longer period as
is required for the Spin Off to be tax free to SFR) (the "Restricted Period").
The Company has also agreed that, unless it obtains an opinion of counsel or a
supplemental ruling from the Internal Revenue Service that such action will not
adversely affect the qualification of the Spin Off as tax-free, the Company will
not merge or consolidate with another corporation, liquidate or partially
liquidate, sell or transfer all or substantially all of its assets or redeem or
otherwise repurchase any of its stock or issue additional shares of the
Company's capital stock during such Restricted Period. The Company's obligations
under this agreement could possibly deter offers or other efforts by third
parties to obtain control of the Company during such Restricted Period, which
could deprive the Company's stockholders of opportunities to sell their shares
of Common Stock at prices higher than prevailing market prices.

     The indemnity agreement will apply if the Spin Off occurs prior to December
31, 1997. The Company believes that if the Company is required to make payments
pursuant to such agreement, the amount that the Company would pay to SFR would
have a material adverse effect on the Company's financial condition. The actions
for which the Company is required to indemnify SFR pursuant to this agreement
are within the Company's control, and the Company has no intention of taking any
actions during the Restricted Period that would have such effect.

  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. Set
forth below are descriptions of three sites for which the Company has been
identified as a potentially responsible party ("PRP") and for which the
Company may be held jointly and severally liable with other PRPs.

     The Company has been identified as one of over 250 PRPs at a superfund site
in Los Angeles County, California (the "OII site"). The site was operated by a
third party as a waste disposal facility from 1948 until 1983. The Environmental
Protection Agency ("EPA") is requiring the PRPs to undertake remediation of
the site in several phases, which include site monitoring and leachate control,
gas control and final remediation. In November 1988 the EPA and a group of PRPs
that includes the Company entered into a consent decree covering the site
monitoring and leachate control phases of remediation. The Company was a member
of the group Coalition Undertaking Remediation Efforts ("CURE") which was
responsible for constructing and operating the leachate treatment plant. This
phase is now complete and the Company's share of costs with respect to this
phase was $1.6 million ($0.9 million after recoveries from working interest
participants in the unit in which the wastes were generated). Another consent
decree provides for

                                       40
<PAGE>
                            MONTEREY RESOURCES, INC.
                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
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 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 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 that its share of final costs of the 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
ninety-five homeowners alleging, among other things, nuisance, trespass, strict
liability and infliction of emotional distress. A second lawsuit has been filed
by thirty-three 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 seven
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 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 site. Total past and future costs for remediation are
estimated 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 cost to complete this final
remediation to be $3 million and the Company has provided $250,000 for such
costs in its 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 during its
fourteen-year operation from 1971 to 1985 (the "Eastside Site"). 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.

     Pursuant to the Contribution Agreement, the Company agreed to indemnify and
hold harmless SFR from and against any costs incurred in the future relating to
environmental liabilities of the Western Division assets (other than the assets
retained by SFR), including any costs or expenses incurred at any of

                                       41
<PAGE>
                            MONTEREY RESOURCES, INC.
                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
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 of any property or interest therein located in California
and formerly owned or operated by the Western Division or its predecessors. SFR
agreed to indemnify the Company from and against any costs relating to
environmental liabilities of any assets or operations of SFR (whether or not
currently owned or operated by SFR) to the extent not attributable to the
Western Division (other than the assets retained by SFR).

  EMPLOYMENT AGREEMENTS

     The Company has entered into employment agreements ("Employment
Agreements") with eight key employees. The initial term of seven of the
agreements expire on December 31, 1998; however, beginning January 1, 1998 and
on each January 1 thereafter the term of the agreements will automatically be
extended for additional one-year periods, unless by September 30 of the
preceding year the Company gives notice that the agreement will not be so
extended. The term of each is automatically extended for a period of two years
following a Change in Control (as defined herein). The other employment
agreement has an initial term which expires on December 31, 1999, is
automatically extended for one-year periods beginning January 1, 1999 and is
automatically extended for a three-year period following a Change in Control.

     In the event that following a change in control employment is terminated
for reasons specified in the Employment Agreements, the agreements provide for
(i) payment of certain amounts to the employee based on the employee's salary
and bonus under the Company's Incentive Compensation Plan; (ii) payout of
nonvested restricted stock, phantom units, stock options, if any, and (iii)
continuation of certain insurance benefits for a period of up to 24 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. In addition, payments and benefits under certain employment
agreements are subject to further limitation based on certain provisions of the
Internal Revenue Code.

  OPERATING LEASES

     The Company has noncancellable agreements with terms ranging from one to
six years to lease office space and equipment. Minimum rental payments due under
the terms of these agreements are: 1997 -- $1.7 million, 1998 -- $1.5 million,
1999 -- $1.4 million, 2000 -- $1.2 million, 2001 -- $1.2 million and $5.5
million thereafter. Rental payments made under the terms of noncancellable
agreements totaled $1.3 million in 1996, $0.8 million in 1995 and $0.9 million
in 1994.

  OTHER MATTERS

     The Company has certain long-term contracts ranging up to eleven 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 equal to 102%
of the applicable index and transportation charges in effect for December 1996).

     There are other claims and actions, including certain other environmental
matters, pending against the Company. While the outcome of lawsuits or other
proceedings against the Company cannot be predicted with certainty, management
does not expect these matters to have a material adverse effect on the business,
financial condition or liquidity of the Company.

(12)  INCOME TAXES

     Monterey is included in the consolidated tax returns of SFR, and pursuant
to the Tax Allocation Agreement, the Company pays to SFR an amount approximating
the federal, state and local tax liability it would have paid if it was an
unaffiliated company. Accordingly, the amounts reflected in the financial

                                       42
<PAGE>
                            MONTEREY RESOURCES, INC.
                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
statements, for all periods presented, have been prepared as if Monterey was not
a member of SFR's consolidated group.

     During 1995 SFR elected for federal income tax purposes to capitalize,
rather than expense, intangible drilling costs attributable to the Company's
operations (which aggregated $23 million and $22 million in 1996 and 1995,
respectively). Current federal tax expense includes $5.8 million and $7.0
million in 1996 and 1995, respectively, as a result of such election. After the
Company ceases to be a member of SFR's consolidated group, it intends to elect
to expense such costs thereafter incurred.

     The Company's income tax expense for the years ended December 31, 1996,
1995 and 1994 is presented below. Such amounts for 1996 include a current and
deferred tax benefit of $2.2 million and $0.1 million, respectively, related to
the Company's extraordinary debt extinguishment costs.

                                         1996     1995     1994
                                         ----     ----     ----
Current
     U.S. federal....................    15.7      5.0     --
     State...........................     6.1      3.3     --
                                         ----     ----     ----
                                         21.8      8.3     --
                                         ----     ----     ----
Deferred
     U.S. federal....................     3.7      6.4     3.0
     State...........................     0.4      1.3     1.7
                                         ----     ----     ----
                                          4.1      7.7     4.7
                                         ----     ----     ----
                                         25.9     16.0     4.7
                                         ====     ====     ====

     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.....    40.8      72.4
State deferred liability.............    10.1      17.0
                                         ----     -----
Gross deferred liabilities...........    50.9      89.4
                                         ----     -----
Accruals not currently deductible for
tax purposes.........................    (5.8)     (7.3)
EOR credit carryforwards.............    (1.9)     (4.6)
AMT credit carryforwards.............     --       (2.8)
                                         ----     -----
Gross deferred assets................    (7.7)    (14.7)
                                         ----     -----
Deferred tax liability...............    43.2      74.7
                                         ====     =====

     A reconciliation of the Company's U.S. income tax expense computed by
applying the statutory U.S. federal income tax rate to the Company's income
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..................................       26.7       17.6        5.7
Increase (reduction) resulting from:
     State income taxes, net of federal
       effect...........................        4.2        3.0        1.1
     Enhanced oil recovery credit.......       (5.2)      (4.2)      (2.5)
     Permanent differences..............        0.2       (0.2)      (0.2)
     Other..............................     --           (0.2)       0.6
                                          ---------  ---------  ---------
                                               25.9       16.0        4.7
                                          =========  =========  =========

                                       43
<PAGE>
                            MONTEREY RESOURCES, INC.
                          SUPPLEMENTAL INFORMATION TO
                        FINANCIAL STATEMENTS (UNAUDITED)

OIL AND GAS RESERVES AND RELATED FINANCIAL DATA

     Information with respect to the Company's oil and gas producing activities,
all of which are located in the United States, 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, 1996, 1995, 1994 and 1993 and the changes in net proved
oil and gas reserves for the years ended December 31, 1996, 1995 and 1994.

                                            CRUDE OIL     NATURAL
                                           AND LIQUIDS      GAS
                                            (MMBBLS)       (BCF)
                                           -----------    -------
Proved reserves at December 31, 1993....      183.6         11.8
     Revisions of previous estimates....        9.9          2.9
     Improved recovery techniques.......       12.6         --
     Purchases of minerals-in-place.....        0.2          0.1
     Production.........................      (15.1)        (1.4)
                                           -----------    -------
Proved reserves at December 31, 1994....      191.2         13.4
     Revisions of previous estimates....        9.7          0.9
     Improved recovery techniques.......       13.7         --
     Purchases of minerals-in-place.....        0.1         --
     Production.........................      (15.2)        (1.9)
                                           -----------    -------
Proved reserves at December 31, 1995....      199.5         12.4
     Revisions of previous estimates....       12.0          1.1
     Improved recovery techniques.......       14.4         --
     Purchases of minerals-in-place.....        7.6         --
     Production.........................      (17.1)        (1.3)
                                           -----------    -------
Proved reserves at December 31, 1996....      216.4         12.2
                                           ===========    =======


                                            CRUDE OIL     NATURAL
                                           AND LIQUIDS      GAS
                                            (MMBBLS)       (BCF)
                                           -----------    -------
Proved developed reserves at December
  31:
     1996...............................      171.0          9.5
     1995...............................      157.1          9.2
     1994...............................      140.2          9.4
     1993...............................      140.8          9.0

     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.

                                       44
<PAGE>
                            MONTEREY RESOURCES, INC.
                          SUPPLEMENTAL INFORMATION TO
                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):

                                             1996        1995        1994
                                          ----------  ----------  ----------
Future cash inflows.....................     4,169.3     2,763.0     2,428.5
Future production costs.................    (2,178.0)   (1,383.6)   (1,219.9)
Future development costs................      (170.6)     (170.0)     (167.9)
Future income tax expenses..............      (638.4)     (421.5)     (352.7)
                                          ----------  ----------  ----------
  Net future cash flows.................     1,182.3       787.9       688.0
Discount at 10% for timing of cash
  flows.................................      (501.6)     (361.5)     (321.9)
                                          ----------  ----------  ----------
Present value of future net cash flows
  from proved reserves (standardized
  measure)..............................       680.7       426.4       366.1
                                          ==========  ==========  ==========
Present value of pretax future net cash
  flows from proved reserves............     1,047.8       654.4       553.8
                                          ==========  ==========  ==========
Average sales prices
  Oil ($/Barrel)........................       19.19       13.78       12.62
  Natural gas ($/Mcf)...................        1.38        0.98        1.07

     The following table 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):

                                             1996        1995        1994
                                          ----------  ----------  ----------
Balance at beginning of year............       426.4       366.1       143.0
                                          ----------  ----------  ----------
Increase (decrease) due to:
  Sales of oil and gas, net of
     production costs...................      (155.9)     (119.2)      (85.0)
  Net changes in prices and production
     costs..............................       265.8        89.9       405.3
  Extensions, discoveries and improved
     recovery...........................        66.6        39.6        25.6
  Purchases of minerals-in-place........        40.8         0.8         0.6
  Sales of minerals-in-place............        (0.4)     --          --
  Development costs incurred............        50.5        49.1        22.7
  Changes in estimated volumes..........        79.8         8.8        20.1
  Changes in estimated development
     costs..............................       (20.8)      (24.8)      (22.7)
  Interest factor -- accretion of
     discount...........................        66.9        56.5        20.0
  Income taxes..........................      (139.0)      (40.4)     (163.5)
                                          ----------  ----------  ----------
                                               254.3        60.3       223.1
                                          ----------  ----------  ----------
                                               680.7       426.4       366.1
                                          ==========  ==========  ==========

     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.

                                       45
<PAGE>
                            MONTEREY RESOURCES, INC.
                          SUPPLEMENTAL INFORMATION TO
                FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)

     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.

  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):

                                         1996       1995       1994
                                       ---------  ---------  ---------
Property acquisition costs
  Unproved...........................        0.1        0.1     --
  Proved.............................        3.4        1.3     --
Exploration costs....................        1.6        2.5        1.4
Development costs....................       47.1       47.8       22.7
                                       ---------  ---------  ---------
                                            52.2       51.7       24.1
                                       =========  =========  =========

  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
                                       ---------  ---------
Oil and gas properties
  Unproved...........................        0.4        0.4
  Proved.............................    1,006.2      960.7
  Other..............................        9.6        9.7
Accumulated amortization of unproved
  properties.........................       (0.2)      (0.1)
Accumulated depletion and
  depreciation of proved
  properties.........................     (643.3)    (614.8)
Accumulated depreciation of other oil
  and gas properties.................       (3.5)      (3.4)
                                       ---------  ---------
                                           369.2      352.5
                                       =========  =========

                                       46
<PAGE>
                            MONTEREY RESOURCES, INC.
                          SUPPLEMENTAL INFORMATION TO
                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):

                                            1996       1995       1994
                                          ---------  ---------  ---------
Revenues................................      292.9      218.7      191.9
Production costs:
     Production and operating costs.....     (107.8)     (86.1)     (87.4)
     Taxes (other than income)..........       (8.2)      (6.8)      (7.6)
Cost of crude oil purchases.............      (20.8)      (6.5)     (11.7)
Exploration, including dry hole costs...       (1.7)      (2.4)      (1.4)
Depletion, depreciation and
  amortization..........................      (36.1)     (31.1)     (31.1)
Restructuring charges...................     --         --           (1.1)
Gain (loss) on disposition of
  properties............................     --         --            0.3
                                          ---------  ---------  ---------
                                              118.3       85.8       51.9
Income taxes............................      (48.4)     (35.1)     (21.2)
                                          ---------  ---------  ---------
                                               69.9       50.7       30.7
                                          =========  =========  =========

     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.

                                       47
<PAGE>
                            MONTEREY RESOURCES, INC.
                          SUPPLEMENTAL INFORMATION TO
                FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)

  SUMMARIZED QUARTERLY FINANCIAL DATA

<TABLE>
<CAPTION>
                                        1ST QTR     2ND QTR     3RD QTR     4TH QTR     YEAR
                                        --------    --------    --------    --------    -----
                                              (IN MILLIONS OF DOLLARS, EXCEPT AS NOTED)
1996
<S>                                       <C>         <C>         <C>          <C>      <C>  
     Revenues........................     59.7        68.4        76.9         87.9     292.9
     Gross profit (a)................     24.4        30.2        26.3         34.9     115.8
     Income from operations..........     22.5        28.2        24.4         31.8     106.9
     Income before extraordinary
       items.........................     16.2         8.0        11.7         18.9      54.8
     Extraordinary items.............     --          --          --           (4.5)     (4.5)
     Net income......................     16.2         8.0        11.7         14.4      50.3
     Pro forma per share data (b)
          Income before extraordinary
             items...................     0.30        0.15        0.21         0.34      1.00
          Extraordinary items........     --          --          --          (0.08)    (0.08)
          Net income.................     0.30        0.15        0.21         0.26      0.92
     Number of shares used in
       computing per share amounts
       (in millions).................     54.8        54.8        54.8         54.8      54.8
1995
     Revenues........................     51.0        57.2        56.8         53.7     218.7
     Gross profit (a)................     15.8        24.9        23.1         19.6      83.4
     Income from operations..........     13.8        23.2        21.3         17.8      76.1
     Net income......................      7.5         9.1         9.8          8.0      34.4
     Pro forma net income per share
       (b)...........................     0.14        0.17        0.18         0.14      0.63
     Number of shares used in
       computing per share amounts
       (in millions).................     54.8        54.8        54.8         54.8      54.8
</TABLE>

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

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

(b) Common shares outstanding at November 13, 1996, the closing date of the
    Company's IPO, have been included in the pro forma per share calculations as
    if such shares were outstanding for all periods prior to November 13, 1996.

                                       48
<PAGE>
                                   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.

                                          MONTEREY RESOURCES, INC.
                                          By R. GRAHAM WHALING
                                             R. GRAHAM WHALING
                                             CHAIRMAN OF THE BOARD
                                             AND CHIEF EXECUTIVE OFFICER
                                             (PRINCIPAL EXECUTIVE OFFICER)

Dated:  March 7, 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.

<TABLE>
<CAPTION>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
                 SIGNATURE AND TITLE
                 -------------------
                  R. GRAHAM WHALING                                     By: R. GRAHAM WHALING
              Chairman of the Board and                                   R. GRAHAM WHALING
               Chief Executive Officer                                  CHAIRMAN OF THE BOARD
            (PRINCIPAL EXECUTIVE OFFICER)                            AND CHIEF EXECUTIVE OFFICER
                                                                           ATTORNEY-IN-FACT

                   GERALD R. CARMAN                                      By: GERALD R. CARMAN
       Vice President, Chief Financial Officer                            GERALD R. CARMAN
                    and Treasurer                                  VICE PRESIDENT, CHIEF FINANCIAL
           (PRINCIPAL FINANCIAL OFFICER AND                             OFFICER AND TREASURER
            PRINCIPAL ACCOUNTING OFFICER)

                      DIRECTORS
                    James L. Payne
                     Hugh L. Boyt
                    Craig A. Huff
                  Michael A. Morphy
                    Robert F. Vagt
                Robert J. Wasielewski
</TABLE>

Dated:  March 7, 1997

                                       49
<PAGE>
                               INDEX TO EXHIBITS

     A. EXHIBITS

        EXHIBIT
         NUMBER                      DESCRIPTION
-------------------------------------------------------------
           3.1*     --  Amended and Restated Certificate of
                        Incorporation (incorporated by
                        reference to Exhibit 3.1 of the Form
                        S-1 Registration Statement of
                        Monterey Resources, Inc. ("MRI")
                        Commission File No. 333-12201 (the
                        "Registration Statement").
           3.2*     --  Amended and Restated Bylaws
                        (incorporated by reference to Exhibit
                        3.2 of the Registration Statement).
          10.1       -- Conveyance and Contribution Agreement
                        between MRI and SFR.
          10.2       -- Agreement for the Allocation of
                        Consolidated Federal Income Tax
                        Liability and State and Local Taxes
                        among the members of the SFER
                        affiliated group.
          10.3       -- Agreement Concerning Taxes and Tax
                        Indemnification Upon Spin Off,
                        between MRI and SFR.
          10.4       -- Corporate Services Agreement between
                        MRI and SFR.
          10.5       -- Registration Rights and
                        Indemnification Agreement between MRI
                        and SFR.
          10.6       -- MRI Incentive Compensation Plan.
          10.7       -- MRI Incentive Stock Compensation Plan
                        for Key Employees.
          10.8       -- MRI Incentive Stock Compensation Plan
                        for Nonexecutive Employees.
          10.9       -- MRI Severance Program.
          10.10     --  MRI Savings Investment Plan.
          10.11     --  MRI Deferred Compensation Plan.
          10.12     --  MRI Employee Stock Ownership Plan.
          10.13     --  Employment Agreement between MRI and
                        R. Graham Whaling.
          10.14*    --  Form of Employment Agreement between
                        MRI and certain executive officers
                        (incorporated by reference to Exhibit
                        10.14 of the Registration Statement).
          10.15     --  Note Agreement dated November 19,
                        1996 for $175,000,000, 10.61% Senior
                        Notes due 2005.
          10.16     --  Credit Agreement, dated November 13,
                        1996 for up to $75 million, among
                        MRI, the Banks signatory thereto and
                        Chase Manhattan Bank as
                        Administrative Agent.
          23.1       -- Consent of Price Waterhouse LLP.
          23.2       -- Consent of Ryder Scott Company.
          24.1       -- Powers of Attorney.

------------
* Incorporated by reference.

                                       50