UNITED STATES
                       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, 1999

                                       OR

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

                         COMMISSION FILE NUMBER 1-7667

                          SANTA FE SNYDER CORPORATION
             (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)

<TABLE>
<S>                                  <C>
              DELAWARE                            36-2722169
   (STATE OR OTHER JURISDICTION OF             (I.R.S. EMPLOYER
   INCORPORATION OR ORGANIZATION)             IDENTIFICATION NO.)

         840 GESSNER, SUITE 1400
             HOUSTON, TEXAS                          77024
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)          (ZIP CODE)
</TABLE>

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

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

                                           NAME OF EACH EXCHANGE ON
         TITLE OF EACH CLASS                   WHICH REGISTERED
--------------------------------------------------------------------------
    COMMON STOCK, $0.01 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. ____

Aggregate market value of the voting stock held by non-affiliates of the
registrant as of March 1, 2000, was $1,355,700,000.

        Shares of common stock outstanding at March 1, 2000: 182,009,498

                      DOCUMENTS INCORPORATED BY REFERENCE:
                Proxy Statement Dated March 22, 2000 (Part III)

<PAGE>
                               TABLE OF CONTENTS

                                     PART I

                                                                            PAGE
                                                                            ----
Items  1. and 2.  Business and Properties                                      1
                  General                                                      1
                  Reserves                                                     2
                  Exploration and Production Activities                        2
                  Drilling Activities                                          8
                  Producing Wells                                              8
                  Domestic Acreage                                             9
                  Foreign Acreage                                              9
                  Santa Fe Energy Trust                                       10
                  Current Markets for Oil and Gas                             10
                  Risk Factors                                                11
                  Other Business Matters                                      13
Item  3.          Legal Proceedings                                           16
Item  4.          Submission of Matters to a Vote of Security Holders         16

                                    PART II

Item  5.          Market for Registrant's Common Equity and Related
                    Stockholder Matters                                       18
Item  6.          Selected Financial Data                                     19
Item  7.          Management's Discussion and Analysis of Financial
                    Condition and Results of Operations                       20
Item 7A.          Qualitative and Quantitative Disclosures
                    About Market Risks                                        26
Item  8.          Consolidated Financial Statements and Supplementary Data    28
Item  9.          Changes in and Disagreements with Accountants on
                    Accounting and Financial Disclosures                      28

                                    PART III

Item 10.          Directors and Executive Officers of the Registrant          29
Item 11.          Executive Compensation                                      29
Item 12.          Security Ownership of Certain Beneficial Owners and
                    Management                                                29
Item 13.          Certain Relationships and Related Transactions              29

                                    PART IV

Item 14.          Exhibits, Financial Statement Schedules and Reports
                    on Form 8-K                                               30
<PAGE>
                                     PART I

CERTAIN DEFINITIONS

As used herein, the following terms have specific meanings as set forth below:

Bbl                 barrel
MBbl                thousand barrels
MMBbl               million barrels
B/d                 barrels per day
Mcf                 thousand cubic feet
MMcf                million cubic feet
Bcf                 billion cubic feet
Tcf                 trillion cubic feet
MMBtu               million British thermal units
BOE                 barrel of oil equivalent, with gas volumes converted to oil
                    barrels at a ratio of 6.0 Mcf of gas to 1.0 barrel of oil
MBOE                thousand barrels of oil equivalent
MMBOE               million barrels of oil equivalent
MMcfe               million cubic feet of gas equivalent, with oil volumes
                    converted to Mcf at a ratio of 1.0 barrel of oil to 6.0 Mcf
                    of gas
CoFD                cost per BOE of reserves added during a year calculated by
                    using a fraction, of which the numerator is equal to the
                    costs incurred by the Company for property acquisition,
                    exploration and development and of which the denominator is
                    equal to proved reserve additions from extensions,
                    discoveries, improved recovery, acquisitions and revisions
                    of previous estimates
E&D Programs        capital expenditures and exploration costs, excluding proved
                    oil and gas property acquisitions and capitalized interest
Gas                 natural gas
Oil                 crude oil, condensate and natural gas
                    liquids
U.S.                United States

References herein to "Santa Fe Snyder", the "Company", "we", "us" and "our" mean
Santa Fe Snyder Corporation.

ITEMS 1 AND 2.  BUSINESS AND PROPERTIES

GENERAL

Santa Fe Snyder is engaged in the exploration, development, acquisition and
production of crude oil and natural gas in the U.S. and certain international
areas. Our U.S. core areas are in the Gulf of Mexico, the Permian Basin and the
Rocky Mountains and our international core areas are Southeast Asia and South
America. We also have oil production and conduct some exploration operations, in
West Africa.

Effective May 5, 1999, Snyder Oil Corporation ("Snyder Oil") was merged with
and into Santa Fe Energy Resources, Inc. ("Santa Fe Energy"), a Delaware
corporation, pursuant to an Agreement and Plan of Merger dated January 13, 1999
(the "Merger"). In connection with the Merger, Santa Fe Energy changed its
name to Santa Fe Snyder. The Merger was accounted for as a purchase, as
described in Note 2 to the Consolidated Financial Statements. See Item
7 -- Management's Discussion and Analysis of Financial Condition and Results of
Operations for a further discussion of the effects of the Merger on the
operations of the Company. As discussed in Note 3 to the Consolidated Financial
Statements, in July 1997 Santa Fe Energy completed the spin-off of Monterey
Resources, Inc. ("Monterey").

At December 31, 1999 our worldwide proved oil and gas reserves totaled 386.3
MMBOE, of which approximately 67% was domestic and 33% was foreign. Year-end
reserves were comprised of 210.8 MMBbls of oil (52% domestic) and 1,053.1 Bcf of
gas (85% domestic). In 1999, excluding the Merger, we replaced 337% of our
production at a CoFD of $4.93 per BOE (including the Merger, 589% at a

                                       1
<PAGE>
CoFD of $6.56 per BOE). In 1999, we participated in 118 development wells (74
domestic and 44 international) and 24 exploratory wells (19 domestic and 5
international), of which 113 development wells (71 domestic and 42
international) and 14 exploratory wells (13 domestic and 1 international) were
successful.

In 1999 E&D Program expenditures totaled $314 million and an additional $264
million was spent on acquisitions of proved oil and gas properties (excluding
those acquired in the Merger). Expenditures on E&D Programs in 2000 are expected
to be approximately $340 million and expenditures to acquire proved oil and gas
properties are expected to be approximately $230 million. The actual amounts
expended in 2000 and the results therefrom will be influenced by numerous
factors, many of which are beyond our control, and may vary significantly from
our plan.

RESERVES

The following tables set forth information regarding changes in the Company's
estimates of net proved reserves from January 1, 1997 to December 31, 1999 and
estimated net proved developed reserves at December 31 for each of the years
1996 through 1999.
<TABLE>
<CAPTION>
                                                  Increases (Decreases)
------------------------------------------------------------------------------------------------------------------------------------
                                                                                NET
                                                                             PURCHASES
                                                   REVISIONS                  (SALES)
                                     BALANCE AT        OF                       OF       SNYDER      SPIN                   BALANCE
                                      BEGINNING     PREVIOUS                 MINERALS      OIL      OFF OF                  AT END
                                      OF PERIOD    ESTIMATES    ADDITIONS    IN PLACE    MERGER    MONTEREY   PRODUCTION   OF PERIOD
<S>                                  <C>           <C>          <C>          <C>         <C>       <C>        <C>          <C>
------------------------------------------------------------------------------------------------------------------------------------
1999
Oil (MMBbls)                            168.6          9.1          13.8        19.0       17.7      --          (17.4)       210.8
Gas (Bcf)                               278.1         15.8         269.2       171.7      424.0      --         (105.7)     1,053.1
Oil equivalents (MMBOE)                 214.9         11.7          58.7        47.7       88.4      --          (35.1)       386.3
1998
Oil (MMBbls)                            129.0         (1.0)         33.8        21.6       --        --          (14.8)       168.6
Gas (Bcf)                               252.6         15.7          58.3        16.5       --        --          (65.0)       278.1
Oil equivalents (MMBOE)                 171.1          1.6          43.6        24.3       --        --          (25.7)       214.9
1997
Oil (MMBbls)                            299.5         11.2          35.5        10.3       --       (205.8)      (21.7)       129.0
Gas (Bcf)                               259.4         39.1          36.1        (6.0)      --        (11.6)      (64.4)       252.6
Oil equivalents (MMBOE)                 342.7         17.7          41.5         9.3       --       (207.7)      (32.4)       171.1

</TABLE>
<TABLE>
<CAPTION>
                                                      December 31,
---------------------------------------------------------------------------------
                                         1999       1998       1997       1996
---------------------------------------------------------------------------------
<S>                                    <C>        <C>        <C>        <C>

PROVED DEVELOPED RESERVES (MMBOE)          259.4      148.4      141.8      275.7
</TABLE>

Ryder Scott Company ("Ryder Scott"), a firm of independent petroleum
engineers, prepared the above estimates of total proved reserves at December 31,
1996, 1997 and 1999. Ryder Scott also prepared the above estimates of proved
reserves at December 31, 1998 with the exception of the reserves on the Jabung
Block in Southeast Asia, which were prepared by the Company.

EXPLORATION AND PRODUCTION ACTIVITIES

UNITED STATES OPERATIONS

The Company's U.S. operations are concentrated in the Gulf of Mexico, the
Permian Basin and the Rocky Mountains. U.S. production averaged 24.9 MBbls of
oil and 263.5 MMcf of gas per day in 1999. U.S. properties accounted for 72% of
total production in 1999 and 67% of proved reserves at December 31, 1999.

In 1999 we participated in 74 gross (47.4 net) domestic development wells, of
which 71 gross (45.1 net) wells were successful, and 19 gross (9.2 net) domestic
exploratory wells in 1999, of which 13 gross

                                       2
<PAGE>
(5.4 net) wells were successful. In 1999 expenditures on domestic E&D Programs
totaled $205 million and we expended an additional $263 million to acquire
proved oil and gas properties (excluding those acquired in the Merger). We
expect expenditures on domestic E&D Programs in 2000 to be approximately $200
million and, we expect to spend $180 million to acquire proved oil and gas
properties.

GULF OF MEXICO.  Our Gulf Coast area properties produced an average of 4.9 MBbls
of oil and 138.3 MMcf of gas per day in 1999. These properties accounted for 41%
of our domestic production in 1999 and 22% of our domestic proved reserves at
December 31, 1999. The majority of our Gulf Coast production comes from the
shallow water (less than 400 feet of water) areas of the Gulf of Mexico. At the
beginning of 1999 we had no production from deepwater areas; however, by
year-end those areas accounted for more than 10% of our Gulf Coast production.
This increase reflects the implementation of our strategy to reinvest in the
deepwater areas.

In July 1999 we increased our deepwater asset base by acquiring a portion of
Shell's working interest in the Angus (Green Canyon Blocks 111, 112, 113, 156
and 157 -- 15% working interest), El Toro (Green Canyon Blocks 68 and 69 -- 49%
working interest), Manatee (Green Canyon Block 15 -- 15% working interest) and
Macaroni (Garden Banks Blocks 602 and 646 -- 15% working interest) fields. The
Angus field is fully developed and on production and we expect the Macaroni
field to commence production in the first quarter of 2000. Development of the El
Toro and Manatee fields is expected to commence in 2000 and 2002, respectively.
In January 2000 we increased our working interest in the Angus and Manatee
fields to 48% with our purchase of Marathon's working interest in the fields.

In 1999 we participated in eight exploratory wells in the offshore Gulf of
Mexico, four in the shallower water Shelf and four in deepwater areas. Six of
the eight wells were discoveries, one well was dry, and the eighth well was
abandoned due to mechanical reasons prior to reaching the targeted objective.

In the Shelf program, three wells were successes and one well was dry. The
successful wells included the South Timbalier 186 #C-2 well that was completed
for a gross rate of 9.5 MMcf of gas and 472 barrels of oil per day and the West
Cameron 536 #A-10 well that is currently producing at a rate of 15 MMcf of gas
per day. We have a 100% working interest in both wells.

In the deepwater program, three wells were discoveries and one well was
abandoned due to mechanical problems. In February 1999, we drilled the Firebird
prospect in Mississippi Canyon Block 661 (25% working interest) and found 85
feet of net gas pay in two zones at approximately 10,200 feet. In December 1999
a second Firebird test found 47 net feet of gas pay at approximately 11,600
feet. Production casing has been set and both wells will be completed as a
subsea development.

In December 1999, we drilled the Gretchen Prospect (100% working interest) in
Green Canyon Block 114. The Gretchen well, drilled in 2,700 feet of water, found
approximately 40 feet of net gas pay at approximately 15,200 feet subsea
elevation. Subsea tieback options are being evaluated for producing this well.
At this time we do not anticipate production to commence prior to 2002. We are
evaluating additional exploratory opportunities on the Block.

An exploration well on the El Toro Deep Prospect, in Green Canyon Block 69, was
abandoned due to mechanical problems. The re-entry was abandoned at 11,450 feet
measured depth due to poor hole conditions. A new well to test this prospect
from a different location is planned for 2000. We have a 49% working interest in
El Toro Deep Prospect.

PERMIAN BASIN.  Properties in the Permian Basin of west Texas and southeastern
New Mexico produced an average of 17.8 MBbls of oil and 71.7 MMcf of gas per day
in 1999. These properties accounted for 43% of our domestic production in 1999
and 37% of our domestic proved reserves at December 31, 1999.

Long-lived properties in mature fields where we are engaged in development
activities through the use of secondary waterfloods and tertiary CO2 floods
accounted for approximately 65% of our Permian Basin oil production in 1999.
Waterfloods involve the injection of water into reservoirs to drive hydrocarbons
into producing wellbores. Following the waterflood phase, certain fields may
continue to produce in

                                       3
<PAGE>
response to tertiary projects such as the injection of CO2, which improves the
efficiency of the waterflood.

Development activities continued in Lea and Eddy Counties of southeastern New
Mexico with the drilling and completing of a total of 26 gross (12.9 net)
development wells in 1999. Net production from this area averaged 4.5 MBbls of
oil and 56.4 MMcf of gas per day in 1999. The most significant producing area in
southeast New Mexico is the Cisco-Canyon project at Indian Basin. Production
from this project, located in Eddy County, averaged 2.9 MBbls of oil and 33.8
MMcf of gas per day in 1999. We operate a major portion of the Cisco-Canyon
project area with an average working interest of 97% in the operated properties.
Development drilling will continue on the project in 2000.

The Lost Peak field, discovered in 1995 in Howard County, Texas, was actively
developed during 1999. We are the operator and hold an average 75% working
interest in this field which covers approximately 12,000 surface acres. Gas
production is from the Cisco formation at a depth of approximately 7,700 feet.
In 1999, we drilled 44 development wells and we have scheduled a similar number
to be drilled in 2000.

ROCKY MOUNTAINS.  The Rocky Mountain area properties, which consist almost
entirely of properties acquired in the Merger and 1999 proved property
acquisitions, produced an average of 2.2 MBbls of oil and 53.5 MMcf of gas per
day in 1999. These properties accounted for 16% of domestic production in 1999
and 41% of domestic proved reserves at December 31, 1999. The Rocky Mountain
producing properties are primarily low-permeability, long-lived gas properties
that offer significant infill drilling opportunities.

At year-end 1999 our properties in the Washakie Basin in southwest Wyoming
produced at a net rate of 63 MMcf of gas and 730 Bbls of oil per day. We
currently operate 229 wells in the Washakie Basin, holding a 77% average working
interest and 64% average net revenue interest. In the Mesaverde and Lewis
formations, we have identified a long-term inventory of drillable locations at
depths ranging from 8,000 to 11,500 feet. During 1999, 20 development wells were
drilled in the Washakie Basin (including wells drilled prior to the Merger), 19
of which were productive, and 32 development wells are planned for 2000.

At year-end 1999 our properties in the Wind River Basin in south-central Wyoming
produced at a net rate of 26 MMcf of gas and 600 Bbls of oil per day. We
currently operate 110 wells in the Wind River Basin, holding a 91% average
working interest and a 79% average net revenue interest. During 1999, we
substantially increased our ownership in the Beaver Creek Unit through
acquisitions and we are currently focusing our development efforts in the Wind
River Basin. During 1999, we completed 11 new wells and recompletions in the
Wind River Basin (including wells drilled prior to the Merger) and plan a
similar number in 2000.

In the Deep Green River Basin we purchased an undeveloped lease in the Jonah
field from the federal government and drilled two wells in late 1999. Drilled to
the Lance formation at approximately 10,000 (feet), the two wells were producing
at a net rate of 12 MMcf of gas per day at year-end 1999. We plan to drill two
more development wells to the Lance formation during 2000. In addition, we hold
the deep rights below the currently producing horizons at the Jonah field on
24,000 gross (10,000 net) acres.

INTERNATIONAL OPERATIONS

In 1999 our production from Indonesia, Argentina and Gabon averaged 22.8 MBbls
of oil and 26.2 MMcf of gas per day, a 14% increase from 1998 production levels.
International properties accounted for 28% of our total production in 1999 and
33% of our proved reserves at December 31, 1999.

In 1999 we participated in 44 gross (10.6 net) international development wells
of which 42 gross (10.0 net) wells were successful. In 1999 our expenditures on
international E&D Programs totaled $109 million. We expect to spend
approximately $140 million on international E&D Programs in 2000 and
approximately $50 million on the acquisition of proved oil and gas properties.
Our principal development projects in 2000 include the Jabung Block in
Indonesia, the Carauna project in Brazil, the El Mangrullo field in Argentina
and the continuing appraisal and development of Block 15/34 in China.

                                       4
<PAGE>
Our international exploration program is concentrated in Southeast Asia, South
America and, to a lesser extent, in West Africa. At year-end, we held interests
in 30 blocks in ten countries. During 1999, we participated in 5 gross (2.1 net)
international exploratory wells, of which 1 gross (.5 net) was successful. Our
international exploration expenditures totaled $32 million in 1999. We expect
these expenditures to increase to approximately $40 million in 2000.

SOUTHEAST ASIA

INDONESIA.  In 1999 our Indonesian production averaged 14.6 MBbls of oil per day
from four producing concessions. We sell our Indonesian oil production for U.S.
dollars to markets outside Indonesia, except for Jabung, which averaged 3.1
MBbls of oil per day in 1999 and is currently sold to the Indonesian state oil
agency ("Pertamina") for U.S. dollars.

We hold a 30% interest and operate the Jabung Block on the island of Sumatra
under the terms of a Production Sharing Contract ("PSC") with Pertamina.
Fields discovered on the block include the North Geragai field, the Makmur field
and the three-field Betara complex consisting of the Northeast Betara, North
Betara and Gemah fields. We have discovered both oil and gas in all these
fields. Oil production commenced from the North Geragai and Makmur fields in
August 1997 and January 1998, respectively, and net production from the two
fields at year-end 1999 was approximately 3.1 MBbls per day. Additional
development wells are planned in the North Geragai field in 2000. A second plan
of development that includes both the Betara complex as well as expansion of the
Geragai field was approved by Pertamina in January 2000. The plan initially
focuses on the development of liquids through the processing of gas, with
initial production scheduled to commence in late 2000. Development of the gas
reserves on the Jabung Block is dependent upon entering into sales contracts for
the gas. We have entered into letter agreements for gas sales and transportation
and are in final negotiations concerning a long-term gas sales contract.
Assuming successful conclusion of the negotiations in early 2000, gas sales
should commence in late 2002 from the Jabung Block. In 1999 we initiated a 185
square mile 3-D seismic program across the Betara and Gemah fields that will be
instrumental in identifying locations for development wells.

The Tuban Block is on the island of Java where a total of 12 successful wells
have been drilled through year-end 1999. Production from the block commenced in
December 1998 and our net production averaged 8.6 MBbls of oil per day in 1999.
Production rates from the field were reduced at year-end due to water influx on
some wells. Updated modeling indicates the need for additional wells to insure
maximum recovery from the field. Pending governmental approval of a revised plan
of development, five additional development wells are planned for 2000-2001. We
hold a 25% equity interest in the Block, which is jointly operated with
Pertamina (with a 50% interest) under the terms of a Joint Operating Body
contract ("JOB").

We operate two concessions in Irian Jaya, Indonesia's easternmost province,
which together produced a net average of 2.9 MBbls of oil per day in 1999. The
Salawati Basin concession, in which we hold a 33% participation interest, is
operated under a PSC with Pertamina. The other concession covers the Salawati
Island Block in which we hold a 17% participation interest and operate the block
jointly with Pertamina (which holds a 50% interest) under the terms of a JOB.

Under the contract terms at Salawati Basin and Tuban, the participants recover
all expenditures related to the operation (the "cost recovery amount") by
allocating to the participants a portion of the crude oil production ("cost
oil") priced at the Indonesian government official crude oil price ("ICP")
and/or proceeds from the sale of gas, sufficient to offset the cost recovery
amount. ICP is determined by the Indonesian government based on the average
market prices of a basket of world crude oil prices. All unrecovered costs in
any calendar year are carried forward to future years. The balance of production
after deducting the cost recovery amount (the "equity production") is
allocated to Pertamina and the participants. Oil equity production is allocated
66% to Pertamina at Salawati Basin and 71% to Pertamina at Tuban. After the
first five years of production, 25% of the oil equity production allocated to
the participants must be sold into the Indonesian domestic market for $0.20 per
barrel.

                                       5
<PAGE>
Under the contract terms at Salawati Island and Jabung, the joint venture
participants are allowed to recover the cost recovery amount, after an initial
20% (12% to Pertamina at Salawati Island and 14% to Pertamina at Jabung) has
been deducted, by allocating to the joint venture participants cost oil priced
at the ICP and/or proceeds from the sale of gas, sufficient to cover the cost
recovery amount. All unrecovered costs in any calendar year are carried forward
to future years. The equity production is allocated to Pertamina and the joint
venture participants. Oil equity production is allocated 61% to Pertamina at
Salawati Island and 71% to Pertamina at Jabung. Gas equity production is
allocated 33% to Pertamina at Jabung. After the first five years of production,
25% of the oil equity production allocated to the joint venture participants
must be sold into the Indonesian domestic market for 10% to 15% of ICP.

CHINA.  Our first operated well in offshore China, the Ursa Prospect Panyu 4-2-1
on Block 15/34 in the Pearl River Mouth Basin of the South China Sea, was
completed as a discovery in April 1998. Based on a 1,600 square mile 3-D survey
that was acquired across Block 15/34 in 1998, the Panyu 4-2-2 appraisal well
confirmed the discovery well in August 1999. In November 1999 a second discovery
well, the Bootes Prospect Panyu 5-1-1, was completed approximately 11 miles east
of the Panyu 4-2-1 well. Two intervals were tested at a combined rate of
approximately 3,800 barrels of oil per day. We expect to drill an appraisal well
to this discovery well in 2000. In 1999 we also participated in the drilling of
three exploratory wells on Block 15/34 that were not commercial. We hold a 50%
working interest in Block 15/34 and are the operator.

We are preparing a plan of development ("ODP") for the Ursa field and will
submit it to the Chinese National Offshore Oil Company ("CNOOC") in 2000.
Following the drilling of the appraisal well to the Bootes discovery, an ODP for
the Bootes field will be prepared and submitted to CNOOC. We currently expect to
develop the fields utilizing wellhead platforms with drilling capabilities and
producing to a floating production, storage and offloading vessel. Upon approval
of an ODP, CNOOC may elect to take a participatory interest in the exploitation
area of up to 51%.

We acquired four new blocks in the Pearl River Mouth Basin in 1999. Two blocks,
16/02 and 16/05, are new PSC exploration concessions with CNOOC. We obtained our
interests in Blocks 15/35 and 15/26 from another company. We hold a 100% working
interest in each of these contract areas and plan to commence exploration
drilling on these Blocks in 2000.

MALAYSIA.  Under a PSC covering offshore Block PM-308, we have work program
commitments, with respect to which we are required to pay 100% of the costs,
that include seismic acquisition and reprocessing and the drilling of three
wells. We fulfilled the seismic work commitment by acquiring new 2-D seismic and
reprocessing existing seismic data. The data has helped us to identify multiple
exploration prospects and better define the structure at the undeveloped Rhu
Field. A drilling program consisting of an exploratory well and a Rhu Field
delineation well is planned in 2000. We hold an 80% working interest in the
Block and are the operator.

THAILAND.  We have signed a concession agreement on Block B7/38 that covers
nearly 2.3 million acres off the East Coast of Thailand. We are planning to
acquire seismic data and to drill at least one exploratory well during the
three-year primary term of the agreement. We hold a 100% working interest in the
block and are the operator.

SOUTH AMERICA

ARGENTINA.  In 1999 our net production in Argentina averaged 5.2 MBbls of oil
and 26.0 MMcf of gas per day. Oil production primarily comes from our 22%
working interest in the El Tordillo field in the San Jorge Basin. Gas production
comes from our 19.9% working interest in the Sierra Chata field in the Neuquen
Basin.

Development activities in the El Tordillo field during 1999 included the
drilling of 36 gross (7.9 net) development wells in addition to performing well
workovers and waterflood expansion projects. In 2000 well workovers and some
waterflood and facility work will continue at El Tordillo.

                                       6
<PAGE>
With the use of a 3-D seismic survey, four wells were drilled in the Sierra
Chata field in 1999. All four were successful, testing at a combined gross rate
of 18 MMcf of gas per day. We have acquired an additional 116 square miles of
3-D seismic and expect to drill six additional wells in 2000 to further extend
the field and maintain deliverability. Production from the Sierra Chata field is
sold under a gas contract with certain "take-or-pay" and "delivery-or-pay"
obligations with a Buenos Aires gas distribution company and to the Chilean
market via the GasAndes Pipeline. We sell gas produced in excess of contract
requirements on the spot market.

In January 2000 we were the successful bidder to develop and operate the El
Mangrullo gas field, located 25 miles south of the Sierra Chata field. Our
development plans for the year 2000 include the drilling of two appraisal wells.

BRAZIL.  In December 1998 we entered into a contract with the Brazilian oil
company Petroleo Brasileiro S.A. ("Petrobras") to develop the Carauna Block in
the Potiguar Basin offshore Brazil. We operate the Block and hold a 51.4%
working interest. Petrobras has drilled ten productive wells that have
discovered six separate field areas on this Block. In 2000 we plan to re-enter
three of these wells, drill four new wells and install a system which will
produce to a floating storage and offloading vessel. We plan to commence first
production from the Block during the second quarter of 2000, and by the end of
that year net production is expected to be about 2 MBbls of oil per day. If the
field performs as expected, we expect to set permanent production facilities and
drill additional development wells in 2001.

In 1999 we participated in acquiring a 3-D seismic program on Block BES-3 in the
offshore Espirito Santo Basin, where we have a 19% non-operating interest. On
Block BPOT-2 in the offshore Potiguar Basin, where we are the operator and hold
a 51% working interest, a 143 mile 2-D seismic program was initiated to aid in
the selection of exploration drilling locations for both blocks.

WEST AFRICA

We have oil production on the Kowe Block, offshore Gabon, and hold exploratory
concessions in Gabon, the Congo, Cote d'Ivoire and Ghana. We are in the process
of evaluating our West African exploratory blocks and expect to reduce our
interests in these blocks.

GABON.  On the Kowe Block, offshore Gabon, oil production commenced from the
Tchatamba Marine field in January 1998 and from the Tchatamba South field in
August 1999. Kowe Block gross oil production averaged 27.5 MBbls per day (4.4
MBbls net per day) in December 1999. Production from the Tchatamba West field is
expected to commence in 2000.

Under the terms of the Kowe Block PSC the Gabonese government may elect to take
a 25% participatory interest in any exploitation area. If the Gabonese
government elects to participate, it may designate the company that will hold
such interest and we and our partners receive reimbursement for certain capital
expenditures. We hold an 18.75% participatory interest in the exploitation
license area covering the Tchatamba Marine and Tchatamba South fields (after
taking into account the Gabonese government's election to participate). The
Gabonese government is expected to elect to take a participatory interest in the
exploitation license area covering the Tchatamba West field when the field is
placed on production. We have a 25% participatory interest in the Block's
exploration area.

We have signed an exploration contract on the M-97 Agali Block located offshore
Gabon. The Block covers nearly 1.1 million acres in water depths that range from
600 to 9,000 feet. We plan to acquire new data and to drill at least one
exploratory well during the three-year primary term of the agreement. We hold
100% of the working interest in the block and are the operator.

CONGO.  The Company farmed-in Marine Block IX, which contains an untested
prospect covering in excess of 6,500 acres. We plan to drill the prospect in
2001. We hold an 85% interest in this block and are the operator.

COTE D'IVOIRE. The Company holds 100% working interests and operates two blocks,
CI-24 and CI-202, offshore Cote d'Ivoire, which cover approximately 320,000
acres. In 2000 we plan to drill a well on Block CI-202.

                                       7
<PAGE>
GHANA.  The Keta Block encompasses an offshore area of approximately 2.2 million
acres in water depths that range from near-shore to 9,000 feet. In 2000 we plan
to drill a well in approximately 1,300 feet of water. We hold 100% of the
working interest in the block and are the operator.

DRILLING ACTIVITIES

The table below sets forth, for the periods indicated, the number of wells
drilled in which we had an economic interest. As of December 31, 1999, wells in
the process of drilling or completing included 6 gross (3.7 net) domestic
exploratory wells, 33 gross (24.0 net) domestic development wells, 1 gross (0.3
net) foreign exploratory well and 7 gross (1.9 net) foreign development wells.
<TABLE>
<CAPTION>
                                                     Year Ended December 31,
------------------------------------------------------------------------------------------
                                             1999              1998              1997
------------------------------------------------------------------------------------------
                                        GROSS     NET     GROSS     NET     GROSS     NET
------------------------------------------------------------------------------------------
<S>                                     <C>      <C>      <C>      <C>      <C>      <C>
Development Wells
  Domestic
     Gas                                  40      24.4      25       9.0      22       9.8
     Oil                                  31      20.7      21      16.0     218     184.2
     Dry                                   3       2.3       1        .1       8       4.2
  Foreign
     Gas                                   6       1.4      15       3.8       2        .4
     Oil                                  36       8.6      44      15.1      41       9.6
     Dry                                   2        .6       2        .6       2        .6
                                        -----    -----    -----    -----    -----    -----
                                         118      58.0     108      44.6     293     208.8
                                        -----    -----    -----    -----    -----    -----
Exploratory Wells
  Domestic
     Gas                                   9       4.1       8       3.4       9       2.9
     Oil                                   4       1.3       2        .6       7       3.4
     Dry                                   6       3.8      17       6.1      21       7.5
  Foreign
     Gas                                 --       --         2        .7     --       --
     Oil                                   1        .5       7       2.2       1        .3
     Dry                                   4       1.6      18       8.2       5       1.8
                                        -----    -----    -----    -----    -----    -----
                                          24      11.3      54      21.2      43      15.9
                                        -----    -----    -----    -----    -----    -----
                                         142      69.3     162      65.8     336     224.7
                                        =====    =====    =====    =====    =====    =====
</TABLE>
PRODUCING WELLS

The following table sets forth our ownership in producing wells at December 31,
1999.
<TABLE>
<CAPTION>
                                                           Southeast
                                          U.S. (a)         Asia (b)      South America   West Africa        Total
----------------------------------------------------------------------------------------------------------------------
                                       GROSS     NET     GROSS    NET    GROSS    NET    GROSS   NET   GROSS     NET
<S>                                    <C>      <C>      <C>     <C>     <C>     <C>     <C>     <C>   <C>     <C>
----------------------------------------------------------------------------------------------------------------------
Oil                                     9,398   1,253.2   412    129.4    453    132.0      8    1.8   10,271  1,516.4
Gas                                     1,486    743.7     16      5.3     28      5.6    --     --     1,530    754.6
                                       ------   ------   -----   -----   -----   -----   -----   ---   ------  -------
                                       10,884   1,996.9   428    134.7    481    137.6      8    1.8   11,801  2,271.0
                                       ======   ======   =====   =====   =====   =====   =====   ===   ======  =======
</TABLE>
------------

(a) Includes 74 gross wells with multiple completions.

(b) Includes 4 gross wells with multiple completions.

                                       8
<PAGE>
DOMESTIC ACREAGE

The following table summarizes our developed and undeveloped fee and leasehold
acreage holdings in the U.S. at December 31, 1999. Acreage in which ownership
interest is limited to royalty, overriding royalty and other similar interests
is excluded.
<TABLE>
<CAPTION>
                                            Undeveloped             Developed
-----------------------------------------------------------------------------------
                                         GROSS        NET        GROSS       NET
-----------------------------------------------------------------------------------
                                                        (in acres)
<S>                                    <C>         <C>         <C>        <C>
Alabama-offshore                           23,040       7,440      8,210      6,921
Alabama-onshore                            --          --            823        112
Arkansas                                  136,931      82,804        822        186
California                                 --          --             40         40
Colorado                                    1,233       1,089      5,932      5,248
Kansas                                         34          34      3,293        737
Louisiana-offshore                        355,913     199,010    221,694     87,055
Louisiana-onshore                         442,473     308,845     32,824     18,467
Michigan                                   35,980      18,364     --         --
Mississippi                                   279          83      2,639        440
Montana                                    12,400       3,023        635         32
New Mexico                                149,291      94,647     69,587     36,403
North Dakota                                7,391       6,278      3,964      1,149
Oklahoma                                    5,170       5,052     20,198      7,771
South Dakota                                  223         223     --         --
Texas-offshore                            128,532      82,145     33,732     12,326
Texas-onshore                             125,672     101,277    209,244    147,612
Utah                                          324         324      2,608      1,373
Wyoming                                   444,040     306,604    183,441    134,783
                                       ----------  ----------  ---------  ---------
                                        1,868,926   1,217,242    799,686    460,655
                                       ==========  ==========  =========  =========
Total offshore                            507,485     288,595    263,636    106,302
                                       ==========  ==========  =========  =========
</TABLE>

FOREIGN ACREAGE

The following table summarizes our foreign acreage holdings at December 31,
1999.
<TABLE>
<CAPTION>
                                           Undeveloped            Developed
---------------------------------------------------------------------------------
                                         GROSS       NET       GROSS       NET
---------------------------------------------------------------------------------
                                                  (thousands of acres)
<S>                                    <C>        <C>        <C>        <C>
Southeast Asia
     China                                 3,861      3,202     --         --
     Indonesia                             5,989      2,192         18          4
     Malaysia                              3,494      2,795     --         --
     Thailand                              2,294      2,294     --         --
South America
     Argentina                             1,186        330        201         46
     Brazil                                  570        176         47         24
West Africa
     Congo                                   207        155     --         --
     Cote d'Ivoire                           315        312     --         --
     Gabon                                 1,052      1,025         13          3
     Ghana                                 2,222      2,222     --         --
                                       ---------  ---------  ---------  ---------
                                          21,190     14,703        279         77
                                       =========  =========  =========  =========
</TABLE>
                                       9
<PAGE>
SANTA FE ENERGY TRUST

The Santa Fe Energy Trust (the "Trust") was formed in 1992 to hold 6,300,000
Depository Units ("Depository Units"), each consisting of beneficial ownership
of one unit of undivided interest in the Trust and a $20 face amount beneficial
ownership interest in a $1,000 face amount zero coupon United States Treasury
obligation maturing on or about February 15, 2008. The Trust will be liquidated
on February 15, 2008. The assets of the Trust consist of certain oil and gas
properties conveyed by the Company.

The properties conveyed to the Trust consisted of two term royalty interests in
two production units in the Wasson field in West Texas and a net profits royalty
interest in certain royalty and working interests in a diversified portfolio of
properties located in twelve states. At December 31, 1999, 3.6 MMBOE of our
estimated proved reserves were subject to such net profits interest. The reserve
estimates included herein reflect the conveyance of the Wasson term royalties to
the Trust.

For any calendar quarter ending on or prior to December 31, 2002, the Trust will
receive support payments to the extent that such payments are required to
provide distributions of $0.39 per Depository Unit per quarter or $2.46 million
in the aggregate. Such support payments come from our remaining royalty interest
in one of the production units in the Wasson field described above, and are
non-recourse to the Company. The aggregate amount of the support payments (net
of any amounts recouped) is limited to $19.4 million on a revolving basis. If
such additional payments are made, certain proceeds otherwise payable to the
Trust in subsequent quarters may be reduced to recoup the amount of such
payments. Through the end of 1999, the Trust had received support payments
totalling $4.2 million and we had recouped $3.9 million of such payments. In the
first quarter of 2000 we recouped the remaining $0.3 million of support
payments. Depending on various factors, such as sales volumes and prices and the
level of operating costs and capital expenditures incurred, proceeds payable to
the Trust with respect to operations in subsequent quarters may not be
sufficient to make the required quarterly distributions. In such instances we
would be required to make support payments.

CURRENT MARKETS FOR OIL AND GAS

Substantially all of the Company's oil and gas production is sold for U.S.
dollars at market responsive prices. The revenues generated from our operations
are highly dependent upon the prices of, and demand for, oil and gas. The price
we receive depends upon numerous factors, the majority of which are beyond our
control, including economic conditions in the U.S. and elsewhere, the world
political situation as it affects OPEC and other producing countries, the
actions of OPEC and governmental regulation. The fluctuation in world oil prices
continues to reflect market uncertainty regarding the balance of world demand
for and supply of oil and gas. The fluctuation of natural gas prices reflects
the seasonal swings of storage inventory, weather conditions, and increasing
utilization of natural gas for electric generation as they affect overall
demand. Decreases in the prices of oil and gas have had, and could have in the
future, a material adverse effect on our development and exploration programs,
proved reserves, revenues, profitability and cash flow. See Item
7A -- Qualitative and Quantative Disclosures About Market Risks.

In Argentina, we market oil for U.S. dollars under market responsive terms.
Production from the El Tordillo field is generally exported from Argentina.
Production from the Tupungato field is sold under a long-term contract to a
local refinery under market responsive terms. Gas from the Sierra Chata field is
sold under a gas contract with certain "take-or-pay" and "delivery-or-pay"
obligations with a Buenos Aires gas distribution company and to the Chilean
Market via the GasAndes Pipeline for prices ranging between $1.15 and $1.35 per
MMBtu. Gas production in excess of the contract requirements is sold on the
local spot market.

We sell our Indonesian oil production for U.S. dollars to markets outside of
Indonesia except for Jabung which we currently sell to the Indonesian state oil
agency for U.S. dollars. Gabonese oil production is sold for U.S. dollars into
the international markets.

                                       10
<PAGE>
We do not believe that the loss of any of our customers would have a material
adverse effect on our operations. Periodically we hedge a portion of our oil and
gas production to manage our exposure to volatility in prices of oil and natural
gas. See Item 7A -- Qualitative and Quantitive Disclosures About Market Risk and
Note 14 to the Consolidated Financial Statements.

RISK FACTORS AND CAUTIONARY STATEMENT FOR PURPOSES OF THE SAFE HARBOR PROVISIONS
OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This report contains or incorporates by reference 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,"
"estimates," "intends" or "projects" and similar expressions are intended
to identify forward-looking statements. Where any forward-looking statement
includes a statement of the assumptions or bases underlying such forward-looking
statement, we caution that while we believe these assumptions or bases to be
reasonable and to be made in good faith, assumed facts or bases almost always
vary from actual results and the difference between assumed facts or bases and
actual results could be material, depending on the circumstances. It is
important to note that our actual results could differ materially from those
projected by such forward-looking statements. Although we believe 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, we cannot
assure you that such expectations will prove correct. Factors that could cause
our 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,
hedging results, the need to develop and replace reserves, the substantial
capital expenditures required to fund operations, exploration risks,
environmental risks, uncertainties about estimates of reserves, competition,
litigation, government regulation, political risks, and our ability to implement
our business strategy. All such forward-looking statements in this document are
expressly qualified in their entirety by the cautionary statements in this
paragraph.

With the foregoing in mind, you should consider the following important factors
that could cause actual results to differ materially from those expressed in any
forward-looking statement made by us or on our behalf.

OIL AND GAS PRICES ARE VOLATILE, WHICH CAN ADVERSELY AFFECT CASH FLOW AVAILABLE
FOR REINVESTMENT AND OUR HEDGING ACTIVITIES EXPOSE US TO CERTAIN RISKS

Prices for oil and gas have historically been volatile and during the latter
part of 1998 and the early part of 1999 prices were significantly lower than
those we are currently receiving. As a result, in those periods we reported
substantial losses. Decreases in oil and gas prices from current levels will
adversely affect our revenues, results of operations, cash flows and proved
reserves. If the industry experiences significant prolonged future price
decreases they could be materially adverse to our operations and could result in
our inability to fund planned capital expenditures.

Periodically, we enter into hedging arrangements relating to a portion of our
oil and gas production to achieve a more predictable cash flow, as well as to
reduce our exposure to adverse price fluctuations of oil and gas. Hedging
instruments used are fixed price swaps, collars and options. While the use of
these types of hedging instruments limits our downside risk to adverse price
movements, they are subject to a number of risks, including instances in which
the benefit to revenues is limited when commodity prices increase.

For a further discussion concerning our risks related to oil and gas prices and
our hedging programs, see Item 7A -- Qualitative and Quantitative Disclosures
About Market Risks.

                                       11
<PAGE>
ESTIMATES OF OUR OIL AND GAS RESERVES MAY CHANGE, WE MAY NOT BE ABLE TO REPLACE
OUR RESERVES

The calculations of our proved oil and gas reserves included in this document
are only estimates. The accuracy of any reserve estimate is a function of the
quality of available data and engineering and geological interpretation and
judgment and the assumptions used regarding quantities of recoverable oil and
gas reserves and prices for oil and gas. Actual prices, production, development
expenditures, operating expenses and quantities of recoverable oil and gas
reserves will vary from those assumed in our estimates, and such variances may
be significant. Any significant variance from the assumptions used could result
in the actual quantity of our reserves and future net cash flow being materially
different from the estimates in our reserve reports. In addition, results of
drilling, testing and production and changes in oil and gas prices after the
date of the estimate may result in substantial upward or downward revisions.

Without successful exploration, development or acquisition activities, our
reserves and revenues will decline over time. Exploration, the continuing
development of our reserves and acquisition activities will require significant
expenditures. If our cash flow from operations is not sufficient for this
purpose, we may not be able to obtain the funds from other sources necessary to
continue such exploration, development and acquisition activities.

OUR FOREIGN ACTIVITIES ARE SUBJECT TO CERTAIN POLITICAL AND ECONOMIC
UNCERTAINTIES

We conduct a significant part of our operations in foreign countries and these
operations expose us to political, economic and other risks including:

  o  the risk of war, revolution, civil unrest, border disputes, expropriation,
     forced renegotiation or modification of existing contracts, import, export
     and transportation regulations and tariffs;

  o  taxation policies, including royalty and tax increases and retroactive tax
     claims;

  o  exchange controls, currency fluctuations and other uncertainties arising
     out of foreign government sovereignty over our international operations;

  o  laws and policies of the United States affecting foreign trade, taxation
     and investment; and

  o  the possibility of having to be subject to the exclusive jurisdiction of
     foreign courts in connection with legal disputes and the possible inability
     to subject foreign persons to the jurisdiction of courts in the U.S.

WE MAY HAVE WRITEDOWNS OF OIL AND GAS PROPERTIES' CARRYING VALUE

Accounting rules require that we review periodically the carrying value of our
oil and gas properties for possible impairment. Based on specific market factors
and circumstances at the time of prospective impairment reviews, and the
continuing evaluation of development plans, production data, economics and other
factors, we may be required to write down the carrying value of our oil and gas
properties. A writedown constitutes a charge to earnings, which does not impact
our cash flow from operating activities.

Based primarily on our long-term outlook for future commodities prices, we
recorded impairment charges of $196.4 million in the second quarter of 1999 and
$87.8 million in the fourth quarter of 1998. For a further discussion of our
accounting policies with respect to oil and gas properties, see Note 1 to the
Consolidated Financial Statements.

WE COULD INCUR SUBSTANTIAL ENVIRONMENTAL LIABILITIES

We may incur significant costs and liabilities in order to comply with existing
and future environmental laws and regulations. It is also possible that other
developments, such as increasingly strict environmental laws, regulations and
enforcement policies thereunder, and claims for damages to property, employees,
other persons and the environment resulting from current or discontinued
operations, could result in substantial costs and liabilities in the future. For
additional information concerning our environmental matters, see Other Business
Matters -- Environmental Regulation.

                                       12
<PAGE>
OUR ACTIVITIES INVOLVE OPERATING HAZARDS AND UNINSURED RISKS

While we maintain insurance against certain of the risks normally associated
with our operations, including, but not limited to explosions, pollution and
fires, the occurrence of a significant event against which we are not fully
insured could have a significant negative effect on our business.

WE ARE SUBJECT TO FINANCING AND INTEREST RATE EXPOSURE RISKS

Our business and operating results can be harmed by factors such as the
availability or cost of capital, changes in interest rates, changes in the tax
rates due to new tax laws, market perceptions of the oil and gas industry or the
Company, or any reduction in our credit ratings.

OTHER BUSINESS MATTERS

WE FACE STIFF COMPETITION

We face competition in all aspects of our business, including, but not limited
to, acquiring reserves, leases, licenses and concessions; obtaining goods,
services and labor needed to conduct operations and manage the Company; and
marketing oil and gas. Our competitors include multinational energy companies,
government-owned oil and gas companies, other independent producers and
individual producers and operators. Many of our competitors have greater
financial and other resources than the Company.

CRUDE OIL AND NATURAL GAS ARE SUBJECT TO EXTENSIVE REGULATION

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

Set forth below is a general description of certain state and federal
regulations that affect our operations.

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

In addition to regulatory oil and gas production, numerous states have
implemented statutory and regulatory initiatives requiring local distribution
companies ("LDCs") to develop (to various degrees) unbundled transportation
and related service options and rates. Typically, these programs are designed to
allow the LDCs' commercial, industrial, and, with increasing frequency,
residential customers to have access to transportation service on the LDC,
coupled with an ability to select third-party city-gate gas suppliers.
Similarly, several states are also addressing the unbundling of the retail
electric markets, ranging from the consideration of initial unbundling proposals
to permitting, in varying degrees, the implementation of programs allowing
direct retail access. These developments have already led a number of industry
participants to redirect significant marketing resources to these emerging
energy markets.

                                       13
<PAGE>
FEDERAL REGULATION.  A portion of our oil and gas leases are granted by the
federal government and administered by the Bureau of Land Management ("BLM")
and the Minerals Management Service ("MMS"), both of which are federal
agencies. Such leases are issued through competitive bidding, contain relatively
standardized terms and require compliance with detailed BLM and MMS regulations
and orders (which are subject to change by the BLM and the MMS). For offshore
operations, lessees must obtain MMS approval for exploration plans and
development and production plans prior to the commencement of such operations.
In addition to permits required from other agencies (such as the Coast Guard,
Army Corps of Engineers and Environmental Protection Agency), lessees must
obtain a permit from the BLM or the MMS prior to the commencement of drilling.

The interstate transportation and sale for resale of gas are regulated by the
Federal Energy Regulatory Commission ("FERC"). Commencing in 1985 and
continuing with the issuance of Order No. 636 in 1992, the FERC promulgated a
series of orders and regulations that significantly fostered competition in the
business of transporting and marketing gas. These orders and regulations
induced, and ultimately required, interstate pipeline companies to provide
nondiscriminatory transportation services to producers, marketers, and other
shippers, regardless of whether shippers were affiliated with an interstate
pipeline company. The FERC's initiatives have led to the development of a
competitive, unregulated, open access market for gas purchases and sales that
permits all purchasers of gas to buy gas directly from third-party sellers other
than the pipelines.

On February 9, 2000, the FERC issued Order No. 637, which permits, and in some
cases, requires, interstate gas pipelines to make certain changes to the nature
of interstate transportation services. We do not expect to experience any
adverse material effect as a result of these changes, although the full impact
of Order No. 637 on our performance cannot be determined at this time. The
changes permitted or required by Order No. 637 attempt to continue the
development of competitive gas markets under the open access regime created by
Order No. 636. These changes include, INTER ALIA: (1) elimination, for a
two-year period, of the rate cap that applies to sales of released firm
transportation capacity by pipelines' firm shippers; (2) the adoption by
pipelines of seasonal or term-differentiated rates; (3) revisions to pipeline
scheduling procedures that are designed to put capacity released by firm
shippers on a more equal footing with capacity sales by pipelines; and (4)
additional reporting requirements that seek to increase the ability of the FERC
and interested parties to monitor the actions of pipelines and firm capacity
holders and detect attempts market power or to engage in unduly discriminatory
conduct.

FERC's regulation of electric transmission facilities may also have a
significant impact on the natural gas industry. In 1996, FERC's issuance of
Order Nos. 888 and 889 resulted in the unbundling of the wholesale electric
industry and the initiation of open-access electric transmission. Moreover, in
its recently issued Order No. 2000, FERC again expressed its continued
commitment to the development of the wholesale transmission market, this time
through the creation of Regional Transmission Organizations. These developments
represent an evolution in Open-Access transmission and are intended to
facilitate a more robust wholesale electric market. Today, as utilities search
for new sources of competitively-priced generation, numerous new generation
facilities are either planned or already being constructed. Many of these new
facilities are gas-fired, leading to a recent trend in the construction of new
pipelines and the expansion of existing ones.

ENVIRONMENTAL REGULATION

Various federal, state and local laws and regulations covering the discharge of
materials into the environment, or otherwise relating to the protection of the
environment, may affect our operations and costs. In particular, our oil and gas
exploration, development, production and secondary and tertiary recovery
operations, activities in connection with storage and transportation of liquid
hydrocarbons and use of facilities for treating, processing, recovering or
otherwise handling hydrocarbons and wastes therefrom are subject to stringent
environmental regulation by governmental authorities. Such regulation has
increased the cost of planning, designing, drilling, installing, operating and
abandoning oil and gas wells and other facilities. We have expended significant
resources, both financial and managerial, to comply with environmental
regulations and permitting requirements and anticipate that we will continue

                                       14
<PAGE>
to do so in the future in order to comply with increasingly stricter industry
and regulatory safety standards such as those described below. Although we
believe our operations and facilities are in general compliance with applicable
environmental regulations, risks of substantial costs and liabilities are
inherent in oil and gas operations and we cannot assure you that we will not
incur significant costs and liabilities in the future. It is also possible that
other developments, such as increasingly strict environmental laws, regulations
and enforcement policies thereunder, and claims for damages to property,
employees, other persons and the environment resulting from our operations,
could result in substantial costs and liabilities in the future. Although the
resulting costs cannot be accurately estimated at this time, these requirements
and risks typically apply to companies with types, quantities and locations of
production similar to ours and to the oil and gas industry in general.

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

SUPERFUND.  The Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA"), also known as the "Superfund" law, imposes liability,
without regard to fault or the legality of the original conduct, on certain
classes of persons that contributed to the release of a "hazardous substance"
into the environment. These persons include the owner or operator of a site and
companies that disposed or arranged for the disposal of the hazardous substance
found at a site. CERCLA also authorizes the EPA and, in some cases, third
parties to take actions in response to threats to the public health or the
environment and to seek to recover from the responsible classes of persons the
costs they incur. In the course of our operations, we have generated and will
generate wastes that may fall within CERCLA's definition of "hazardous
substances". We 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 us or our predecessors have been investigated under state and Federal
Superfund statutes, and we have been and could be named a potentially
responsible party ("PRP") for the cleanup of some of these sites.

Monterey agreed to indemnify and hold harmless the Company from and against any
costs incurred in the future relating to environmental liabilities in respect to
any property or interest located in California and formerly owned or operated by
the former Western Division or its predecessors.

AIR EMISSIONS.  Our operations are subject to local, state and federal
regulations for the control of emissions from sources of air pollution. Legal
and regulatory requirements in this area are increasing, and there can be no
assurance that significant costs and liabilities will not be incurred in the
future as a result of new regulatory developments. In particular, the 1990 Clean
Air Act Amendments impose additional requirements that may affect operations,
including permitting of existing sources and control of hazardous air
pollutants. We have been and may in the future be subject to administrative
enforcement actions for failure to comply strictly with air regulations or
permits. These administrative actions are generally resolved by payment of a
monetary penalty and correction of any identified deficiencies. Alternatively,
regulatory agencies may require us to forego construction or operation of
certain air emission sources.

OTHER.  We are 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 us to organize information about hazardous materials used or
produced in our operations. Certain of this information must be provided to
employees, state and local governmental authorities and local citizens.

                                       15
<PAGE>
Although generally less stringent, our foreign operations are subject to similar
foreign laws respecting environmental and worker safety matters.

INSURANCE COVERAGE MAINTAINED WITH RESPECT TO OPERATIONS

We maintain insurance policies covering our operations in amounts and areas of
coverage normal for a company of our size in the oil and gas exploration and
production industry. These include, but are not limited to, workers'
compensation, employers' liability, automotive liability and general liability.
In addition, umbrella liability and operator's extra expense policies are
maintained. All such insurance is subject to normal deductible levels. We do not
insure against all risks associated with our business either because insurance
is not available or because we have elected not to insure due to prohibitive
premium costs.

EMPLOYEES

At December 31, 1999, we had 1,408 total employees, including 865 foreign
nationals working in Indonesia and Argentina. We believe that our relations with
our employees are satisfactory.

ITEM 3.  LEGAL PROCEEDINGS

The Company, its subsidiaries and other related companies are named defendants
in several lawsuits and named parties in certain governmental proceedings
arising in the ordinary course of business. While the outcome of such lawsuits
or other proceedings cannot be predicted with certainty, in the opinion of
management, the amounts, if any, which may be awarded in connection with any of
these claims and actions could be significant to the results of operations and
cash flows of any period, but would not be material to our consolidated
financial position.

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

No matters were submitted to a vote of shareholders in the fourth quarter of
1999.

EXECUTIVE OFFICERS OF SANTA FE SNYDER

Listed below are the names, ages (as of February 1, 2000) and positions of all
executive officers of Santa Fe Snyder (excluding executive officers who are also
directors of Santa Fe Snyder, who are described in our proxy statement) and
their business experience during the past five years. Each executive officer
holds office until his or her successor is elected or appointed or until his or
her earlier death, resignation or removal.

     HUGH L. BOYT, 54  President -- International since May 5, 1999. From April
     1998 until May 1999, Mr. Boyt served as President and Chief Operating
     Officer. From March 1990 until April 1998, Mr. Boyt served as Senior Vice
     President -- Production.

     WILLIAM G. HARGETT, 50  President -- North America since May 5, 1999. From
     April 1997 until May 1999, Mr. Hargett served as President and Chief
     Operating Officer of Snyder Oil. From September 1994 until April 1997, Mr.
     Hargett served as President of Greenhill Petroleum Corporation.

     JANET F. CLARK, 45  Executive Vice President -- Corporate
     Development/Administration since May 5, 1999. From March 1998 until May
     1999, Ms. Clark served as Senior Vice President, Chief Financial Officer
     and Treasurer. From January 1997 until March 1998, Ms. Clark served as Vice
     President and Chief Financial Officer. Ms. Clark was with Southcoast
     Capital Corporation from January 1994 until she joined Santa Fe. While with
     Southcoast Capital, Ms. Clark served as Vice President from January 1994 to
     June 1996 and as Director, Corporate Finance, from June 1996 to December
     1996.

     MARK A. JACKSON, 45  Executive Vice President and Chief Financial Officer
     since May 5, 1999. From August 1997 until May 1999 Mr. Jackson served as
     Senior Vice President and Chief Financial Officer of Snyder Oil. Prior to
     joining Snyder Oil Mr. Jackson was with Apache Corporation from 1988 until
     August 1997 and held various positions including Vice President,

                                       16
<PAGE>
     Finance from May 1994 until March 1996 and Vice President and Chief
     Financial Officer from March 1996 until August 1997.

     TIMOTHY S. PARKER, 47  Executive Vice President -- Exploration since May 5,
     1999. From January 1999 until May 1999, Mr. Parker served as Senior Vice
     President -- Exploration and Land. From April 1998 until January 1999, Mr.
     Parker served as Vice President -- Exploration and from September 1995
     until April 1998 he served as Division Exploration Manager, International.
     Mr. Parker served as Corporate Exploration Manager from May 1994 until
     September 1995 and from 1988 until May 1994 he served as Division Manager,
     Exploration.

     DUANE C. RADTKE, 51  Executive Vice President -- Production since May 5,
     1999. From April 1998 until May 1999, Mr. Radke served as Senior Vice
     President -- Production. From July 1993 to April 1998, Mr. Radtke served as
     President -- Santa Fe Energy Resources, Inc. Southeast Asia Companies.

     DAVID L. HICKS, 50  Vice President -- Law and General Counsel since March
     1991.

                                       17

<PAGE>
                                    PART II

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

Santa Fe Snyder common stock is listed for trading on the New York Stock
Exchange and trades under the symbol SFS. The following table sets forth
information as to the closing sales price per share of our common stock as
quoted on the Consolidated Tape System of the New York Stock Exchange for each
calendar quarter in 1999 and 1998.
<TABLE>
<CAPTION>
                                           Price Range
-----------------------------------------------------------
                                         HIGH        LOW
-----------------------------------------------------------
                                           (in dollars)
<S>                                    <C>        <C>
1999
     First Quarter                        7.6250     4.8750
     Second Quarter                       9.3125     6.5625
     Third Quarter                       10.5625     8.1250
     Fourth Quarter                       9.3125     6.8125
1998
     First Quarter                        11.687      8.812
     Second Quarter                       11.562      9.375
     Third Quarter                        11.000      6.844
     Fourth Quarter                        9.187      5.375
</TABLE>

Except for the distribution of shares of Monterey common stock in July 1997, we
have not paid dividends on common stock since the third quarter of 1993. The
determination of the amount of future cash dividends, if any, to be declared and
paid is in the sole discretion of our Board of Directors and will depend on our
financial condition, earnings and funds from operations, the level of capital
and exploration expenditures, dividend restrictions in financing agreements,
future business prospects and other matters as our Board of Directors deems
relevant. For a discussion of certain restrictions on our ability to pay
dividends, see Item 7 -- Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity and Capital Resources and Note
9 to the Consolidated Financial Statements.

At December 31, 1999 we had approximately 28,600 shareholders of record.

                                       18
<PAGE>
ITEM 6.  SELECTED FINANCIAL DATA

SELECTED FINANCIAL DATA

(IN MILLIONS OF DOLLARS, EXCEPT AS NOTED)
<TABLE>
<CAPTION>
                                                      Year Ended December 31,
--------------------------------------------------------------------------------------------
                                         1999       1998       1997       1996       1995
--------------------------------------------------------------------------------------------
<S>                                    <C>        <C>        <C>        <C>        <C>
INCOME STATEMENT DATA
  Revenues(a)                              510.3      290.7      514.1      582.3      447.8
  Impairment of oil and gas
     properties                            196.4       87.8     --           57.4       30.2
  Merger related costs                      16.8     --         --         --         --
  Income (loss) from operations           (128.8)    (154.3)     110.2       88.5       52.3
  Income (loss) before extraordinary
     items                                (120.7)     (98.7)      54.7       42.4       26.6
  Extraordinary items -- debt
     extinguishment costs                   (4.2)    --         --           (6.0)    --
  Net income (loss)                       (124.9)     (98.7)      54.7       36.4       26.6
  Earnings (loss) attributable to
     common shares                        (124.9)     (98.7)      42.7      (10.8)      11.8
  Basic and diluted per share data
     (in dollars)
       Before extraordinary item            (.79)      (.96)       .43       (.05)       .13
       Extraordinary item -- debt
          extinguishment costs              (.03)    --         --           (.07)    --
       Per common share                     (.82)      (.96)       .43       (.12)       .13
  Weighted average shares outstanding
     (in millions)                         152.9      102.6       98.6       90.6       90.2
BALANCE SHEET DATA (AT PERIOD END)
  Properties and equipment, net(a)       1,657.1      718.3      649.7      909.8      889.5
  Total assets(a)                        1,862.8      859.0      788.9    1,129.1    1,073.8
  Long-term debt                           629.4      330.6      121.7      278.5      344.4
  Convertible preferred stock             --         --         --           19.7       80.0
  Shareholders' equity                     741.2      348.4      454.7      526.8      437.7
</TABLE>
------------

(a) The increase in 1999 in revenues, properties and equipment, net and total
    assets primarily reflect the effect of the Merger (see Note 2 to the
    Consolidated Financial Statements). The decrease in such amounts in 1997
    primarily reflect the spin off of Monterey (see Note 3 to the Consolidated
    Financial Statements).

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

Our U.S. core areas are the Gulf of Mexico, the Permian Basin and the Rocky
Mountains. Our international core areas are Southeast Asia and South America. We
also have oil production, and conduct some exploration operations, in West
Africa.

On May 5, 1999 Snyder Oil was merged with and into Santa Fe Energy and the
Company's name was changed to Santa Fe Snyder Corporation. The producing
properties that we acquired in the Merger are entirely located in the U.S.,
primarily in the Gulf of Mexico and the Rocky Mountains. The Merger is described
in Note 2 to the Consolidated Financial Statements. The consolidated financial
statements for the year ended December 31, 1999 include eight months of results
attributable to the properties acquired in the Merger.

As described in Note 3 to the Consolidated Financial Statements, we completed
the spin off of Monterey on July 25, 1997. The consolidated financial statements
for the year ended December 31, 1997 include seven months of Monterey's results.

RESULTS OF OPERATIONS

The following table reflects the components of our oil and gas revenues:
<TABLE>
<CAPTION>
                                           Year Ended December 31,
----------------------------------------------------------------------
                                         1999       1998       1997
----------------------------------------------------------------------
<S>                                    <C>        <C>        <C>
OIL
  SALES VOLUMES (MBBLS/DAY)
     Domestic                               24.9       21.2       50.3
     Argentina                               5.2        5.4        4.9
     Indonesia                              14.6       12.3        4.3
     Gabon                                   3.0        1.8         --
                                       ---------  ---------  ---------
                                            47.7       40.7       59.5
                                       =========  =========  =========
  SALES PRICES ($/BBL)
     Unhedged
       Domestic                            16.49      11.60      16.32
       Argentina                           16.89      10.73      16.93
       Indonesia                           17.42      11.91      17.58
       Gabon                               19.13      11.59         --
       Total                               16.99      11.58      16.46
     Hedged                                16.84      11.74      16.56
  REVENUES ($ MILLIONS)
     Sales
       Domestic                            150.2       89.4      299.9
       Argentina                            31.8       21.3       30.5
       Indonesia                            92.9       53.4       27.4
       Gabon                                21.2        7.7         --
                                       ---------  ---------  ---------
                                           296.1      171.8      357.8
     Hedging                                (2.5)       2.5        2.2
     Net Profits Payments                   (1.4)      (3.0)      (4.3)
                                       ---------  ---------  ---------
                                           292.2      171.3      355.7
                                       =========  =========  =========
</TABLE>

                                             (TABLE CONTINUED ON FOLLOWING PAGE)

                                       20
<PAGE>
<TABLE>
<CAPTION>
                                           Year Ended December 31,
----------------------------------------------------------------------
                                         1999       1998       1997
----------------------------------------------------------------------
<S>                                    <C>        <C>        <C>
GAS
  SALES VOLUMES (MMCF/DAY)
     Domestic                              263.5      152.1      154.8
     Argentina                              26.0       25.7       21.4
     Indonesia                                .2         .2         .3
                                       ---------  ---------  ---------
                                           289.7      178.0      176.5
                                       =========  =========  =========
  SALES PRICES ($/MCF)
     Unhedged
       Domestic                             2.23       2.01       2.37
       Argentina                            1.24       1.30       1.30
       Indonesia                            1.16       1.01       1.04
       Total                                2.14       1.91       2.23
     Hedged                                 2.11       1.91       2.23
  REVENUES($ MILLIONS)
     Sales
       Domestic                            214.0      111.7      133.7
       Argentina                            11.8       12.2       10.1
       Indonesia                              .1         .1         .1
                                       ---------  ---------  ---------
                                           225.9      124.0      143.9
     Hedging                                (3.0)        --         --
     Net Profits Payments                   (5.6)      (4.9)      (5.8)
                                       ---------  ---------  ---------
                                           217.3      119.1      138.1
                                       =========  =========  =========
</TABLE>

The following table sets forth our revenues and costs and expenses (excluding
impairment of oil and gas properties and merger related costs) on a BOE basis:
<TABLE>
<CAPTION>
                                           Year Ended December 31,
----------------------------------------------------------------------
                                         1999       1998       1997
----------------------------------------------------------------------
                                 (In Dollars Per BOE, except as noted)
<S>                                    <C>        <C>        <C>
Production -- MMBOE                         35.1       25.7       32.4
                                       =========  =========  =========
Revenues                                   14.56      11.33      15.83
                                       ---------  ---------  ---------
Production costs                            3.77       4.38       4.89
Production and other taxes                   .76        .63        .67
Cost of crude oil purchased               --         --            .68
General and administrative                   .75        .77        .87
Financing costs, net(a)                     1.04        .34(b)     .45
                                       ---------  ---------  ---------
                                            6.32       6.12       7.56
                                       ---------  ---------  ---------
     Operating margin                       8.24       5.21       8.27
Exploration                                 1.55       2.77       1.51
Depletion, depreciation and
  amortization                              5.30       5.30       3.93
Loss (gain) on disposition of assets         .02        .06       (.11)
                                       ---------  ---------  ---------
     Pre-tax margin                         1.37      (2.92)      2.94
                                       =========  =========  =========
</TABLE>
------------

a) Reflects interest expense less amounts capitalized and interest income.

b) Includes $0.18 per BOE ($4.7 million) of interest income related to federal
   income tax audit refunds.

                                       21
<PAGE>
YEAR ENDED DECEMBER 31, 1999 COMPARED WITH YEAR ENDED DECEMBER 31, 1998

Total revenues for 1999 of $510.3 million were 76% higher than in 1998,
primarily reflecting higher realized prices for oil and gas and increased
production. Our increased production was primarily due to the contribution of
the properties acquired in the Merger and other producing property acquisitions
(collectively the "Acquired Properties"). Our average sales price for oil
increased 43%, from $11.74 per barrel in 1998 to $16.84 per barrel in 1999, and
the average sales price for gas increased 10%, from $1.91 per Mcf in 1998 to
$2.11 per Mcf in 1999. Oil production increased 17%, from 40.7 MBbls per day in
1998 to 47.7 MBbls per day in 1999, primarily reflecting production from the
Acquired Properties of 4.3 MBbls per day as well as increases of 2.3 MBbls per
day in Indonesia and 1.2 MBbls per day in Gabon. Gas production increased 63%,
from 178.0 MMcf per day in 1998 to 289.7 MMcf per day in 1999, primarily
reflecting production from the Acquired Properties of 101.4 MMcf per day.
Realized oil prices for 1999 were reduced $0.15 per barrel by hedging losses
compared to a $0.16 increase in 1998 realized prices due to hedging gains.
Realized gas sales prices in 1999 were reduced by a $0.03 per Mcf hedging loss.
The Company did not hedge gas sales in 1998.

Costs and expenses increased from $445.0 million in 1998 to $639.1 million in
1999. Production costs, depletion, depreciation and amortization ("DD&A"),
general and administrative and production and other taxes increased primarily
reflecting costs attributable to the Merger and the Acquired Properties.
Production costs decreased from $4.38 per BOE in 1998 to $3.77 per BOE in 1999,
principally reflecting the effect of costs per BOE attributable to the Acquired
Properties. Exploration costs decreased $16.9 million in 1999, primarily
reflecting a $17.5 million decrease in dry hole costs. Merger related expenses
in 1999 include $1.9 million of severance and relocation costs and $9.6 million
of costs related to the acceleration of certain compensation plans and other
benefits.

In 1999 we evaluated the recovery of our long-lived assets and determined that
the estimated future undiscounted cash flows were below the carrying value of
certain oil and gas properties in the U.S., resulting in an impairment of $196.4
million. The estimated fair value was based on anticipated future cash flows
discounted at a rate commensurate with the risk involved with the properties and
our long-term outlook for future commodity prices. The impairments recognized in
1998 related to certain producing properties and unproven leaseholds in the Gulf
of Mexico. For an explanation of such impairment, see the following discussion
that compares the results of operations for the years 1998 and 1997.

Interest income decreased $5.1 million, due to the inclusion in 1998 of interest
income from federal income tax audits. Current year interest expense increased
$21.6 million reflecting the assumption of $219.0 million in debt in the Merger
and increased borrowings under our credit facility. Income taxes for 1998
included a $6.0 million benefit related to the favorable settlement of an audit
and a $2.4 million benefit related to an income tax refund.

The extraordinary item recognized in 1999 relates to the write-off of certain
debt issue costs and prepayment penalties incurred in connection with the
retirement of certain debt, net of $2.3 million in related income tax benefit.
See -- Liquidity and Capital Resources.

YEAR ENDED DECEMBER 31, 1998 COMPARED WITH YEAR ENDED DECEMBER 31, 1997

Total revenues for 1998 of $290.7 million were 43% lower than 1997, due to lower
prices for oil and gas which were down 30% and 14%, respectively and the
contribution of Monterey for seven months of 1997. Monterey contributed $180.8
million in oil and gas revenues in 1997. Our oil production for 1998 decreased
31% to 40.7 MBbls per day from 59.5 MBbls per day in 1997. The production
decrease was due to Monterey's contribution of 29.2 MBbls per day in 1997,
partially offset by an increase of 10.4 MBbls per day which was attributable to
new production from the Mudi, N. Geragai and Makmur fields in Indonesia and the
Tchatamba field in Gabon, the acquisition of an additional working interest in
the Mudi field and a full year of production from the Tupungato field in
Argentina. Gas production increased to 178.0 MMcf per day in 1998 compared with
176.5 MMcf per day for the same period in 1997. Gas production from new wells in
Southeast New Mexico, the Gulf of Mexico and Argentina more than offset the loss
of production from natural production declines, property sales and
weather-related disruptions in the Gulf of Mexico. Oil prices in 1998 averaged
$11.74 per barrel, including a $0.16 per barrel hedging

                                       22
<PAGE>
benefit, compared with $16.56 per barrel, including a $0.10 per barrel hedging
benefit in 1997. Gas prices in 1998 averaged $1.91 per Mcf, compared with an
average of $2.23 per Mcf in 1997.

Production costs for the year ended December 31, 1998 decreased to $112.5
million from $158.9 million in 1997 principally due to Monterey's contribution
of $71.3 million for the first seven months of 1997 partially offset by
increased oil and gas production, as noted above. Production costs decreased to
$4.38 per BOE from $4.89 per BOE in 1997 primarily due to Monterey's production
for the first seven months of 1997. Exploration expense in 1998 increased to
$71.1 million from $49.1 million in 1997, primarily due to dry hole costs in
Cote d'Ivoire, China and Ecuador and seismic programs in China and Gabon. DD&A
for 1998 increased to $136.1 million from $127.8 million for the same period of
1997 primarily due to increased production, but was partially offset by
Monterey's contribution of $22.3 million for the first seven months of 1997.
DD&A per BOE increased to $5.30 from $3.93 in 1997 due to new production from
higher cost properties in the Gulf of Mexico and Monterey's contribution in 1997
at $2.07 per BOE.

Impairments of $87.8 million were recorded in 1998 primarily on producing oil
and gas properties and unproven leasehold in the Gulf of Mexico. The impairments
of oil and gas properties were primarily the result of lower oil and gas prices.
The oil and gas impairment tests were based on estimates of future cash flows
using an initial WTI spot oil price and an initial New York Mercantile Exchange
("NYMEX") gas price based on quoted forward market prices which were
moderately escalated and included no forward sales. Future cash flows at
December 31, 1998 were based on our estimate of proved reserves and, in the case
of two fields where waterflood projects will be implemented, risk-adjusted
probable reserves. Probable reserves were reduced by risk factors for the
inherently higher risk associated with the ultimate recovery of these reserves.
If the cash flows from probable reserves had not been included in the impairment
test, the amount of the impairment would have increased by $17.0 million for
1998. The probable reserves associated with the two waterflood projects require
approval from state authorities and interest owners and will involve the
expenditure of approximately $8 million in the year 2000 and $7 million in the
following two years. We intend to expend this capital and have the financial
resources to do so. We charge accumulated amortization with the remaining basis
of individually insignificant unproved leasehold deemed to have no future value.
The impairments of unproved leasehold in the amount of $18.4 million recorded
during 1998 were associated with substantially all leases on the Gulf of Mexico
shelf and certain individually significant leases in the flex trend of the Gulf
of Mexico. Based primarily on unsuccessful drilling results to date, a thorough
technical review of flex trend leases and the current commodity price
environment, we decided not to commit additional capital to further explore on
these leases.

Interest income for 1998 included $4.7 million related to refunds on federal
income tax audits. Interest expense decreased by $1.8 million in 1998 primarily
due to Monterey's contribution of $11.7 million for the first seven months of
1997 and was partially offset by an increase in borrowings in 1998. Income taxes
for 1998 included a $6.0 million benefit related to the favorable settlement of
an audit and a $2.4 million benefit related to an anticipated income tax refund.
The preferred dividend requirement decreased $3.6 million in 1998 due to the
purchase and conversion of all of our outstanding preferred stock, which
included the Convertible Preferred Stock, 7% Series (the "7% Preferred") and
the $.732 Series A Convertible Preferred (the "DECS"). In November 1996 we
purchased 3.8 million of the outstanding shares of our 7% Preferred for $24.50
per share. In the second quarter of 1997, we converted the remaining 1.2 million
outstanding shares of 7% Preferred for 2.3 million shares of common stock. The
conversion of the 7% Preferred resulted in a noncash reduction in earnings to
common shares (which is reflected as a convertible preferred premium in the
Statement of Operations) of $8.4 million in 1997. Also, in the second quarter of
1997, we converted all 10.7 million outstanding shares of our DECS into 9.1
million shares of common stock which had no effect on earnings to common shares.

LIQUIDITY AND CAPITAL RESOURCES

CAPITAL EXPENDITURES.  In 1999, our primary needs for cash were for exploration,
development and acquisition of oil and gas properties. We spent $521.1 million
for capital expenditures in 1999, including

                                       23
<PAGE>
$263.7 million related to the acquisition of producing oil and gas properties.
In 2000 we expect to spend approximately $340 million on E&D Programs and
approximately $230 million on the acquisition of producing oil and gas
properties. Because the actual amounts expended in the future and the results
therefrom will be influenced by numerous factors, including many beyond our
control, no assurances can be given as to the amounts that will be expended. The
Board of Directors has authorized the purchase of up to $50 million of our
common stock to meet the requirements of outstanding stock options and to
satisfy the stock requirements of employee benefit plans. From December 1997
through year-end 1998, we purchased 1.3 million common shares for $12.0 million
and in 1999 1.6 million shares were purchased for $11.6 million. In early 2000
we purchased an additional 1.2 million common shares for $8.8 million.

CAPITAL RESOURCES.  Our principal capital resources in 1999 consisted of cash
flow from operating activities of $296.4 million, including $99.3 million
relating to a crude oil forward sale contract, $55.8 million in borrowings under
the Credit Facility, $108.0 (net of underwriting discounts) from an equity
offering of common stock, and $23.4 million of proceeds from the issuance of the
Senior Notes in excess of the amount used to retire our 11% Senior Subordinated
Debentures. See Note 9 to the Consolidated Financial Statements. At December 31,
1999, there were $629.4 million in borrowings outstanding, all of which were
classified as long-term debt on the balance sheet since we have the ability and
intend to refinance on a long-term basis. At December 31, 1999 one letter of
credit for $20.2 million was outstanding under the Credit Facility.

Concurrent with the closing of the Merger we entered into a $500.0 million
credit facility (the "Credit Facility") which was amended in November 1999 to
increase the amount available to $600.0 million. The Credit Facility consists of
a $450.0 million five-year tranche and a renewable $150.0 million 364-day
tranche. The Credit Facility bears interest, at our option, at LIBOR or prime
rates plus applicable margins dependent upon our credit rating and certain
financial ratios. Borrowings under the Credit Facility are unsecured. At
December 31, 1999, $320.0 million in borrowings were outstanding under the
Credit Facility. The weighted average interest rate with respect to borrowings
under the Credit Facility during 1999 was 6.3%.

In connection with the Merger, Santa Fe Snyder assumed Snyder Oil's $175.0
million of 8.75% Senior Subordinated Notes (the "Subordinated Notes") due June
15, 2007. The Subordinated Notes are redeemable on or after June 15, 2002,
initially at 104.375% of principal and at prices declining to 100% of principal
on or after June 15, 2005. The Subordinated Notes are general unsecured
obligations. Also in connection with the Merger, we assumed $44.0 million of
long-term debt outstanding under the terms of Snyder Oil's revolving credit
facility, which was repaid with funds borrowed under the Credit Facility.

In June 1999 the Company filed a shelf registration statement with the
Securities and Exchange Commission under which, for a period of two years, we
may sell different types of securities in one or more offerings up to a total
amount of $500 million. Utilizing the shelf registration statement, we may offer
and sell; (i) unsecured debt securities consisting of senior notes and
debentures and subordinated notes and debentures and/or other unsecured
evidences of indebtedness in one or more series; (ii) shares of preferred stock,
in one or more series, which may be convertible or exchangeable for common stock
or debt securities; and (iii) shares of common stock. During 1999 we issued $125
million of senior notes and sold 12.6 million shares of common stock in a public
offering for $114.6 million under the shelf registration.

In June 1999 we issued $125 million of 8.05% Senior Notes due 2004 (the "Senior
Notes") to replace our $100.0 million of 11% Senior Subordinated Debentures.
The Senior Notes were issued for 98.758% of face value and we received total
proceeds of $121.6 million after deducting related costs and expenses of $1.9
million. In connection with the Senior Notes offering, we executed two forward
treasury lock agreements (the "Treasury Locks") to mitigate interest rate risk
during the issuance of the Senior Notes. Upon the issuance of the Senior Notes,
the Treasury Locks were terminated, resulting in proceeds totaling $3.1 million,
which will be recognized as a component of interest expense over the life of the
Senior Notes.

                                       24
<PAGE>
The Credit Facility and the indentures for the Subordinated Notes and the Senior
Notes include covenants that restrict our ability to take certain actions,
including the ability to incur additional indebtedness and to pay dividends or
repurchase capital stock. Under the most restrictive of these covenants, at
December 31, 1999 we could incur $616 million of additional indebtedness, of
which $280 million could be borrowed under the Credit Facility, and could pay
dividends and/or repurchase common stock of up to $83 million.

In addition to the Credit Facility, we have short-term uncommitted lines of
credit which are used to meet short-term cash needs. At December 31, 1999 we had
two lines of credit and in February 2000 a third line of credit was added. Under
two of the lines of credit we may borrow up to $20.0 million and $10.0 million,
respectively, and under the other line of credit the amount available (up to
$25.0 million) varies with the amount outstanding under the Credit Facility.
Interest rates on borrowings under these lines of credit are typically lower
than rates paid under the Credit Facility when compared to the prime rate, which
would be required for short-term (less than 30 days) borrowings. As of December
31, 1999, there was $10.8 million in borrowings outstanding under short-term
facilities.

In connection with the retirement of certain debt in 1999 we recorded a $4.2
million extraordinary loss, net of $2.3 million of taxes. The extraordinary loss
represents the write-off of certain debt issue costs and prepayment penalties
pertaining to the retirement of the Debentures, net of related tax benefits.

In August 1999, we entered into an oil forward sales contract, under the terms
of which we will deliver a total of 6.2 million barrels of oil to the purchaser,
at specified monthly volumes, during the period from October 1999 through August
2002. In consideration we received a prepayment of $99.3 million, after
deducting arrangement and other related costs. The prepayment is recognized in
earnings when the oil is delivered. The balance of the prepayment related to
undelivered oil is reflected on the consolidated balance sheet under the caption
Deferred Revenues.

Also in August 1999, we completed a $114.6 million equity offering of 12.65
million shares of Santa Fe Snyder common stock receiving $108.0 million after
deducting the underwriting discount. The proceeds from these transactions were
used to fund the previously discussed acquisition of Gulf of Mexico deepwater
properties.

As a result of the Merger, we acquired interests in two foreign energy companies
which are listed on the London Stock Exchange. In November 1999 we sold our
interest in Cairn Energy plc for $24.7 million. Our investment in SOCO
International plc ("SOCO") is classified as an available-for-sale security and
is included in Other Assets in the consolidated balance sheet at December 31,
1999 (see Note 7 to the Consolidated Financial Statements).

In January 2000 we increased our working interest in two recently acquired
offshore Gulf of Mexico fields by purchasing Marathon Oil Company's working
interest for $160.0 million. To finance a portion of this acquisition, we
entered into an oil forward sales contract. Under the terms of the contract, we
will deliver a total of 4.2 million barrels of oil to the purchaser, at
specified monthly volumes, during the period from February 2000 through August
2002. In consideration, we received a prepaid amount of $74.6 million, after
deducting arrangement and other related costs. The balance of the prepayment
related to undelivered oil will be shown on the consolidated balance sheet under
the caption Deferred Revenues. The remainder of the purchase price was paid
utilizing the Credit Facility.

At February 29, 2000 we had $455.0 million outstanding under the Credit Facility
and $21.5 million outstanding under our short-term lines of credit. At that date
letters of credit outstanding totaled $27.3 million. The increase in outstanding
debt from year-end 1999 primarily reflects the purchase of working interests
from Marathon.

Historically we have funded our operations and exploration and development
capital spending programs with cash flow from operations and borrowings under
bank credit facilities and funded acquisitions with cash flow from operations,
bank debt, public debt, equity offerings and forward sales of production. We
believe we will be able to fund our anticipated capital requirements for 2000
from the same or similar sources.

                                       25
<PAGE>
ENVIRONMENTAL MATTERS.  Almost all phases of our 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. We have
expended significant financial and managerial resources to comply with such
regulations and believe our operations and facilities are in general compliance
with applicable environmental regulations, however, 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 our operations, could result in
significant costs and liabilities in the future. As we have done in the past, we
intend to fund the cost of environmental compliance from operating cash flows.
See Part I, Items 1. and 2. Business and Properties, Other Business
Matters -- Environmental Regulation and Note 14 to the Consolidated Financial
Statements.

DIVIDENDS.  The determination of the amount of future cash dividends, if any, to
be declared and paid on our common stock is at the sole discretion of our Board
of Directors and is dependent on financial condition, earnings and available
funds from operations, level of capital and exploration expenditures, dividend
restrictions as set forth in financing agreements, future business prospects and
other matters that our Board deems relevant.

YEAR 2000.  Many computer systems were built using software that processes
transactions using two digits to represent the year. This type of software
generally required modifications to function properly with dates after December
31, 1999 (or, to become "Y2K compliant"). To date, we have not encountered any
significant problems, have not incurred any unexpected costs and do not expect
any Y2K problems to arise in the future. We estimate the total cost related to
our Y2K compliance effort to be approximately $1.7 million, of which $0.5
million was capitalized, which was funded by cash from operations or borrowings
under the Credit Facility.

ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISKS

We are exposed to market risk, which includes adverse changes in commodity
prices and interest rates as discussed below.

COMMODITY PRICE RISK

We produce and sell oil and gas. As a result, our financial results can be
materially affected as these commodity prices fluctuate widely in response to
changing market factors. Oil prices are subject to significant changes in
response to fluctuations in the domestic and world supply and demand and other
market conditions as well as the world political situation as it affects OPEC
and other producing countries. In 1999 our actual average oil sales price
(unhedged) received ranged from a low of $10.85 per barrel in the first quarter
to a high of $21.70 per barrel in the fourth quarter. Our average oil sales
price (unhedged) received in January 2000 was $23.34 per barrel. The price of
gas fluctuates due to weather conditions, the level of gas in storage, the
relative balance between supply and demand and other economic factors. Our
actual average sales price received in 1999 for gas (unhedged) ranged from a low
of $1.59 per Mcf in the first quarter to a high of $2.36 per Mcf in the third
quarter. Our average gas price received in January 2000 was $2.04 per Mcf.

Based on operating results for the last six months of 1999, we estimate that on
an annualized basis a $1.00 per barrel increase or decrease in our average oil
sales price would result in a corresponding $12.3 million change in net income
and a $15.7 million change in cash flow from operating activities, and a $0.10
per Mcf increase or decrease in our average gas sales price would result in a
corresponding $7.8 million change in net income and an $11.7 million change in
cash flow from operating activities. These estimates do not give effect to
changes in any other factors, such as the effect of our hedging program, debt
levels and related interest expense, reserve levels or the level of capital
expenditures, that might result from a change in oil and gas prices.

From time to time we hedge a portion of our oil and gas sales to provide a
certain minimum level of cash flow. While the hedges are generally intended to
reduce our exposure to declines in market price, our

                                       26
<PAGE>
gain from increases in market price may be limited. We use various financial
instruments whereby monthly settlements are based on differences between the
prices specified in the instruments and the settlement prices of certain futures
contracts quoted on the New York Mercantile Exchange ("NYMEX") or certain
other indices. The instruments we utilize differ from futures contracts in that
there is no contractual obligation which requires or allows for the future
delivery of the product. Gains or losses on hedging activities are recognized in
oil and gas revenues in the period in which the hedged production is sold.

Oil sales hedges resulted in a $2.5 million decrease in revenues in 1999 and
increases of $2.5 million and $2.2 million in 1998 and 1997, respectively. At
December 31, 1999 we had open oil sales hedges on an average of 11,000 barrels
per day through December 31, 2000. The instruments used have an average floor of
$20.20 per barrel and an average ceiling of $25.06 per barrel. If the aggregate
average of the applicable daily settlement prices is below the floor, we will
receive a settlement based on difference, and if the aggregate average of the
applicable daily settlement prices is above the ceiling, we will be required to
pay an amount based on the difference. Based on the December 31, 1999 settlement
price of the applicable NYMEX futures contracts, our unrealized loss with
respect to such hedges at December 31, 1999 was $1.8 million. The actual gains
or losses realized from these hedges may vary significantly due to the
volatility of the futures markets and other indices.

At January 31, 2000 we had open oil sales hedges on an average of 17,300 barrels
per day through December 31, 2000. The instruments used have an average floor of
$20.19 per barrel and an average ceiling of $25.12 per barrel.

In addition to oil sales hedges, we have entered into two forward sales
contracts which cover approximately 9.6 million barrels of our oil production
during the period from February 2000 until August 2002. These contracts are
discussed in Liquidity and Capital Resources.

Gas sales hedges resulted in a $3.0 million reduction in gas revenues in 1999.
We had no gas sales hedges in 1998 or 1997 and currently have no open gas sales
hedges. We have a long-term gas swap agreement that was entered into by Snyder
Oil in 1994 to lock in the price difference between the Rocky Mountain and Henry
Hub prices on 20,000 MMBtu per day of Rocky Mountain gas production through
2004. The gas swap agreement had no effect on gas revenues for the full year
1999. The unrealized gain with respect to the gas swap agreement at December 31,
1999 was $2.2 million.

INTEREST RATE RISK

Our exposure to changes in interest rates primarily results from our short-term
and long-term debt with both fixed and floating interest rates. To date, we have
not deemed it necessary to enter into any financial instruments, such as
interest rate swaps, because interest rates have remained at historically low
levels.

NEW ACCOUNTING STANDARDS

Statement of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" ("SFAS 133"), as amended by Statement of
Financial Accounting Standards No. 137, is effective for all fiscal quarters of
all fiscal years beginning after June 15, 2000. We intend to implement the
provisions of SFAS 133 beginning January 1, 2001.

SFAS 133 requires all derivatives to be recognized in the balance sheet as
either assets or liabilities and measured at fair value. Derivatives that are
not hedges must be adjusted to fair value through income. If the derivative is a
hedge, depending on the nature of the hedge, changes in the fair value of
derivatives will either be offset against the change in fair value of the hedged
assets, liabilities, or firm commitments through earnings or recognized in other
comprehensive income until the hedged item is recognized in earnings. The
ineffective portion of a derivative's change in fair value will be immediately
recognized in earnings. We have not yet determined the impact that the adoption
of SFAS 133 will have on earnings, financial position or cash flows.

                                       27
<PAGE>
ITEM 8.  CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

See the Consolidated Financial Statements listed under Item 14 (a)(1) on page 30
and the Supplemental Information to Consolidated Financial Statements
(Unaudited) on page 59. Information required by schedules required under
Regulation S-X is either not applicable or is included in the consolidated
financial statements or notes thereto.

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

None.

                                       28
<PAGE>
                                    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 the Executive Officers of the
Registrant, which is included in Part 1 of this Report, the information called
for by Items 10 through 14 is incorporated by reference from the Company's
definitive Proxy Statement, which involves the election of directors, in
accordance with General Instruction G to the Annual Report on Form 10-K. Such
definitive Proxy Statement shall be filed with the Securities and Exchange
Commission not later than April 29, 2000.

                                       29

<PAGE>
                                    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) Consolidated Financial Statements

     Report of Management                                                 31
     Report of Independent Accountants                                    32
     Consolidated Statement of Operations --
       Years Ended December 31, 1999, 1998 and 1997                       33
     Consolidated Balance
      Sheet -- December 31, 1999 and 1998                                 34
     Consolidated Statement of Cash Flows --
       Years Ended December 31, 1999, 1998 and 1997                       35
     Consolidated Statement of Comprehensive Income --
       Years Ended December 31, 1999, 1998 and 1997                       36
     Consolidated Statement of Shareholders' Equity --
       Years Ended December 31, 1999, 1998 and 1997                       37
     Notes to Consolidated Financial Statements                           38
 (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
     thereto.

 (3) Exhibits

     See Index of Exhibits on page 68 for a description of the exhibits filed as
     a part of this report.

(b)  Reports on Form 8-K

     Not applicable.

                                       30
<PAGE>
                              REPORT OF MANAGEMENT

To the Stockholders of Santa Fe Snyder Corporation:

Management of Santa Fe Snyder is responsible for preparing the accompanying
consolidated financial statements and for assuring their integrity and
objectivity. These statements were prepared in accordance with generally
accepted accounting principles and fairly present the transactions and financial
position of the Company. The financial statements include amounts that are based
on management's best estimates and judgments.

The Company's financial statements have been audited by PricewaterhouseCoopers
LLP, independent accountants selected by the Audit Committee and approved by the
stockholders. Management has made available to PricewaterhouseCoopers LLP all of
the Company's financial records and related data, as well as the minutes of
stockholders' and directors' meetings.

Management of the Company has established and maintains a system of internal
accounting controls that is designed to provide reasonable assurance that assets
are safeguarded, transactions are properly recorded and executed in accordance
with management's authorization, and the books and records accurately reflect
the disposition of assets. The system of internal controls includes appropriate
division of responsibility. The Company maintains an internal audit department
that conducts a comprehensive program of internal audits and independently
assesses the effectiveness of the internal controls.

The Board of Directors exercises its oversight role with respect to the
Company's system of internal controls primarily through its Audit Committee,
which is composed of directors who are not officers or employees of the Company.
It meets regularly with members of management, the internal auditors and the
independent accountants to discuss the adequacy of the Company's internal
controls, financial statements and the nature, extent and results of the audit
effort. Both the internal auditors and the independent accountants have free and
direct access to the Audit Committee without the presence of management.

<TABLE>
<S>                                    <C>
           James L. Payne                                Mark A. Jackson
Chief Executive Officer and Director              Executive Vice President and
    (Principal Executive Officer)                    Chief Financial Officer
                                                  (Principal Financial Officer)
</TABLE>

                                       31
<PAGE>
                       REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Shareholders of
  Santa Fe Snyder Corporation:

In our opinion, the consolidated financial statements listed in the accompanying
index appearing under Item 14(a)(1) on page 30 present fairly, in all material
respects, the financial position of Santa Fe Snyder Corporation and its
subsidiaries (the "Company") at December 31, 1999 and 1998, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 1999 in conformity with accounting principles generally
accepted in the United States. 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 auditing standards generally accepted in the
United States 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.

PRICEWATERHOUSECOOPERS LLP

Houston, Texas
January 28, 2000

                                       32

<PAGE>
SANTA FE SNYDER CORPORATION
CONSOLIDATED STATEMENT OF OPERATIONS
(In Millions of Dollars, except as noted)
<TABLE>
<CAPTION>
                                           Year Ended December 31,
----------------------------------------------------------------------
                                         1999       1998       1997
----------------------------------------------------------------------
<S>                                    <C>        <C>        <C>
Revenues
  Crude oil and liquids                $   292.2  $   171.3  $   355.7
  Natural gas                              217.3      119.1      138.1
  Crude oil purchased                     --         --           20.5
  Other                                       .8         .3        (.2)
                                       ---------  ---------  ---------
                                           510.3      290.7      514.1
                                       ---------  ---------  ---------
Costs and Expenses
  Production costs                         132.1      112.5      158.9
  Production and other taxes                26.6       16.3       21.6
  Cost of crude oil purchased             --         --           22.0
  Exploration                               54.2       71.1       49.1
  Depletion, depreciation and
     amortization                          185.8      136.1      127.8
  Impairment of oil and gas
     properties                            196.4       87.8     --
  General and administrative                26.2       19.7       28.1
  Merger related costs                      16.8     --         --
  Loss (gain) on disposition of
     assets                                  1.0        1.5       (3.6)
                                       ---------  ---------  ---------
                                           639.1      445.0      403.9
                                       ---------  ---------  ---------
Income (Loss) from Operations             (128.8)    (154.3)     110.2
  Interest income                            1.1        6.2        2.5
  Interest expense                         (43.6)     (22.0)     (23.8)
  Interest capitalized                       6.0        7.2        6.7
                                       ---------  ---------  ---------
Income (Loss) Before Income Taxes,
  Minority Interest and Extraordinary
  Item                                    (165.3)    (162.9)      95.6
  Current income tax (expense)
     benefit                                 1.6       11.4       (8.9)
  Deferred income tax (expense)
     benefit                                43.0       52.8      (27.3)
                                       ---------  ---------  ---------
Income (Loss) Before Minority
  Interest and Extraordinary Item         (120.7)     (98.7)      59.4
  Minority interest in Monterey
     Resources, Inc.                      --         --           (4.7)
                                       ---------  ---------  ---------
Income (Loss) Before Extraordinary
  Item                                    (120.7)     (98.7)      54.7
  Extraordinary item -- debt
     extinguishment costs                   (4.2)    --         --
                                       ---------  ---------  ---------
Net Income (Loss)                         (124.9)     (98.7)      54.7
  Preferred dividend requirement          --         --           (3.6)
  Convertible preferred repurchase
     premium                              --         --           (8.4)
                                       ---------  ---------  ---------
Earnings (Loss) Attributable to
  Common Shares                        $  (124.9) $   (98.7) $    42.7
                                       =========  =========  =========
Earnings (Loss) per Common Share,
  basic and diluted (in dollars)
  Before extraordinary item            $    (.79) $    (.96) $     .43
  Extraordinary item -- debt
     extinguishment costs                   (.03)    --         --
                                       ---------  ---------  ---------
  Per common share                     $    (.82) $    (.96) $     .43
                                       =========  =========  =========
Weighted Average Shares Outstanding
  (in millions)                            152.9      102.6       98.6
                                       =========  =========  =========
</TABLE>

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

                                       33
<PAGE>
SANTA FE SNYDER CORPORATION
CONSOLIDATED BALANCE SHEET
(In Millions of Dollars)
<TABLE>
<CAPTION>
                                           December 31,
-----------------------------------------------------------
                                         1999       1998
-----------------------------------------------------------
<S>                                    <C>        <C>
               ASSETS
Current Assets
  Cash and cash equivalents            $     6.0  $    12.1
  Accounts receivable                      106.6       53.2
  Inventories                               25.5       19.0
  Other current assets                      35.0       31.7
                                       ---------  ---------
                                           173.1      116.0
                                       ---------  ---------
Properties and equipment, at cost
  Oil and gas (successful efforts
     method of accounting)               3,134.9    1,940.0
  Other                                     53.2       37.0
                                       ---------  ---------
                                         3,188.1    1,977.0
  Accumulated depletion,
     depreciation, amortization and
     impairment                         (1,531.0)  (1,258.7)
                                       ---------  ---------
                                         1,657.1      718.3
                                       ---------  ---------
Other Assets
  Deferred income taxes                   --           13.5
  Other assets                              32.6       11.2
                                       ---------  ---------
                                            32.6       24.7
                                       ---------  ---------
                                       $ 1,862.8  $   859.0
                                       =========  =========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
  Accounts payable                     $   200.4  $   123.3
  Income taxes payable                       1.3        1.2
  Interest payable                           2.1        1.9
  Other current liabilities                 36.1       12.8
                                       ---------  ---------
                                           239.9      139.2
                                       ---------  ---------
Long-Term Debt                             629.4      330.6
                                       ---------  ---------
Deferred Revenues                          104.8        3.6
                                       ---------  ---------
Other Long-Term Obligations                 70.1       37.2
                                       ---------  ---------
Deferred Income Taxes                       77.4     --
                                       ---------  ---------
Commitments and Contingencies (Note
  14)
Shareholders' Equity
  Preferred stock, $0.01 par value,
     50.0 million shares authorized
     in 1999, 38.1 million shares
     authorized in 1998, none issued      --         --
  Common stock, $0.01 par value,
     500.0 million shares authorized
     in 1999, 200.0 million shares
     authorized in 1998                      1.8        1.0
  Paid-in capital                        1,247.4      728.2
  Accumulated deficit                     (498.5)    (372.5)
  Accumulated other comprehensive
     income                                  1.3     --
  Treasury stock, at cost                  (10.8)      (6.8)
  Unamortized restricted stock awards     --           (1.5)
                                       ---------  ---------
                                           741.2      348.4
                                       ---------  ---------
                                       $ 1,862.8  $   859.0
                                       =========  =========
</TABLE>

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

                                       34
<PAGE>
SANTA FE SNYDER CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(In Millions of Dollars)
<TABLE>
<CAPTION>
                                           Year Ended December 31,
----------------------------------------------------------------------
                                         1999       1998       1997
----------------------------------------------------------------------
<S>                                    <C>        <C>        <C>
Operating Activities
  Net income (loss)                    $  (124.9) $   (98.7) $    54.7
  Adjustments to reconcile net income
     (loss) to net cash provided by
     operating activities:
       Depletion, depreciation and
          amortization                     185.8      136.1      127.8
       Impairment of oil and gas
          properties                       196.4       87.8     --
       Deferred income taxes               (43.0)     (52.8)      27.3
       Loss (gain) on disposition of
          oil and gas properties             1.0        1.5       (3.6)
       Exploratory dry hole costs           20.9       38.4       23.7
       Minority interest in Monterey
          Resources, Inc.                 --         --            4.7
       Other                                 7.6        3.9        5.7
     Changes in operating assets and
       liabilities (net of
       acquisitions):
       Decrease (increase) in
          accounts receivable              (38.0)      20.6       11.3
       Decrease (increase) in
          inventories                       (5.5)      (2.6)      (2.3)
       Increase (decrease) in
          accounts payable                  16.7      (16.0)      15.3
       Increase (decrease) in income
          taxes payable                       .1       (5.3)     (15.0)
       Increase (decrease) in
          interest payable                  (5.7)        .5        1.7
       Increase (decrease) in
          deferred revenues                 98.4        (.1)       (.3)
       Change in other assets and
          liabilities                      (13.4)       1.8        3.6
                                       ---------  ---------  ---------
  Net cash provided by operating
     activities                            296.4      115.1      254.6
                                       ---------  ---------  ---------
Investing activities
  Capital expenditures                    (255.9)    (191.9)    (218.6)
  Acquisition of Snyder Oil
     Corporation, net of cash
     acquired                               (1.5)    --         --
  Acquisition of producing properties     (263.7)    (117.6)    (197.8)
  Proceeds from disposition of assets       36.8        2.0       40.8
                                       ---------  ---------  ---------
  Net cash used in investing
     activities                           (484.3)    (307.5)    (375.6)
                                       ---------  ---------  ---------
Financing Activities
  Issuance of common stock                 108.0        1.6        2.8
  Net change in long-term lines of
     credit                                 55.8      208.9      118.2
  Issuance of 8.05% senior notes           123.4     --         --
  Retirement of 11% senior
     subordinated debentures              (100.0)    --         --
  Cash dividends paid                     --         --           (8.5)
  Treasury stock purchased                 (11.6)     (11.6)      (0.5)
  Treasury stock reissued                    6.2     --         --
                                       ---------  ---------  ---------
  Net cash provided by financing
     activities                            181.8      198.9      112.0
                                       ---------  ---------  ---------
  Net Increase (Decrease) in Cash and
     Cash Equivalents                       (6.1)       6.5       (9.0)
  Cash and Cash Equivalents at
     Beginning of Period                    12.1        5.6       14.6
                                       ---------  ---------  ---------
  Cash and Cash Equivalents at End of
     Period                            $     6.0  $    12.1  $     5.6
                                       =========  =========  =========
Supplemental Disclosure of Cash Flow
  Information
  Interest paid                        $    52.3  $    21.1  $    11.5
  Income taxes paid                    $     5.0  $     5.2  $    17.8
</TABLE>

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

                                       35
<PAGE>
SANTA FE SNYDER CORPORATION
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(In Millions of Dollars)
<TABLE>
<CAPTION>
                                           Year Ended December 31,
----------------------------------------------------------------------
                                         1999       1998       1997
----------------------------------------------------------------------
<S>                                    <C>        <C>        <C>
Earnings (Loss) Attributable to
  Common Shares                        $  (124.9) $   (98.7) $    42.7
                                       ---------  ---------  ---------
Other Comprehensive Income
  Unrealized holding gain on
     securities                              2.1     --         --
  Deferred income taxes                      (.8)    --         --
                                       ---------  ---------  ---------
                                             1.3     --         --
                                       ---------  ---------  ---------
Comprehensive Income (Loss)            $  (123.6) $   (98.7) $    42.7
                                       =========  =========  =========
</TABLE>

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

                                       36
<PAGE>
SANTA FE SNYDER CORPORATION
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
(Shares and Dollars In Millions)
<TABLE>
<CAPTION>
                                              1999                1998                1997
------------------------------------------------------------------------------------------------
                                        SHARES    AMOUNT    SHARES    AMOUNT    SHARES    AMOUNT
------------------------------------------------------------------------------------------------
<S>                                     <C>       <C>       <C>       <C>       <C>       <C>
$.732 SERIES A CONVERTIBLE PREFERRED
STOCK
  Balance, beginning of year             --       $--        --       $--        10.7     $91.4
  Conversion to common stock                                                    (10.7)    (91.4)
                                        ------    ------    ------    ------    ------    ------
  Balance, end of year                   --        --        --        --        --        --
                                        ======    ------    ======    ------    ======    ------
COMMON STOCK
  Balance, beginning of year            103.0       1.0     103.0       1.0      91.0       0.9
  Issuances of common stock
    Acquisition of Snyder Oil Company    68.8       0.7      --        --        --        --
    Public offering                      12.6       0.1      --        --        --        --
    Employee stock compensation and
      savings plans                      --        --        --        --         0.7      --
    Conversion of $.732 Series A
      preferred stock                    --        --        --        --         9.1       0.1
    Conversion of convertible
      preferred
      stock, 7% series                   --        --        --        --         2.2      --
                                        ------    ------    ------    ------    ------    ------
  Balance, end of year                  184.4       1.8     103.0       1.0     103.0       1.0
                                        ======    ------    ======    ------    ======    ------
PAID-IN CAPITAL
  Balance, beginning of year                      728.2               728.2               601.3
  Issuances of common stock
    Acquisition of Snyder Oil Company             411.4                --                  --
    Public offering                               107.8                --                  --
    Employee stock compensation and
      savings plans                                --                  --                   7.6
    Conversion of $.732 Series A
      preferred stock                              --                  --                  91.3
    Conversion of convertible
      preferred
      stock, 7% series                             --                  --                  28.0
                                                  ------              ------              ------
  Balance, end of year                            1,247.4             728.2               728.2
                                                  ------              ------              ------
ACCUMULATED DEFICIT
  Balance, beginning of year                      (372.5)             (273.2)             (166.5)
  Net income (loss)                               (124.9)             (98.7)               54.7
  Common stock issuances related to
    employee stock compensation and
    savings plans                                  (1.1)               (0.6)               --
  Conversion of convertible
    preferred stock, 7% series                     --                  --                  (8.4)
  Dividends declared                               --                  --                  (3.6)
  Spin off of Monterey Resources,
    Inc.                                           --                  --                 (149.4)
                                                  ------              ------              ------
  Balance, end of year                            (498.5)             (372.5)             (273.2)
                                                  ------              ------              ------
ACCUMULATED OTHER COMPREHENSIVE
  INCOME
  Balance, beginning of year                       --                  --                  --
  Other comprehensive income                        1.3                --                  --
                                                  ------              ------              ------
  Balance, end of year                              1.3                --                  --
                                                  ------              ------              ------
TREASURY STOCK
  Balance, beginning of year             (0.8)     (6.8)     (0.1)     (0.6)     --        (0.3)
  Issuances related to employee stock
    compensation and savings plans        0.9       7.6       0.6       5.4      --         0.2
  Purchase of treasury stock             (1.6)    (11.6)     (1.3)    (11.6)     (0.1)     (0.5)
                                        ------    ------    ------    ------    ------    ------
  Balance, end of year                   (1.5)    (10.8)     (0.8)     (6.8)     (0.1)     (0.6)
                                        ======    ------    ======    ------    ======    ------
UNAMORTIZED RESTRICTED STOCK AWARDS
  Balance, beginning of year                       (1.5)               (0.7)               --
  Issuances related to employee stock
    compensation and savings plans                 (0.1)               (2.6)               (2.4)
  Amortization of restricted stock
    awards                                          1.6                 1.8                 1.7
                                                  ------              ------              ------
  Balance, end of year                             --                  (1.5)               (0.7)
                                                  ------              ------              ------
TOTAL SHAREHOLDERS' EQUITY                        $741.2              $348.4              $454.7
                                                  ======              ======              ======
</TABLE>

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

                                       37
<PAGE>
SANTA FE SNYDER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES. PRINCIPLES
OF CONSOLIDATION. The consolidated financial statements of Santa Fe Snyder
Corporation ("Santa Fe Snyder" or the "Company") and its subsidiaries include
the accounts of all wholly owned subsidiaries and Monterey Resources, Inc.
("Monterey") until its Spin Off in July 1997. Prior to Monterey's initial public
offering in November 1996, the Company owned 100% of the outstanding common
stock of Monterey. At December 31, 1996, the Company owned 82.8% of the
outstanding common stock of Monterey. On July 25, 1997 the Company distributed
pro rata to its common shareholders all of the shares of Monterey's common stock
that it owned (the "Spin Off" -- see Note 3 -- Spin Off of Monterey Resources,
Inc.).

Effective May 5, 1999, Snyder Oil Corporation ("Snyder Oil") was merged with
and into Santa Fe Energy Resources, Inc. ("Santa Fe Energy"), a Delaware
corporation, pursuant to an Agreement and Plan of Merger dated January 13, 1999
(the "Merger"). In connection with the Merger, Santa Fe amended its Articles
of Incorporation to change its name to Santa Fe Snyder Corporation and increased
its authorized common stock and preferred stock to 500.0 million shares and 50.0
million shares, respectively. The Merger was accounted for as a purchase. See
Note 2 -- Merger with Snyder Oil Corporation.

All significant intercompany accounts and transactions have been eliminated.
Certain amounts in prior periods have been reclassified to conform to the
current year's presentation.

OIL AND GAS OPERATIONS.  The Company follows the successful efforts method of
accounting for its oil and gas exploration and production activities. Costs
(both tangible and intangible) of productive wells and development dry holes, as
well as the cost of prospective acreage, are capitalized. For exploratory
drilling costs where management is assessing the appropriateness of significant
capital expenditures, amounts are capitalized pending finalization of spending
plans. Other costs of drilling exploratory wells are capitalized pending
determination within one year of whether they have discovered commercial
reserves. The costs of drilling and equipping exploratory wells which do not
find proved reserves are expensed upon determination that a 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 a field basis
using the unit-of-production method based upon proved oil and gas reserves
attributable to the field. Periodically, proved properties are reviewed to
determine if the carrying value of the property exceeds the expected
undiscounted future net cash flows from the operation of the property. Based on
this review and the continuing evaluation of development plans, production data,
economics and other factors, as appropriate, the Company records impairment
(additional depletion and depreciation) to the extent that the carrying value of
the property exceeds the fair value of the property on a discounted basis.

In 1999 and 1998 the Company recorded impairment charges of $196.4 million and
$87.8 million, respectively. In 1999 the Company determined that the estimated
future undiscounted cash flows were below the carrying value of certain oil and
gas properties in the United States. The estimated fair value was based on
anticipated future cash flows discounted at a rate commensurate with the risk
involved with the properties and the Company's long-term outlook for future
commodity prices. The impairments recorded in 1998 were primarily on producing
oil and gas properties and unproven leasehold in the Gulf of Mexico and were
primarily the result of lower oil and gas prices. The oil and gas impairment
tests were based on estimates of future cash flows using an initial WTI spot oil
price and an initial New York Mercantile Exchange ("NYMEX") gas price based on
quoted forward market prices which were moderately escalated and included no
forward sales. Future cash flows were based on the Company's estimate of proved
reserves and, in 1998, risk-adjusted probable reserves. Probable reserves were
reduced by risk factors for the inherently higher risk associated with the
ultimate recovery of such

                                       38
<PAGE>
SANTA FE SNYDER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)

reserves. If cash flows from probable reserves had not been included in the
impairment tests, the amount of the impairment would have increased by $17.0
million for 1998.

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. 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.
Additional amortization may be recognized based upon periodic assessment of
prospect evaluation results. The previously discussed impairment amount for 1998
includes $18.4 million associated with substantially all leases on the Gulf of
Mexico shelf and certain individually significant leases in the flex trend of
the Gulf of Mexico. Based primarily on unsuccessful drilling results, a thorough
technical review of flex trend leases and the current commodity price
environment, the Company decided not to commit additional capital to further
explore on such leases.

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 $28.9
million and such amount is being accrued over the expected life of the
properties on a unit-of-production basis. At December 31, 1999 and 1998,
accumulated depletion, depreciation, amortization and impairment included $17.0
million and $12.3 million, respectively, of such costs.

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

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

Revenues from natural gas production are generally recorded using the
entitlement method, net of royalties and net profits interests. Sales proceeds
in excess of the Company's entitlement are included in Deferred Revenues and the
Company's share of sales taken by others is included in Other Assets. At
December 31, 1999 and 1998, the Company's deferred revenues for sales proceeds
received in excess of the Company's entitlement were $10.3 million with respect
to 5.1 MMcf and $3.2 million with respect to 2.5 MMcf, respectively, and the
asset related to the Company's share of sales taken by others was $8.1 million
with respect to 4.4 MMcf and $1.2 million with respect to 0.9 MMcf,
respectively.

In August 1999 and January 2000 the Company entered into crude oil forward sales
contracts under the terms of which the Company is obligated to deliver crude oil
to the purchaser, based on specified monthly volumes, during the period October
1999 through August 2002. See Note 14 -- Commitments and Contingencies -- Crude
Oil Sales Contracts.

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

PRICE RISK MANAGEMENT.  The Company engages in price risk management activities
for non-trading purposes. Derivative financial instruments (primarily fixed
price swaps, collars and options) are utilized to hedge the impact of market
fluctuations on natural gas and crude oil market prices. Gains and losses on
derivative financial instruments are recognized in oil and gas revenues in the
period in which the hedged production is sold. Gains and losses on hedging
instruments that are closed prior to maturity are deferred and recognized in
earnings over the period the hedged production is sold. The cash flow impact of
hedging activities are reflected in Cash Provided by Operating Activities in the
Consolidated Statement of Cash Flows. See Note 14 -- Commitments and
Contingencies -- Oil and Gas Hedging.

                                       39
<PAGE>
SANTA FE SNYDER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)

EARNINGS PER SHARE.  The computation of earnings per share is discussed in Note
4 -- Earnings Per Share.

ACCOUNTS RECEIVABLE.   Accounts Receivable relates primarily to sales of oil and
gas and amounts due from joint interest partners for expenditures made by the
Company on behalf of such partners. The Company reviews the financial condition
of potential purchasers and partners prior to signing sales or joint interest
agreements. At December 31, 1999 and 1998 the Company's allowance for doubtful
accounts receivable, which is reflected in the consolidated balance sheet as a
reduction in accounts receivable, totaled $2.1 million and $1.6 million,
respectively. Accounts receivable totalling $1.1 million and $0.3 million were
written off as uncollectible in 1998 and 1997, respectively. The allowance was
increased by $0.5 million in 1999 as a result of the Merger and by $0.5 million
in 1997 by a charge to expense.

INVENTORIES.  Inventories are generally valued at the lower of cost (average
price or first-in, first-out) or market. Crude oil inventories at December 31,
1999 and 1998 were $9.8 million and $5.7 million, respectively, and materials
and supplies inventories at such dates were $15.7 million and $13.3 million,
respectively.

ENVIRONMENTAL EXPENDITURES.  Environmental 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 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.

FUNCTIONAL CURRENCY.  The functional currency of the Company and its
subsidiaries is the U.S. dollar.

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. The
Company's most significant financial estimates are related to the Company's
proved oil and gas reserves (see Supplemental Information to Consolidated
Financial Statements). Actual results may differ from such estimates.

COMPREHENSIVE INCOME.  Comprehensive income is net income, plus certain other
items that are recorded directly to shareholders' equity. In 1998 and 1997, the
Company had no comprehensive income other than net income.

NEW ACCOUNTING STANDARDS.  Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"),
as amended by Statement of Financial Accounting Standards No. 137, is effective
for fiscal years beginning after June 15, 2000. The Company intends to implement
the provisions of SFAS 133 beginning January 1, 2001.

SFAS 133 requires all derivatives to be recognized in the balance sheet as
either assets or liabilities and measured at fair value. Derivatives that are
not hedges must be adjusted to fair value through income. If the derivative is a
hedge, depending on the nature of the hedge, changes in the fair value of
derivatives will either be offset against the change in fair value of the hedged
assets, liabilities, or firm commitments through earnings or recognized in other
comprehensive income until the hedged item is recognized in

                                       40
<PAGE>
SANTA FE SNYDER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)

earnings. The ineffective portion of a derivative's change in fair value will be
immediately recognized in earnings. The Company has not yet determined the
impact that the adoption of SFAS 133 will have on its earnings, statement of
financial position or cash flows.

NOTE 2.  MERGER WITH SNYDER OIL CORPORATION.  Effective May 5, 1999, Snyder Oil
was merged with and into Santa Fe Energy pursuant to an Agreement and Plan of
Merger dated January 13, 1999. In connection with the Merger, Santa Fe Energy
amended its Articles of Incorporation to change its name to Santa Fe Snyder
Corporation. In the Merger each issued and outstanding share of common stock of
Snyder Oil was converted into 2.05 shares of common stock of Santa Fe Snyder.
The exchange ratio was determined through arm's length negotiations between the
parties. The Merger has been accounted for as a purchase and the results of
operations of the acquired company are included in Santa Fe Snyder's results of
operations effective May 1, 1999.

To consummate the Merger, Santa Fe Snyder issued 68.8 million shares of common
stock, assumed the long-term debt and other liabilities of Snyder Oil and
incurred other Merger-related costs. In addition, the Company recorded a
deferred income tax liability with respect to the difference between the book
and tax basis in the assets acquired. Such amounts are set forth in the
following table, in millions of dollars:

<TABLE>
<S>                                    <C>
Cash costs                                   1.5
Common stock                               412.1
Long-term debt assumed                     219.0
Liabilities assumed or accrued              96.7
Deferred income tax liability              135.4
                                       ---------
                                           864.7
                                       =========
</TABLE>

Such amount was allocated to specific assets or charged to the Company's results
of operations as follows, in millions of dollars:

<TABLE>
<S>                                    <C>
Charged to assets acquired
  Property, plant and equipment            793.9
  Current assets                            16.8
  Other assets                              37.2
Charged to results of operations            16.8
                                       ---------
                                           864.7
                                       =========
</TABLE>

The allocation of the purchase price to specific assets was based on certain
estimates of fair values. At the time of the Merger the Company assumed or
accrued the following $19.4 million of costs which were capitalized: (i)
severance costs related to Snyder employees of $9.6 million; (ii) professional
fees of $5.7 million; (iii) provisions for certain lease obligations for
duplicate or unused facilities of $2.5 million; and (iv) other transition costs
of $1.6 million. Subsequently the Company increased the accruals for
professional fees and other transition costs by $0.3 million and $1.0 million,
respectively. At December 31, 1999, after deducting payments made, the Company's
accrued liabilities included $2.9 million with respect to severance costs and
$0.3 million of costs with respect to lease obligations for duplicate or unused
facilities.

                                       41
<PAGE>
SANTA FE SNYDER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)

The following unaudited pro forma condensed income statement information has
been prepared to give effect to the Merger as if such transaction had occurred
at the beginning of the period presented. The historical results of operations
have been adjusted to reflect the difference between Snyder Oil's historical
depletion, depreciation and amortization and such expense calculated based on
the value allocated to the assets acquired in the Merger. The information
presented is not necessarily indicative of the results of future operations of
the merged companies.
<TABLE>
<CAPTION>
                                        Year Ended December 31,
----------------------------------------------------------------
                                         1999             1998
----------------------------------------------------------------
<S>                                     <C>              <C>
(In millions of dollars, except per
share data)                                   (Unaudited)
Revenues                                  550.1            429.0
Net loss before extraordinary items      (144.2)          (140.2)
Net loss                                 (148.4)          (140.2)
Basic and diluted loss per share           (.84)            (.82)
</TABLE>

NOTE 3.  SPIN OFF OF MONTEREY RESOURCES, INC.  In 1996 the Company formed
Monterey to assume the operations of the Company's Western Division (the
"Western Division"), which conducted the Company's oil and gas operations in
the State of California. In November 1996 Monterey sold 9.3 million shares of
its common stock (17.2%) in an initial public offering. On July 25, 1997 the
Company distributed pro rata to its common shareholders all of the shares of
Monterey's common stock that it owned (82.8% of the outstanding Monterey common
stock) by means of a tax-free distribution. Pursuant to the terms of a letter
agreement dated June 13, 1996, upon consummation of the Spin Off, fees
aggregating $3.3 million were paid by Monterey to Chase Securities Inc. and
Petrie Parkman & Co., Inc. In addition, a fee of $0.4 million was paid to GKH
Partners, L.P., of which $0.2 million was paid by the Company and $0.2 million
was paid by Monterey. One of the Company's former directors was associated with
Chase Securities and another current director is associated with GKH Partners.

Monterey agreed to indemnify the Company if at any time during the one-year
period subsequent to consummation of the Spin Off (or if certain tax legislation
is enacted and is applicable, such longer period as is required for the Spin Off
to be tax free to the Company) Monterey takes certain actions, the effects of
which result in the Spin Off being taxable to the Company. The Company does not
believe that any such actions occurred during the one-year period that would
have had such effect on the Spin Off.

Prior to the Spin Off, Monterey purchased all the common stock of McFarland
Energy, Inc. ("McFarland Energy") for $106.2 million in cash and $2.3 million
of assumed debt.

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

                                       42
<PAGE>
SANTA FE SNYDER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)

The following table sets forth certain financial information for the Company, on
an unaudited pro forma basis assuming that the Spin Off occurred January 1, 1997
(in millions of dollars, except per share amounts):
<TABLE>
<CAPTION>
                                              YEAR ENDED
                                         DECEMBER 31, 1997 (1)
---------------------------------------------------------------
                                              (Unaudited)
<S>                                     <C>
Revenues                                         333.5
Income from operations                            60.3
Net income                                        35.0
Earnings to common shares                         23.0
Earnings per common share, basic and
  diluted                                         0.23
</TABLE>

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

(1) Costs and expenses related to the Spin Off of Monterey have been excluded
    from the year ended December 31, 1997 pro forma presentations as follows:
    (i) $2.0 million in pension curtailments and (ii) $0.6 million in
    compensation expenses; and (iii) $1.1 million in Spin Off related costs and
    expenses.

The Company recorded the following reductions on the balance sheet in 1997 as a
result of the Spin Off of Monterey (in millions of dollars):

<TABLE>
<S>                                    <C>
Current assets                              45.7
Property and equipment, net                537.5
Other assets                                 1.6
Current liabilities                         49.0
Long-term debt                             277.3
Other long-term obligations                  3.8
Deferred income taxes                       74.2
Minority interest in Monterey
  Resources, Inc.                           31.1
Shareholders' equity                       149.4
</TABLE>

NOTE 4.  EARNINGS PER SHARE.  The following table sets forth the components of
the Company's basic and diluted earnings per share calculations:

<TABLE>
<CAPTION>
                                                             WEIGHTED
                                        EARNINGS (LOSS)       AVERAGE
                                        ATTRIBUTABLE TO    COMMON SHARES     PER SHARE
                                         COMMON SHARES      OUTSTANDING        AMOUNT
----------------------------------------------------------------------------------------
                                         ($/millions)       (millions)      (in dollars)
<S>                                     <C>                <C>              <C>
Year Ended December 31, 1999
     Basic and diluted before
       extraordinary item                    (120.7)           152.9             (.79)
     Basic and
       diluted -- extraordinary item           (4.2)           152.9             (.03)
                                        ---------------                     ------------
     Basic and diluted after
       extraordinary item                    (124.9)           152.9             (.82)
                                        ===============                     ============
Year Ended December 31, 1998
     Basic and diluted                        (98.7)           102.6             (.96)
                                        ===============    =============    ============
Year Ended December 31, 1997
     Basic                                     42.7             98.6
     Effect of dilutive stock options       --                   1.8
     Effect of dilutive performance
       awards                               --                    .2
                                        ---------------    -------------
     Basic and diluted                         42.7            100.6              .43
                                        ===============    =============    ============
</TABLE>

                                       43
<PAGE>
SANTA FE SNYDER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)

The Company had 5.1 million, 5.2 million and 1.4 million stock options
outstanding in 1999, 1998 and 1997, respectively, which were not included in the
computation of diluted earnings per share because the exercise price of these
options was greater than the average market price of the common shares. The
Company also had convertible preferred stock in 1997 and 1996 which was
antidilutive. The Company reported a loss in 1999 and 1998 and, accordingly, the
potential effects of dilutive stock options and performance awards were not
included in the computation of diluted earnings per share as they are
antidilutive.

NOTE 5.  SANTA FE ENERGY TRUST.  The Santa Fe Energy Trust (the "Trust") was
formed in 1992 to hold 6.3 million Depository Units ("Depository Units"), each
consisting of beneficial ownership of one unit of undivided interest in the
Trust and a $20 face amount beneficial ownership interest in a $1,000 face
amount zero coupon United States Treasury obligation maturing on or about
February 15, 2008, when the Trust will be liquidated. The assets of the Trust
consist of certain oil and gas properties conveyed by the Company.

For any calendar quarter ending on or prior to December 31, 2002, the Trust will
receive additional support payments to the extent that it needs such payments to
distribute $0.39 per Depository Unit per quarter. The source of such support
payments is limited to the Company's remaining royalty interest in certain of
the properties conveyed to the Trust. The aggregate amount of the additional
royalty payments (net of any amounts recouped) is limited to $19.4 million on a
revolving basis. If such support payments are made, certain proceeds otherwise
payable to the Trust in subsequent quarters may be reduced to recoup the amount
of such support payments. Through the end of 1999, the Trust had received
support payments totalling $4.2 million and the Company had recouped $3.9
million of such payments. In the first quarter of 1999 the Company recouped the
remaining $0.3 million of support payments. Depending on various factors, such
as sales volumes and prices and the level of operating costs and capital
expenditures incurred, proceeds payable to the Trust with respect to operations
in subsequent quarters may not be sufficient to make the required quarterly
distributions. In such instances the Company would be required to make support
payments. At December 31, 1999 and 1998, accounts payable included $3.4 million
and $2.6 million, respectively, due to the Trust.

NOTE 6.  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's accrued accounts payable with respect to capital expenditures
increased by $45.2 million in 1999, $29.9 million in 1998 and $7.2 million in
1997.

The following balances represent noncash adjustments to the Company's
Consolidated Balance Sheet at December 31, 1999 related to the Merger (in
millions of dollars):

<TABLE>
<S>                                     <C>
Accounts receivable                        15.4
Inventories                                 1.0
Accounts payable                           15.2
Interest payable                            5.9
Deferred revenues                           2.8
Long-term debt                            219.0
Other assets and liabilities               11.5
Common stock and paid-in capital          412.1
</TABLE>

                                       44
<PAGE>
SANTA FE SNYDER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)

The following balances represent noncash adjustments to the Company's
Consolidated Balance Sheet as of December 31, 1998, related to the acquisition
of an additional interest in the Tuban Production Sharing Contract on the island
of Java in Indonesia from Total S.A. (in millions of dollars):

<TABLE>
<CAPTION>
                                        TOTAL S.A.
                                        ACQUISITION
---------------------------------------------------
<S>                                     <C>
Accounts receivable                         2.9
Inventories                                 1.9
Other assets                                3.4
Accounts payable                            3.4
Other long-term obligations                  .1
Deferred income taxes                        .9
</TABLE>

The following balances represent noncash adjustments to the Company's
Consolidated Balance Sheet as of December 31, 1997, related to Monterey's
acquisition of McFarland Energy, the Company's Spin Off of Monterey and the
Company's acquisition of interests in the Tupungato field in Argentina (in
millions of dollars):

<TABLE>
<CAPTION>
                                         MCFARLAND     MONTEREY     TUPUNGATO
                                        ACQUISITION    SPIN OFF    ACQUISITION     TOTAL
------------------------------------------------------------------------------------------
<S>                                     <C>            <C>         <C>           <C>
Accounts receivable                          7.0         (38.4)        1.3           (30.1)
Inventories                                   .3          (2.4)         .7            (1.4)
Accounts payable                              .5         (27.6)         .6           (26.5)
Income taxes payable                       --               .1       --                 .1
Interest payable                           --             (6.3)      --               (6.3)
Other assets and liabilities                ( .3)         10.1         1.2            11.0
Long-term debt                               2.3        (277.3)      --             (275.0)
</TABLE>

NOTE 7.  INVESTMENTS.  As a result of the Merger, the Company acquired interests
in two foreign energy companies which are listed on the London Stock Exchange.
The Company's investment in Cairn Energy plc was sold in November 1999 for $24.7
million. The Company's investment in SOCO International plc ("SOCO") is
classified as an available-for-sale security and such investment is reported at
fair value, with unrealized gains and losses excluded from earnings and reported
in Comprehensive Income. The Company's cost basis in its investment in SOCO is
$7.0 million and at December 31, 1999 the fair value of such securities was $9.1
million. Accordingly, 1999 Comprehensive Income includes an unrealized gain of
$2.1 million ($1.3 after deducting $0.8 million in deferred income taxes). The
Company's investment in SOCO is included in Other Assets in the Consolidated
Balance Sheet at December 31, 1999.

NOTE 8.  INCOME TAXES.  Tax years 1997 and 1998 are currently under audit.
Certain state franchise tax returns for years 1984 through 1990 are currently
under audit. In November 1996, the Company and Monterey executed a tax sharing
agreement, which transferred to Monterey all obligations attributable to these
franchise tax liabilities for such years.

Total pretax income (loss) for the years ended December 31, 1999, 1998 and 1997
was taxed under the following jurisdictions (in millions of dollars):

<TABLE>
<CAPTION>
                                         1999       1998       1997
----------------------------------------------------------------------
<S>                                    <C>        <C>        <C>
Domestic                                  (193.4)    (126.1)      88.0
Foreign                                     28.1      (36.8)       7.6
                                       ---------  ---------  ---------
                                          (165.3)    (162.9)      95.6
                                       =========  =========  =========
</TABLE>
                                       45
<PAGE>
SANTA FE SNYDER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)

The Company's total income tax benefit (expense) for the years ended December
31, 1999, 1998 and 1997 consisted of the following items (in millions of
dollars):

<TABLE>
<CAPTION>
                                         1999       1998       1997
----------------------------------------------------------------------
<S>                                    <C>        <C>        <C>
Current
  U.S. federal                               6.3       11.2       (2.3)
  State                                       .1        2.1       (1.4)
  Foreign                                   (4.8)      (1.9)      (5.2)
                                       ---------  ---------  ---------
                                             1.6       11.4       (8.9)
                                       ---------  ---------  ---------
Deferred
     U.S. federal                           55.9       41.6      (26.7)
     State                                --         --            (.7)
     Foreign                               (12.9)      11.2         .1
                                       ---------  ---------  ---------
                                            43.0       52.8      (27.3)
                                       ---------  ---------  ---------
                                            44.6       64.2      (36.2)
                                       =========  =========  =========
</TABLE>

The Company's deferred income tax (assets) liabilities at December 31, 1999 and
1998 are composed of the following differences between financial and tax
reporting (in millions of dollars):

<TABLE>
<CAPTION>
                                         1999       1998
-----------------------------------------------------------
<S>                                    <C>        <C>
Capitalized costs and write-offs           151.6       47.2
Foreign deferred liability                    .9     --
                                       ---------  ---------
Gross deferred tax liability               152.5       47.2
                                       ---------  ---------
Accruals not currently deductible for
  tax purposes                              (5.0)      (3.0)
Alternative minimum tax carryforwards      (18.8)     (16.9)
Net operating loss carryforwards           (50.7)     (26.6)
Foreign deferred asset                    --          (14.1)
Other                                        (.6)       (.1)
                                       ---------  ---------
Gross deferred tax assets                  (75.1)     (60.7)
                                       ---------  ---------
Deferred tax (asset) liability              77.4      (13.5)
                                       =========  =========
</TABLE>

                                       46
<PAGE>
SANTA FE SNYDER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)

A reconciliation of the Company's total income tax benefit (expense) computed by
applying the statutory U.S. federal income tax rate to the Company's total
income (loss) before income taxes minority interest and extraordinary item for
the years ended December 31, 1999, 1998 and 1997 is presented in the following
table (in millions of dollars):

<TABLE>
<CAPTION>
                                         1999       1998       1997
----------------------------------------------------------------------
<S>                                    <C>        <C>        <C>
U.S. federal income tax benefit
(expense) at statutory rate                 57.8       57.0      (33.4)
Increase (reduction) resulting from:
  State income taxes, net of federal
     effect                                   .1        1.4       (1.4)
  Foreign income taxes in excess of
     (less than) U.S. rate                  (5.8)      (2.8)      (2.4)
  U.S. tax on foreign reinvested
     earnings                                (.8)       (.6)       (.5)
  Prior period tax adjustments              (6.7)       9.3     --
  Other                                   --            (.1)       1.5
                                       ---------  ---------  ---------
                                            44.6       64.2      (36.2)
                                       =========  =========  =========
</TABLE>

As a result of the Merger, the Company succeeded to net operating loss
carryforwards of $97.6 million. Such loss carryforwards are subject to Internal
Revenue Code Section 382 limitations, which annually limit the amount of taxable
income that can be offset by such carryforwards. Certain changes in the
Company's shareholders may impose additional limitations. The majority of these
carryforwards expire between 2006 and 2010.

NOTE 9.  FINANCING AND DEBT.  Long-term debt at December 31, 1999 and 1998
consisted of the following balances (in millions of dollars):

<TABLE>
<CAPTION>
                                                 1999                      1998
----------------------------------------------------------------------------------------
                                        CURRENT     LONG-TERM     CURRENT     LONG-TERM
----------------------------------------------------------------------------------------
<S>                                     <C>         <C>           <C>         <C>
11% Senior Subordinated Debentures        --           --           --            99.6
8.05% Senior Notes                        --           123.6        --           --
8.75% Senior Subordinated Notes           --           175.0        --           --
Lines of credit borrowings                --           330.8        --           231.0
                                        --------    ----------    --------    ----------
                                          --           629.4        --           330.6
                                        ========    ==========    ========    ==========
</TABLE>

Aggregate total maturities of long-term debt during the next five years are as
follows: 2000 -- none; 2001 -- none; 2002 -- none; 2003 -- none; and
2004 -- $454.4 million.

In connection with the Merger, the Company assumed Snyder Oil's $175.0 million
of 8.75% Senior Subordinated Notes (the "Subordinated Notes") due June 15,
2007. The Subordinated Notes are redeemable by the Company on or after June 15,
2002, initially at 104.375% of principal and at prices declining to 100% of
principal on or after June 15, 2005. The Subordinated Notes are general
unsecured obligations of the Company. Also, in connection with the Merger, the
Company assumed $44.0 million of long-term debt outstanding under the terms of
Snyder Oil's revolving credit facility, which was repaid with funds borrowed
under the Credit Facility.

Concurrent with the closing of the Merger the Company entered into a $500.0
million credit facility (the "Credit Facility") which was amended in November
1999 to increase the amount available to $600.0 million. The Credit Facility
consists of a $450.0 million five-year tranche which expires May 2004 and a
renewable $150.0 million 364 day tranche. The Credit Facility bears interest, at
the Company's option, at LIBOR or prime rates plus applicable margins dependent
upon the Company's credit rating and certain financial ratios. Borrowings under
the Credit Facility are unsecured. At December 31, 1999, the Company had $320.0
million in borrowings outstanding under the Credit Facility which were

                                       47
<PAGE>
SANTA FE SNYDER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)

classified as long-term debt on the balance sheet since the Company had the
ability and intended to refinance such amounts on a long-term basis. The
weighted average interest rate with respect to borrowings under the Credit
Facility during 1999 was 6.3%.

At the time the Company entered into the Credit Facility, the Company had a
revolving credit agreement (the "Credit Agreement") which matured May 15, 2003
and permitted the Company to obtain revolving credit loans and issue letters of
credit having a maximum aggregate amount of $335.0 million. Amounts outstanding
under the Credit Agreement was refinanced under the terms of the Credit
Facility.

In June 1999 the Company issued $125.0 million of 8.05% Senior Notes due 2004
(the "Senior Notes"). The Senior Notes were issued for 98.758% of face value
and the Company received total proceeds of $121.6 million after deducting
related costs and expenses of $1.9 million. The Senior Notes, which mature June
15, 2004, are redeemable, upon not less than thirty nor more than sixty days
notice, as a whole or in part, at the option of the Company at a redemption
price equal to the sum of (i) 100% of the principal amount thereof, (ii) the
applicable make-whole premium as determined by an independent investment banker
and (iii) accrued and unpaid interest. The Senior Notes are general unsecured
obligations of the Company.

At the time of the issuance of the Senior Notes, the Company had outstanding
$100.0 million of 11% Senior Subordinated Debentures (the "Debentures") which
matured May 15, 2004 and were redeemable at the option of the Company at prices
set forth in the indenture for the Debentures. A portion of the net proceeds
from the Senior Notes was used to retire the Debentures and to pay $5.5 million
in accrued interest and prepayment penalties due upon retirement of such debt.

The Credit Facility and the indentures for the Senior Subordinated Notes and the
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 or repurchase capital stock. Under the most restrictive of these
covenants, at December 31, 1999 the Company could incur $615.8 million of
additional indebtedness, of which $280.0 million could be borrowed under the
Credit Facility, and could pay dividends and/or repurchase common stock of up to
$83.1 million.

In addition to the Credit Facility, at December 31, 1999 the Company also had
two short-term uncommitted lines of credit which are used to meet short-term
cash needs. Under one line of credit the Company may borrow up to $20.0 million
and under the other line of credit the amount available (up to $25.0 million)
varies with the amount outstanding under the Credit Facility. Interest rates on
borrowings under these lines of credit are typically lower than rates paid under
the Credit Facility when compared to the prime rate, which would be required for
short-term (less than 30 days) borrowings. As of December 31, 1999, the Company
had $10.8 million in borrowings outstanding under these facilities, which were
classified as long-term debt on the balance sheet since the Company has the
ability and intends to refinance such amounts on a long-term basis.

In connection with the Senior Notes offering, the Company executed two forward
treasury lock agreements (the "Treasury Locks") to mitigate interest rate risk
during the issuance of the Senior Notes. Upon the issuance of the Senior Notes,
the Treasury Locks were terminated resulting in proceeds to the Company totaling
$3.1 million which amount has been deferred and will be recognized as a
component of interest expense over the life of the Senior Notes.

In connection with the retirement of certain debt in 1999, the Company recorded
a $4.2 million extraordinary loss, net of $2.3 million of taxes. The
extraordinary loss represents the write-off of certain debt issue costs and
prepayment penalties pertaining to the retirement of the Debentures, net of
related tax benefits.

                                       48
<PAGE>
SANTA FE SNYDER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)

At December 31, 1998, the Company had $225.0 million in borrowings outstanding
under the Credit Agreement and $6.0 million in borrowings outstanding under
short term lines of credit. Such borrowings were classified as long-term debt on
the balance sheet since the Company had the ability and intended to refinance
such amounts on a long-term basis.

The fair value of the Company's long-term debt at December 31, 1999 and 1998 was
$627.4 million and $336.4 million, respectively. The fair value of the Company's
8.05% Senior Notes, 8.75% Senior Subordinated Notes and 11% Senior Subordinated
Debentures is based on market prices. With respect to the Company's
floating-rate debt, the carrying amount approximates fair value. The fair value
set forth herein is not representative of the amount that could be realized or
settled, nor does the fair value amount consider tax consequences, if any, of
realization or settlement.

NOTE 10.  SEGMENT INFORMATION.  The principal business of the Company consists
of the exploration, development and acquisition of oil and gas properties and
the production and sale of crude oil and liquids and natural gas. The Company
has determined that its reportable segments are those that are based on the
Company's method of internal reporting, which disaggregates its business by
geographic area. The Company's reportable segments are the United States,
Southeast Asia, South America, and West Africa.

The accounting policies of the segments are the same as those described in the
"Summary of Significant Accounting Policies." The Company evaluates the
performance of its segments and allocates resources based principally on
operating income or loss.

                                       49
<PAGE>
SANTA FE SNYDER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)

The table below presents information about the reported segments for the years
ending December 31, 1999, 1998 and 1997. Other reconciling items include other
corporate income and expenses, hedging activities and overhead costs not
allocated to specific geographic areas. Asset information by reportable segment
is not presented because such information is not a factor used by management to
evaluate the performance of the segments.
<TABLE>
<CAPTION>
                                                                  INCOME (LOSS)
                                                                  BEFORE INCOME      DEPLETION
                                                                 TAXES, MINORITY    DEPRECIATION
                                                    OPERATING     INTEREST AND      AMORTIZATION       GAIN (LOSS)
                                         TOTAL       INCOME       EXTRAORDINARY         AND         ON DISPOSITION OF
                                        REVENUES     (LOSS)           ITEM           IMPAIRMENT          ASSETS
---------------------------------------------------------------------------------------------------------------------
                                                                    (millions of dollars)
<S>                                     <C>         <C>          <C>                <C>             <C>
1999
United States                             365.4        (77.9)          (77.9)           325.5               1.8
Southeast Asia                             93.0         25.1            25.1             19.2           --
South America                              43.6         (8.0)           (8.0)            26.2              (2.5)
West Africa                                21.2          3.5             3.5              4.9           --
Other reconciling items                   (12.9)       (71.5)         (108.0)             6.4               (.3)
                                        --------    ---------    ---------------    ------------    ----------------
                                          510.3       (128.8)         (165.3)           382.2              (1.0)
                                        ========    =========    ===============    ============    ================
1998
United States                             194.3        (78.8)          (78.8)           179.4              (1.5)
Southeast Asia                             53.5        (14.5)          (14.5)            20.4           --
South America                              33.8         (6.2)           (6.2)            13.1           --
West Africa                                 7.7        (25.5)          (25.5)             2.4           --
Other reconciling items                     1.4        (29.3)          (37.9)             8.6           --
                                        --------    ---------    ---------------    ------------    ----------------
                                          290.7       (154.3)         (162.9)           223.9              (1.5)
                                        ========    =========    ===============    ============    ================
1997
United States                             443.7        127.5           127.5            106.0               3.6
Southeast Asia                             27.8         (2.9)           (2.9)             7.3           --
South America                              40.7         13.4            13.4              9.2           --
West Africa                               --            (1.7)           (1.7)             0.2           --
Other reconciling items                     1.9        (26.1)          (40.7)             5.1           --
                                        --------    ---------    ---------------    ------------    ----------------
                                          514.1        110.2            95.6            127.8               3.6
                                        ========    =========    ===============    ============    ================
</TABLE>

For the year ended December 31, 1999 no individual purchaser accounted for 10%
of the Company's consolidated revenues. For the year ended December 31, 1998
revenues from two purchasers accounted for 13% and 12%, respectively, of the
Company's consolidated revenues and for the year ended December 31, 1997 one
purchaser accounted for 11% of consolidated revenues. All of these amounts
represent sales in the United States segment.

The following table represents enterprise-wide information for long-lived
assets. These assets include net property and equipment and other long-term
assets (in millions of dollars):
<TABLE>
<CAPTION>
                                           December 31,
-----------------------------------------------------------
                                         1999       1998
-----------------------------------------------------------
<S>                                    <C>        <C>
United States                            1,352.0      419.4
Southeast Asia                             166.2      151.9
South America                              130.2      141.8
West Africa                                 41.3       29.9
                                       ---------  ---------
                                         1,689.7      743.0
                                       =========  =========
</TABLE>

                                       50
<PAGE>
SANTA FE SNYDER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)

NOTE 11.  SHAREHOLDERS' EQUITY.  CONVERTIBLE PREFERRED STOCK, 7% SERIES.  In
1997, the Company converted the 1.2 million outstanding shares of Convertible
Preferred Stock, 7% Series (the "7% Preferred") for 2.3 million shares of
common stock. The conversion of the 7% Preferred resulted in a non-cash
reduction in earnings to common shares which is reflected as an $8.4 million
convertible preferred repurchase premium in the Statement of Operations.

$.732 SERIES A CONVERTIBLE PREFERRED STOCK.  In the second quarter of 1997 the
Company converted all 10.7 million outstanding shares of its $.732 Series A
Convertible Preferred Stock (the "DECS") into 9.1 million shares of common
stock. There was no charge to earnings as a result of the conversion of the
DECS.

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

COMMON STOCK.  At December 31, 1999 the Company had 500.0 million shares
authorized, 184.4 million shares issued, 182.9 million shares outstanding and
1.5 million shares in treasury. At December 31, 1998 the Company had 200.0
million shares authorized, 103.0 million shares issued, 102.2 million shares
outstanding and 0.8 million shares in treasury.

TREASURY STOCK.  The Company's Board of Directors has authorized the Company to
buy back up to $50.0 million of its common stock to meet the requirements of
outstanding stock options and to satisfy the stock requirements of employee
benefit plans. In 1999, 1998 and 1997, the Company purchased 1.6 million shares,
1.3 million shares and 0.1 million shares, for $11.6 million, $11.6 million and
$0.5 million, respectively. In 1999 and 1998 the Company issued 0.9 million
shares and 0.6 million shares, respectively, of treasury stock in connection
with outstanding stock options and to meet certain requirements with respect to
employee benefit plans.

NOTE 12.  STOCK OPTION PLANS.  The Company has granted options and awards in the
form of Restricted Stock, Bonus Stock, and Phantom Units, as such terms may be
defined in the applicable plans, to its employees, officers and directors. Under
the terms of the Santa Fe Snyder 1990 Incentive Stock Compensation Plan (the
"1990 Plan") options and awards have been granted to officers, directors and
key employees. Under the terms of the Santa Fe Snyder 1995 Incentive Stock
Compensation Plan (the "1995 Plan"), the Company may grant options and awards
with respect to not more than 1,000,000 shares of common stock per year to
employees, other than executive officers, and directors. Under the terms of the
Santa Fe Snyder 1999 Stock Compensation Retention Plan (the "Retention Plan"),
awards in the form of Phantom Units may be made to certain executive officers.
In addition, in connection with the Merger one-time grants were made to certain
former employees and directors of Snyder Oil to replace options held under
Snyder Oil's stock option plans. Collectively, these plans are referred to as
the "Plans".

Options granted under the terms of the 1990 Plan and the 1995 Plan have been
granted at the average market price on the date of grant and have a ten-year
term with vesting periods ranging from six months to three years. Awards under
the Retention Plan convert into common shares two years from the date of grant.
The options granted to the former Snyder Oil employees and directors are vested
and expire under the same terms as under the Snyder Oil stock option plans. As
of December 31, 1999 no additional options or awards can be granted under the
1990 Plan, no shares were available for options

                                       51
<PAGE>
SANTA FE SNYDER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)

or awards under the 1995 Plan and 0.1 million Phantom Units were available for
awards under the Retention Plan.

The following table summarizes the activity with respect to options and awards
outstanding under the Plans during the years ended December 31, 1999, 1998 and
1997 (per share amounts in dollars):
<TABLE>
<CAPTION>
                                                1999                       1998                       1997
--------------------------------------------------------------------------------------------------------------------
                                                     WEIGHTED                   WEIGHTED                   WEIGHTED
                                                      AVERAGE                   AVERAGE                    AVERAGE
                                         SHARES      EXERCISE      SHARES       EXERCISE      SHARES       EXERCISE
                                       (THOUSANDS)     PRICE     (THOUSANDS)     PRICE      (THOUSANDS)     PRICE
--------------------------------------------------------------------------------------------------------------------
<S>                                    <C>           <C>         <C>           <C>          <C>           <C>
Outstanding at beginning of year         9,386.2        8.01       8,068.5         7.69       5,392.0        12.07
Grants                                   1,891.4        7.54       1,783.6         9.68         873.1         9.73
Merger grants                            4,451.0        7.74        --            --           --            --
Revaluation due to Spin Off               --           --           --            --          3,119.0         7.27
Cancellations                             (322.6)       9.81        (222.0)       11.29        (919.7)       11.31
Exercises                                 (976.2)       7.33        (243.9)        6.84        (395.9)        7.23
                                        --------                  --------                   --------
Outstanding at end of year              14,429.8        7.90       9,386.2         8.01       8,068.5         7.69
                                        ========                  ========                   ========
Exercisable at end of year              13,083.8                   6,560.9                    6,037.3
                                        ========                  ========                   ========
Weighted average fair value of
  options granted during the year                       4.85                       4.88                       5.73
</TABLE>

The following table summarizes certain information with respect to options
outstanding under the Plans at December 31, 1999 (per share amounts in dollars):
<TABLE>
<CAPTION>
                                       Options Outstanding                   Options Exercisable
---------------------------------------------------------------------------------------------------
                                             WEIGHTED       WEIGHTED                      WEIGHTED
                                              AVERAGE        AVERAGE                       AVERAGE
                                             REMAINING      EXERCISE                      EXERCISE
                              SHARES        CONTRACTUAL       PRICE         SHARES          PRICE
RANGE OF EXERCISE PRICES    (THOUSANDS)        LIFE         PER SHARE     (THOUSANDS)     PER SHARE
---------------------------------------------------------------------------------------------------
<S>                         <C>             <C>             <C>           <C>             <C>
2.75 to 5.99                  3,480.9        3.6 years         5.27         3,480.9          5.27
6.00 to 10.99                 9,600.9        5.5 years         8.22         8,254.9          8.29
11.00 to 14.25                1,348.0        4.7 years        12.41         1,348.0         12.32
                            -----------                                   -----------
                             14,429.8                                      13,083.8
                            ===========                                   ===========
</TABLE>

During 1998 and 1997 the Company granted 0.1 million and 0.2 million,
respectively, shares of restricted stock to certain employees and directors.

In each of 1998 and 1997 the Company issued 0.2 million shares of restricted
stock under its incentive compensation plan. Such restricted shares vested
one-third per year over a three year period and the value of such shares at the
grant date was being amortized over the vesting period. The unamortized portion
of the awards at December 31, 1998 was $1.5 million. As a result of the Merger,
all such shares vested and the unamortized portion of the awards was charged to
expense.

As a result of the Spin Off of Monterey in July 1997, all stock options
outstanding at that time were adjusted to reflect the effect of the transaction
on the value of the Company's common stock. The anti-

                                       52
<PAGE>
SANTA FE SNYDER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)

dilution formula utilized follows the Internal Revenue Service approved
guidelines for adjusting Qualified Incentive Stock Options and took into account
the average sales prices for the Company's common stock for a period of time
before and after the Spin Off. As a result of the adjustment the number of
options outstanding increased by a factor of 1.7045 and the strike price was
reduced accordingly in order to preserve the value of either in the money or out
of the money spread in existence at the time. The Company will receive the same
overall consideration for the underlying securities upon exercise of the option.
All outstanding Phantom Units were also adjusted utilizing the same formula. All
other terms and conditions of the options and the Phantom Units remained
unchanged.

The Company has elected to continue to account for stock-based compensation
costs in accordance with APB Opinion No. 25. If the Company had elected to adopt
the fair value method of accounting for options under SFAS No. 123, earnings
(loss) attributable to common shares and the related per share amounts would
have been reduced as is reflected by the pro forma amounts in the following
table (in millions of dollars, except per share data):
<TABLE>
<CAPTION>
                                           Year Ended December 31,
----------------------------------------------------------------------
                                         1999       1998       1997
----------------------------------------------------------------------
<S>                                    <C>        <C>        <C>
AS REPORTED
  Earnings (loss) attributable to
     common shares                        (124.9)     (98.7)      42.7
  Earnings (loss) per common share,
     basic and diluted                      (.82)      (.96)       .43
PROFORMA
  Earnings (loss) attributable to
     common shares                        (133.3)    (102.4)      41.4
  Earnings (loss) per common share,
     basic and diluted                      (.87)     (1.00)       .42
</TABLE>

The fair value of each option grant is estimated on the date of grant using the
Black-Scholes option-pricing model with the following assumptions: (i) expected
dividend yield - 0.0%; (ii) expected stock price volatility - 35% to 42%; (iii)
risk-free interest rate - 5% to 7%; and (iv) expected life of options - 10
years.

NOTE 13.  PENSION AND OTHER POSTRETIREMENT BENEFITS.  The following disclosures
regarding pension benefits represent the combination of three plans the Company
offers its employees. These plans include (i) a defined benefit retirement plan
(the "SFER Plan") covering substantially all salaried employees, (ii) a
nonqualified supplemental plan (the "Supplemental Plan") which pays benefits
to participants in the SFER Plan in those instances where the SFER Plan formula
produces a benefit in excess of limits established by ERISA and The Tax Reform
Act of 1986 and (iii) a pension plan for certain persons employed in foreign
locations (the "Foreign Plan"). Disclosures regarding other benefits represent
health care and life insurance benefits for substantially all employees who
retire under the provisions of a Company-sponsored retirement plan and their
dependents.

                                       53
<PAGE>
SANTA FE SNYDER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)

The following table sets forth the status of those plans and benefits described
above at December 31, 1999 and 1998 (in millions of dollars, except as noted):
<TABLE>
<CAPTION>
                                         Pension Benefits       Other Benefits
---------------------------------------------------------------------------------
                                         1999       1998       1999       1998
---------------------------------------------------------------------------------
<S>                                    <C>        <C>        <C>        <C>
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of
  year                                      48.7       42.2        8.1        6.6
Service cost                                 2.4        1.7         .7         .4
Interest cost                                3.3        3.1         .6         .5
Contribution by plan participants         --         --         --             .1
Merger                                       3.1     --             .8     --
Actuarial (gain) loss                       (2.0)       3.8         .6        1.0
Benefits paid                               (2.2)      (2.1)       (.7)       (.5)
                                       ---------  ---------  ---------  ---------
Benefit obligation at end of year           53.3       48.7       10.1        8.1
                                       ---------  ---------  ---------  ---------
CHANGE IN PLAN ASSETS
Fair value of plan assets at
  beginning of year                         35.2       37.1     --         --
Actual return on plan assets                 6.0         .2     --         --
Company contribution                          .1     --             .6         .4
Contribution by plan participants         --         --             .1         .1
Benefits paid                               (2.2)      (2.1)       (.7)       (.5)
                                       ---------  ---------  ---------  ---------
Fair value of plan assets at end of
  year                                      39.1       35.2     --         --
                                       ---------  ---------  ---------  ---------
Funded status                              (14.2)     (13.5)     (10.1)      (8.1)
Contributions                                 .1     --             .1         .1
Unrecognized net (gain) loss                 (.5)       4.4         .8         .2
Unrecognized prior service cost               .4         .5     --         --
Unrecognized net transition (asset)
  obligation                                 (.4)       (.5)       2.1        2.3
                                       ---------  ---------  ---------  ---------
Prepaid (accrued) benefit cost             (14.6)      (9.1)      (7.1)      (5.5)
                                       =========  =========  =========  =========
WEIGHTED AVERAGE ASSUMPTIONS AT
  YEAR - END
Discount rate                              7.50%      6.75%      7.50%      6.75%
Expected return on plan assets             9.50%      9.50%
Rate of compensation increase              4.75%      4.75%      4.75%      4.75%
Health care trend rate                                           5.50%      6.00%

EFFECTS OF CHANGES IN ASSUMED HEALTH
  CARE COST TREND RATE
Effect of a one percentage point
  increase
  Effect on postretirement benefit
    obligation                                                     1.0         .7
  Effect on total of service and
    interest cost components                                        .2         .1
Effect of a one percentage point
  decrease
  Effect on postretirement benefit
    obligation                                                     (.8)       (.6)
  Effect on total of service and
    interest cost components                                       (.2)       (.1)
</TABLE>

                                       54
<PAGE>
SANTA FE SNYDER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)
<TABLE>
<CAPTION>
                                              Pension Plan                 Other Benefits
----------------------------------------------------------------------------------------------
                                        1999      1998      1997      1999      1998      1997
----------------------------------------------------------------------------------------------
<S>                                     <C>       <C>       <C>       <C>       <C>       <C>
COMPONENTS OF NET PERIODIC BENEFIT
  COST
Service cost                            2.4       1.7       1.9        .7        .4        .5
Interest cost                           3.3       3.1       3.2        .6        .5        .5
Expected return on plan assets         (3.2)     (3.4)     (3.3)     --        --        --
Amortization of transition obligation   --        --        (.1)       .2        .2        .2
Amortization of loss (gain)             --        (.1)      --        --        --        --
Curtailment charges (credits)           --        --        (2.4)     --        --         .3
                                        ----      ----      ----      ----      ----      ----
Net periodic (benefit) cost             2.5       1.3       (.7)      1.5       1.1       1.5
                                        ====      ====      ====      ====      ====      ====
</TABLE>

The aggregate projected benefit obligation, the aggregate accumulated benefit
obligation and the aggregate fair value of plan assets for plans with benefit
obligations in excess of plan assets were $53.3 million, $44.5 million and $39.1
million, respectively, as of December 31, 1999 and $48.7 million, $40.0 million
and $35.2 million, respectively, as of December 31, 1998.

SAVINGS PLAN

The Company has a savings plan available to substantially all salaried employees
and intended to qualify as a deferred compensation plan under Section 401(k) of
the Internal Revenue Code (the "401(k) Plan"). The Company matches employee
contributions for amounts up to 4% of each employee's base salary. In addition,
if at the end of each fiscal year the Company's performance for such year has
exceeded certain predetermined criteria, each participant will receive an
additional matching contribution equal to 50% of the regular matching
contribution. The Company's contributions to the 401(k) Plan, which are made in
the form of the Company's common stock and charged to expense, totaled $1.6
million in 1999, $1.3 million in 1998 and $1.6 million in 1997.

The Company also has a savings plan with respect to certain personnel employed
in foreign locations. The plan is an unsecured creditor of the Company and at
December 31, 1999, and 1998 and 1997, the Company's liability with respect to
the plan totaled $0.4 million, $0.3 million and $0.2 million, respectively.

NOTE 14.  COMMITMENTS AND CONTINGENCIES.  OIL AND GAS HEDGING.  From time to
time the Company hedges a portion of its oil and gas sales to provide a certain
minimum level of cash flow from its sales of oil and gas. While the hedges are
generally intended to reduce the Company's exposure to declines in market price,
the Company's gain from increases in market price may be limited. The Company
uses various financial instruments whereby monthly settlements are based on
differences between the prices specified in the instruments and the settlement
prices of certain futures contracts quoted on the New York Mercantile Exchange
("NYMEX") or certain other indices. Generally, in instances where the
applicable settlement price is less than the price specified in the contract,
the Company receives a settlement based on the difference; in instances where
the applicable settlement price is higher than the specified price, the Company
pays an amount based on the difference. The instruments utilized by the Company
differ from futures contracts in that there is no contractual obligation which
requires or allows for the future delivery of the product. Gains or losses on
hedging activities are recognized in oil and gas revenues in the period in which
the hedged production is sold.

Crude oil sales hedges resulted in a $2.5 million decrease in revenues in 1999
and increases of $2.5 million and $2.2 million in 1998 and 1997, respectively.
At December 31, 1999, the Company had open crude oil sales hedges on an average
of 11,000 barrels per day through December 31, 2000. The instruments used have
an average floor of $20.20 per barrel and an average ceiling of $25.06 per
barrel.

                                       55
<PAGE>
SANTA FE SNYDER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)

Under the terms of the instruments, if the aggregate average of the applicable
daily settlement prices is below the floor, the Company will receive a
settlement based on the difference, and if the aggregate average of the
applicable daily settlement prices is above the ceiling, the Company will be
required to pay an amount based on the difference. Based on the December 31,
1999 settlement price of the applicable NYMEX futures contracts, the Company's
unrealized loss with respect to such hedges at December 31, 1999 was $1.8
million. The actual gains or losses realized by the Company from these hedges
may vary significantly due to the volatility of the futures markets and other
indices.

At January 31, 2000 the Company had open oil sales hedges on an average of
17,300 barrels per day through December 31, 2000. The instruments used have an
average floor of $20.19 per barrel and an average ceiling of $25.12 per barrel.

Natural gas sales hedges resulted in a $3.0 million reduction in revenues in
1999. The Company had no natural gas sales hedges in 1998 or 1997 and had no
open natural gas sales hedges at December 31, 1999. The Company has a long-term
gas swap agreement that was entered into by Snyder Oil in 1994 to lock in the
price difference between the Rocky Mountain and Henry Hub prices on a portion of
its Rocky Mountain gas production. The contract covers 20,000 MMBtus per day
through 2004. The long-term gas swap agreement had no effect on revenues in
1999. The unrealized gain with respect to the swap agreement at December 31,
1999 was $2.2 million.

CRUDE OIL SALES CONTRACTS.  In August 1999, the Company entered into a crude oil
forward sales contract under the terms of which the Company is to deliver a
total of 6.2 million barrels of crude oil to the purchaser, at specified monthly
volumes, during the period from October 1999 through August 2002. In
consideration the Company received a prepayment of $99.3 million, after
deducting arrangement and other related costs. The prepayment is recognized in
earnings when the crude oil is delivered. The balance of the prepayment related
to undelivered crude oil is reflected on the balance sheet under the caption
Deferred Revenues.

In January 2000, the Company entered into a crude oil forward sales contract
under the terms of which the Company is to deliver a total of 4.2 million
barrels of crude oil to the purchaser, at specified monthly volumes, during the
period from February 2000 through August 2002. In consideration the Company
received a prepayment of $74.6 million, after deducting arrangement and other
related costs. The prepayment will be recognized in earnings when the crude oil
is delivered. The balance of the prepayment related to undelivered crude oil
will be reflected on the consolidated balance sheet under the caption Deferred
Revenues. The proceeds from the prepayment were used to pay a portion of the
$160.0 million purchase price of certain proved oil and gas properties acquired
in January 2000.

ENVIRONMENTAL REGULATION.  The Company's oil and gas operations are subject to
stringent environmental regulation by government authorities. Such regulation
has increased the costs of planning, designing, drilling, installing, operating
and abandoning oil and gas wells and associated facilities. The Company has
expended significant financial and managerial resources to comply with such
regulations. Although the Company believes its operations and facilities are in
general compliance with applicable environmental regulations, the risk of
substantial costs and liabilities are inherent to 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 in the past, the Company intends to fund the future costs of
environmental compliance from operating cash flows.

OPERATING LEASES.  The Company has noncancellable agreements with terms ranging
from one to ten years to lease office space, office equipment and certain
production equipment in foreign locations. Minimum rental payments due under the
terms of these agreements are: 2000 - $22.3 million,

                                       56
<PAGE>
SANTA FE SNYDER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)

2001 - $16.0 million, 2002 - $9.4 million, 2003 - $5.0 million, 2004 - $4.8
million and $21.6 million thereafter. Rental expense under the terms of
noncancellable agreements totaled $17.3 million in 1999, $15.2 million in 1998
and $10.8 million in 1997.

OTHER MATTERS.  In connection with the development of the Sierra Chata gas field
in Argentina in which the Company has a 19.9% working interest, a gas contract
with "take-or-pay" and "delivery-to-pay" obligations was executed in 1994
with a gas distribution company.

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

                                       57
<PAGE>
SANTA FE SNYDER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)

NOTE 16.  SUMMARIZED QUARTERLY FINANCIAL DATA (UNAUDITED).
<TABLE>
<CAPTION>
                                         FIRST     SECOND      THIRD     FOURTH
                                        QUARTER    QUARTER    QUARTER    QUARTER     YEAR
------------------------------------------------------------------------------------------
                                              (millions of dollars, except as noted)
<S>                                     <C>        <C>        <C>        <C>        <C>
1999(a)
Revenues                                  68.2      112.3      157.0      172.8      510.3
Impairment of oil and gas properties      --        196.4       --         --        196.4
Merger related costs                      --         16.8       --         --         16.8
Gross profit (loss)(b)                    (6.8)    (191.5)      46.5       49.2     (102.6)
Loss (gain) on disposition of assets        .1         .1         .6         .2        1.0
Income (loss) from operations            (12.2)    (199.1)      40.0       42.5     (128.8)
Income (loss) before extraordinary
  items                                  (12.1)    (143.8)      16.4       18.8     (120.7)
Extraordinary item -- debt
  extinguishment costs                    --         (4.2)      --         --         (4.2)
Net income (loss)                        (12.1)    (148.0)      16.4       18.8     (124.9)
Earnings (loss) attributable to
  common shares                          (12.1)    (148.0)      16.4       18.8     (124.9)
Earnings (loss) attributable to
  common shares per share, basic and
  diluted (in dollars)(c)
     Earnings (loss) before
       extraordinary items                (.12)      (.99)       .09        .10       (.79)
     Extraordinary item                   --         (.03)      --         --         (.03)
     Earnings (loss) to common share      (.12)     (1.02)       .09        .10       (.82)
Weighted average shares outstanding
  (millions)                             102.2      145.3      178.8      184.2      152.9
1998
Revenues                                  68.8       77.7       75.8       68.4      290.7
Impairment of oil and gas properties      --         --         --         87.8       87.8
Gross profit (loss)(b)                     (.9)       5.3      (18.9)    (120.1)    (134.6)
Loss (gain) on disposition of assets      --          1.2         .2         .1        1.5
Income (loss) from operations             (5.3)        .7      (24.0)    (125.7)    (154.3)
Net Income (loss)                          (.3)        .4      (17.8)     (81.0)     (98.7)
Earnings (loss) attributable to
  common shares                            (.3)        .4      (17.8)     (81.0)     (98.7)
Earnings (loss) attributable to
  common shares per share, basic and
  diluted (in dollars)                    --         --         (.17)      (.79)      (.96)
Weighted average shares outstanding
  (millions)                             102.7      102.9      102.6      102.2      102.6
</TABLE>

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

(a) Includes the results of operations of the properties acquired in the Merger
    effective May 1, 1999.

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

(c) The sum of the per share amounts per quarter does not equal the year due to
    the changes in the average number of common shares outstanding.

                                       58
<PAGE>
SANTA FE SNYDER CORPORATION
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

OIL AND GAS RESERVES AND RELATED FINANCIAL DATA

Information with respect to the Company's oil and gas producing activities is
presented in the following tables. Reserve quantities as well as certain
information regarding future production and discounted cash flows were
determined by independent petroleum consultants, Ryder Scott Company, for all
years presented, with the exception of the Company's reserves on the Jabung
Block in Southeast Asia at December 31, 1998, which were prepared by the
Company.

The following estimates of proved and proved developed reserve quantities and
related standardized measure of discounted net cash flow are estimates only, and
do no purport to reflect realizable values or fair market values of the
Company's reserves. The Company emphasizes that reserve estimates are inherently
imprecise and that estimates of new discoveries are more imprecise than those of
producing oil and gas properties. Accordingly, these estimates are expected to
change as future information becomes available.

OIL AND GAS RESERVES

The following table sets forth the Company's net proved oil and gas reserves at
December 31, 1996, 1997, 1998 and 1999 and the changes in net proved oil and gas
reserves for the years ended December 31, 1997, 1998 and 1999.
<TABLE>
<CAPTION>
                                                Crude Oil and Liquids (MMBbls)                       Natural Gas (Bcf)
---------------------------------------------------------------------------------------------------------------------------------
                                                SOUTHEAST    SOUTH       WEST                      SOUTHEAST     SOUTH
                                        U.S.      ASIA      AMERICA     AFRICA    TOTAL    U.S.       ASIA      AMERICA    TOTAL
---------------------------------------------------------------------------------------------------------------------------------
<S>                                    <C>      <C>        <C>          <C>       <C>      <C>     <C>          <C>        <C>
Proved Reserves at December 31, 1996    275.3      8.9        15.3        --      299.5   232.8         .2        26.4      259.4
Revisions of previous estimates           6.9      2.2         2.1        --       11.2    22.7      --           16.4       39.1
Improved recovery techniques             10.6     --         --           --       10.6     --       --           --         --
Extensions, discoveries and other
  additions                               1.0     15.6         3.9         4.4     24.9    34.9      --            1.2       36.1
Purchases of minerals-in-place            3.9     --           6.4        --       10.3     7.0      --           --          7.0
Sales of minerals-in-place               --       --         --           --       --     (13.0)     --           --        (13.0)
Spin Off of Monterey Resources         (205.8)    --         --           --     (205.8)  (11.6)     --           --        (11.6)
Production                              (18.3)    (1.6)       (1.8)       --      (21.7)  (56.5)       (.1)       (7.8)     (64.4)
                                       ------   ------     -------      -------  -------  ------   -------      ------    -------
Proved Reserves at December 31, 1997     73.6     25.1        25.9         4.4    129.0   216.3        0.1        36.2      252.6
Revisions of previous estimates          (7.5)    11.7        (5.2)       --       (1.0)    9.4      --            6.3       15.7
Extensions, discoveries and other
  additions                               1.8     22.0         0.9         9.1     33.8    54.6      --            3.7       58.3
Purchases of minerals-in-place            1.3      6.4        13.9        --       21.6    18.8      --           --         18.8
Sales of minerals-in-place               --       --         --           --       --      (2.3)     --           --         (2.3)
Production                               (7.7)    (4.5)       (2.0)       (0.6)   (14.8)  (55.5)       (.1)       (9.4)     (65.0)
                                       ------   ------     -------      -------  -------  ------   -------      ------    -------
Proved Reserves at December 31, 1998     61.5     60.7        33.5        12.9    168.6   241.3      --           36.8      278.1
Revisions of previous estimates          17.8     (9.5)        2.5        (1.7)     9.1     3.7        (.4)       12.5       15.8
Improved recovery techniques             --       --            .7        --         .7     --       --             .4         .4
Extensions, discoveries and other
  additions                               2.0      9.2         1.6         0.3     13.1   145.8       99.1        23.9      268.8
Merger with Snyder Oil                   17.7     --         --           --       17.7   424.0      --           --        424.0
Purchases of minerals-in-place           19.2     --         --           --       19.2   172.2      --           --        172.2
Sales of minerals-in-place                (.2)    --         --           --        (.2)    (.5)     --           --          (.5)
Production                               (9.1)    (5.3)       (1.9)       (1.1)   (17.4)  (96.2)     --           (9.5)    (105.7)
                                       ------   ------     -------      -------  -------  ------   -------      ------    -------
Proved Reserves at December 31, 1999    108.9     55.1        36.4        10.4    210.8   890.3       98.7        64.1    1,053.1
                                       ======   ======     =======      =======  =======  ======   =======      ======    =======
</TABLE>

                                       59
<PAGE>
SANTA FE SNYDER CORPORATION
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
(Continued)
<TABLE>
<CAPTION>
                                                   Crude Oil and Liquids (MMBbls)                       Natural Gas (Bcf)
--------------------------------------------------------------------------------------------------------------------------------
                                                  SOUTHEAST     SOUTH        WEST                         SOUTHEAST      SOUTH
                                         U.S.       ASIA       AMERICA      AFRICA     TOTAL     U.S.        ASIA       AMERICA
--------------------------------------------------------------------------------------------------------------------------------
<S>                                     <C>       <C>         <C>           <C>        <C>       <C>      <C>           <C>
Proved Developed Reserves at December 31,
1996                                     224.1       6.5          8.5         --       239.1     193.6         .2         25.9
1997                                      68.0      21.8         15.2         --       105.0     184.8         .1         35.6
1998                                      56.5      39.5         12.3          1.8     110.1     194.8      --            35.0
1999                                      90.7      24.1         12.6          7.1     134.5     713.4      --            36.2

<CAPTION>
                                          TOTAL
-----------------------------------------------
<S>                                       <C>
Proved Developed Reserves at December 31,
1996                                      219.7
1997                                      220.5
1998                                      229.8
1999                                      749.6
</TABLE>

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

Southeast Asia reserves include Indonesian reserves which represent an
entitlement to gross reserves in accordance with a production sharing contract.
These reserves include estimated quantities allocable to the Company for
recovery of operating costs as well as quantities related to the Company's net
equity share after recovery of costs. Accordingly, these quantities are subject
to fluctuations with an inverse relationship to the price of oil. If oil prices
increase, the reserve quantities attributable to the recovery of operating costs
decline. Although this reduction would be offset partially by an increase in the
net equity share, the overall effect would be a reduction of reserves
attributable to the Company. The Company has certain commitments with respect to
the delivery of natural gas which the Company believes it can fulfill from its
proved reserves and supply contracts with other companies.

At December 31, 1999, 1.7 million barrels of crude oil reserves and 11.5 billion
cubic feet of natural gas reserves were subject to a 90% net profits interest
held by Santa Fe Energy Trust.

STANDARDIZED MEASURE OF FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS
RESERVE QUANTITIES

The standardized measure of discounted future net cash flows is computed by
applying year-end prices of oil and gas (with consideration of price changes
only to the extent provided by contractual arrangements) to the estimated future
production of proved oil and gas reserves, less estimated future expenditures
(based on year-end costs) to be incurred in developing and producing the proved
reserves, less estimated future income tax expenses (based on year-end statutory
tax rates, with consideration of future tax rates already legislated) to be
incurred on pretax net cash flows less tax basis of the properties and available
credits, and assuming continuation of existing economic conditions. The
estimated future net cash flows are then discounted using a rate of 10 percent a
year to reflect the estimated timing of the future cash flows.

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 with consideration of price changes
only to the extent provided by contractual arrangements in existence at
year-end. Each period presented reflects the effects of gas sold from the Sierra
Chata field sold under long-term contracts in Argentina and Chile for prices
ranging between $1.15 and $1.35 per MMBtu. Gas production in excess of the
contract requirements is sold on the local spot market. Such prices have been
held constant except for known and determinable escalation.

                                       60
<PAGE>
SANTA FE SNYDER CORPORATION
SUPPLEMENTAL INFORMATION TO CONSOLIDATED 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.

The standardized measure of future net cash flows relating to the Company's
proved oil and gas reserve quantities at December 31, 1999, 1998 and 1997 is
presented in the following tables (in millions of dollars, except as noted):

<TABLE>
<CAPTION>
                                                   SOUTHEAST      SOUTH       WEST
                                         U.S.         ASIA       AMERICA     AFRICA      TOTAL
------------------------------------------------------------------------------------------------
<S>                                    <C>         <C>           <C>         <C>       <C>
1999
Future cash inflows                      4,391.4    1,632.4        908.1      254.7      7,186.6
Future development and production
  costs                                 (1,767.8)    (988.1)      (340.9)     (85.2)    (3,182.0)
Future income tax expenses                (576.1)    (233.6)      (143.7)     (58.8)    (1,012.2)
                                       ---------   ----------    --------    -------   ---------
    Net future cash flows                2,047.5      410.7        423.5      110.7      2,992.4
Discount at 10% for timing of cash
  flows                                   (936.7)    (202.0)      (199.1)     (25.1)    (1,362.9)
                                       ---------   ----------    --------    -------   ---------
Present value of future net cash
  flows from proved reserves             1,110.8      208.7        224.4       85.6      1,629.5
                                       =========   ==========    ========    =======   =========
Present value of pretax future net
  cash flows from proved reserves        1,423.1      325.1        298.3      131.2      2,177.7
                                       =========   ==========    ========    =======   =========
Average sales prices
    Oil ($/Barrel)                         23.24      23.97        22.78      24.47        23.38
    Natural gas ($/Mcf)                     2.13       3.66         1.23       --           2.22
                                                            (TABLES CONTINUED ON FOLLOWING PAGE)
</TABLE>
                                       61
<PAGE>
SANTA FE SNYDER CORPORATION
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
(Continued)

<TABLE>
<CAPTION>
                                                   SOUTHEAST      SOUTH       WEST
                                         U.S.         ASIA       AMERICA     AFRICA      TOTAL
------------------------------------------------------------------------------------------------
<S>                                    <C>         <C>           <C>         <C>       <C>
1998
Future cash inflows                      1,067.1      582.8        344.5      135.5      2,129.9
Future development and production
  costs                                   (535.7)    (378.9)      (250.6)     (94.9)    (1,260.1)
Future income tax expenses                 (31.5)     (18.7)       (16.1)      (4.2)       (70.5)
                                       ---------   ----------    --------    -------   ---------
    Net future cash flows                  499.9      185.2         77.8       36.4        799.3
Discount at 10% for timing of cash
  flows                                   (183.8)     (71.9)       (44.7)     (16.9)      (317.3)
                                       ---------   ----------    --------    -------   ---------
Present value of future net cash
  flows from proved reserves               316.1      113.3         33.1       19.5        482.0
                                       =========   ==========    ========    =======   =========
Present value of pretax future net
  cash flows from proved reserves          336.0      126.0         34.7       21.8        518.5
                                       =========   ==========    ========    =======   =========
Average sales prices
    Oil ($/Barrel)                          9.94      10.14         8.84      10.55         9.81
    Natural gas ($/Mcf)                     1.94      --            1.29       --           1.85

1997
Future cash inflows                      1,653.8      412.9        431.0       69.9      2,567.6
Future development and production
  costs                                   (775.5)    (225.3)      (266.4)     (49.6)    (1,316.8)
Future income tax expenses                (208.2)     (54.7)       (24.4)      (5.6)      (292.9)
                                       ---------   ----------    --------    -------   ---------
    Net future cash flows                  670.1      132.9        140.2       14.7        957.9
Discount at 10% for timing of cash
  flows                                   (259.2)     (55.0)       (61.0)      (3.0)      (378.2)
                                       ---------   ----------    --------    -------   ---------
Present value of future net cash
  flows from proved reserves               410.9       77.9         79.2       11.7        579.7
                                       =========   ==========    ========    =======   =========
Present value of pretax future net
  cash flows from proved reserves          538.6      111.9         93.1       16.1        759.7
                                       =========   ==========    ========    =======   =========
Average sales prices
    Oil ($/Barrel)                         16.30      16.59        14.96      16.00        16.06
    Natural gas ($/Mcf)                     2.26       1.05         1.21       --           2.11
</TABLE>

                                       62
<PAGE>
SANTA FE SNYDER CORPORATION
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
(Continued)

The following tables set forth the changes in the present value of estimated
future net cash flows from proved reserves during 1999, 1998 and 1997 (in
millions of dollars):

<TABLE>
<CAPTION>
                                                   SOUTHEAST      SOUTH       WEST
                                         U.S.         ASIA       AMERICA     AFRICA      TOTAL
------------------------------------------------------------------------------------------------
<S>                                    <C>         <C>           <C>         <C>       <C>
1999
Balance at beginning of year               316.1      113.3         33.1       19.5        482.0
                                       ---------   ----------    --------    -------   ---------
Increase (decrease) due to
    Sales of oil and gas, net of
      production costs of $153.6
      million                             (256.6)     (57.8)       (27.8)     (13.7)      (355.9)
    Net changes in prices and
      production costs                     406.9      291.2        265.9      115.0      1,079.0
    Extensions, discoveries and
      improved recovery                    114.1       72.0         14.1         .6        200.8
    Purchase of mineral-in-place           734.1      --           --          --          734.1
    Sales of minerals-in-place              (3.5)     --           --          --           (3.5)
    Development costs incurred             133.3       33.0         13.2       17.3        196.8
    Changes in estimated volumes            46.3     (146.2)         8.3      (13.7)      (105.3)
    Changes in estimated development
      costs                               (116.7)      (3.5)       (14.0)       1.3       (132.9)
    Interest factor -- accretion of
      discount                              29.2       10.3          4.0        2.5         46.0
    Income taxes                          (292.3)    (103.7)       (72.4)     (43.2)      (511.6)
                                       ---------   ----------    --------    -------   ---------
                                           794.8       95.3        191.3       66.1      1,147.5
                                       ---------   ----------    --------    -------   ---------
Balance at end of year                   1,110.9      208.6        224.4       85.6      1,629.5
                                       =========   ==========    ========    =======   =========

1998
Balance at beginning of year               410.9       77.9         79.2       11.7        579.7
                                       ---------   ----------    --------    -------   ---------
Increase (decrease) due to
    Sales of oil and gas, net of
      production costs of $115.0
      million                             (129.6)     (25.9)       (17.6)      --         (173.1)
    Net changes in prices and
      production costs                    (228.7)    (102.9)       (86.2)     (20.8)      (438.6)
    Extensions, discoveries and
      improved recovery                     52.8      134.9         10.9       17.2        215.8
    Purchase of mineral-in-place            43.3       61.2          4.9       --          109.4
    Sales of minerals-in-place              (8.2)     --           --          --           (8.2)
    Development costs incurred             130.1       68.5         28.3       12.4        239.3
    Changes in estimated volumes            (0.9)    (113.8)        (9.6)       1.3       (123.0)
    Changes in estimated development
      costs                               (105.6)     (22.8)         5.0       (6.1)      (129.5)
    Interest factor -- accretion of
      discount                              44.3       15.3          6.0        1.8         67.4
    Income taxes                           107.7       20.9         12.2        2.0        142.8
                                       ---------   ----------    --------    -------   ---------
                                           (94.8)      35.4        (46.1)       7.8        (97.7)
                                       ---------   ----------    --------    -------   ---------
Balance at end of year                     316.1      113.3         33.1       19.5        482.0
                                       =========   ==========    ========    =======   =========
                                                            (TABLES CONTINUED ON FOLLOWING PAGE)
</TABLE>
                                       63
<PAGE>
SANTA FE SNYDER CORPORATION
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
(Continued)

<TABLE>
<CAPTION>
                                                   SOUTHEAST     SOUTH      WEST
                                         U.S.        ASIA       AMERICA    AFRICA     TOTAL
---------------------------------------------------------------------------------------------
<S>                                    <C>         <C>          <C>        <C>      <C>
1997
Balance at beginning of year             1,363.8      15.1        98.2      --        1,477.1
                                       ---------   ---------    -------    ------   ---------
Increase (decrease) due to
    Sales of oil and gas, net of
      production costs of $177.1
      million                             (271.4)    (10.8)      (26.9)     --         (309.1)
    Net changes in prices and
      production costs                    (444.7)     16.0       (73.8)     --         (502.5)
    Extensions, discoveries and
      improved recovery                    107.0      64.0         7.3      16.1        194.4
    Purchase of mineral-in-place            24.0     --           32.2      --           56.2
    Spin off of Monterey Resources        (932.2)    --           --        --         (932.2)
    Sales of minerals-in-place             (36.3)    --           --        --          (36.3)
    Development costs incurred             325.7      30.7        54.6       5.2        416.2
    Changes in estimated volumes            28.4      11.7        14.7      --           54.8
    Changes in estimated development
      costs                               (294.9)    (25.4)      (44.9)     (5.2)      (370.4)
    Interest factor -- accretion of
      discount                              80.6       2.2        10.2      --           93.0
    Income taxes                           460.9     (25.6)        7.6      (4.4)       438.5
                                       ---------   ---------    -------    ------   ---------
                                          (952.9)     62.8       (19.0)     11.7       (897.4)
                                       ---------   ---------    -------    ------   ---------
Balance at end of year                     410.9      77.9        79.2      11.7        579.7
                                       =========   =========    =======    ======   =========
</TABLE>

COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES

The following tables includes all costs incurred, whether capitalized or charged
to expense at the time incurred (in millions of dollars):

<TABLE>
<CAPTION>
                                                   SOUTHEAST     SOUTH      WEST
                                         U.S.        ASIA       AMERICA    AFRICA     TOTAL
---------------------------------------------------------------------------------------------
<S>                                    <C>         <C>          <C>        <C>      <C>
1999
Property acquisition costs
    Unproved                                14.5        1.3       --         2.4         18.2
    Proved                                 262.7      --          --         1.0        263.7
    Snyder Oil Acquisition                 771.9      --          --        --          771.9
Exploration costs                           58.4       18.6        6.2       4.0         87.2
Development costs                          135.9       34.6       25.1      19.0        214.6
                                       ---------   ---------    -------    ------   ---------
                                         1,243.4       54.5       31.3      26.4      1,355.6
                                       =========   =========    =======    ======   =========

1998
Property acquisition costs
    Unproved                                13.6        3.3        1.9      --           18.8
    Proved                                  60.2       42.2        7.1        .8        110.3
Exploration costs                           36.3       21.8        8.4      24.4         90.9
Development costs                           73.6       30.7       27.0      15.0        146.3
                                       ---------   ---------    -------    ------   ---------
                                           183.7       98.0       44.4      40.2        366.3
                                       =========   =========    =======    ======   =========

1997
Property acquisition costs
    Unproved                                14.9         .8         .3       1.2         17.2
    Proved                                 185.2         --       37.6        --        222.8
Exploration costs                           48.5        8.6        4.1       4.4         65.6
Development costs                          115.6       30.7       17.2       5.2        168.7
                                       ---------   ---------    -------    ------   ---------
                                           364.2       40.1       59.2      10.8        474.3
                                       =========   =========    =======    ======   =========
</TABLE>

                                       64
<PAGE>
SANTA FE SNYDER CORPORATION
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
(Continued)

CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES

The following table sets forth information concerning capitalized costs at
December 31, 1999 and 1998 related to the Company's oil and gas operations (in
millions of dollars):

<TABLE>
<CAPTION>
                                                   SOUTHEAST      SOUTH       WEST
                                         U.S.         ASIA       AMERICA     AFRICA      TOTAL
------------------------------------------------------------------------------------------------
<S>                                    <C>         <C>           <C>         <C>       <C>
1999
Oil and gas properties
    Unproved                                91.3       17.8          5.2        3.6        117.9
    Proved                               2,527.6      258.4        182.4       48.6      3,017.0
Accumulated amortization of unproved
  properties                               (50.8)      (8.7)        (2.8)      (1.2)       (63.5)
Accumulated depletion, depreciation
  and impairment of proved properties   (1,262.0)    (105.1)       (68.8)      (9.7)    (1,445.6)
                                       ---------   ----------    --------    -------   ---------
                                         1,306.1      162.4        116.0       41.3      1,625.8
                                       =========   ==========    ========    =======   =========
1998
Oil and gas properties
    Unproved                                74.7       16.5         11.9        1.9        105.0
    Proved                               1,427.1      219.7        157.9       30.3      1,835.0
Accumulated amortization of unproved
  properties                               (41.7)      (6.4)        (3.2)      (1.6)       (52.9)
Accumulated depletion, depreciation
  and impairment of proved properties   (1,050.6)     (89.4)       (45.7)      (5.2)    (1,190.9)
                                       ---------   ----------    --------    -------   ---------
                                           409.5      140.4        120.9       25.4        696.2
                                       =========   ==========    ========    =======   =========
</TABLE>

                                       65
<PAGE>
SANTA FE SNYDER CORPORATION
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
(Continued)

RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES

The following table sets forth the Company's results of operations from oil and
gas producing activities for the years ended December 31, 1999, 1998 and 1997
(in millions of dollars):

<TABLE>
<CAPTION>
                                                   SOUTHEAST      SOUTH       WEST
                                         U.S.         ASIA       AMERICA     AFRICA     TOTAL
----------------------------------------------------------------------------------------------
<S>                                    <C>         <C>           <C>         <C>        <C>
1999
Revenues                                   351.8       93.0         43.5       21.2      509.5
Production costs                           (72.1)     (35.4)       (17.0)      (7.6)    (132.1)
Production taxes                           (23.2)     --             (.4)      --        (23.6)
Exploration                                (31.1)     (12.5)        (6.1)      (4.5)     (54.2)
Depletion, depreciation, amortization
  and impairments                         (325.5)     (19.2)       (26.2)      (4.9)    (375.8)
Gain (loss) on disposition of assets         1.8      --            (2.5)      --         (0.7)
                                       ---------   ----------    --------    -------    ------
                                           (98.3)      25.9         (8.7)       4.2      (76.9)
Income tax (expense) benefit                34.4      (14.5)         2.9       (1.7)      21.1
                                       ---------   ----------    --------    -------    ------
                                           (63.9)      11.4         (5.8)       2.5      (55.8)
                                       =========   ==========    ========    =======    ======
1998
Revenues                                   195.8       53.5         33.4        7.7      290.4
Production costs                           (60.5)     (27.9)       (15.9)      (8.2)    (112.5)
Production taxes                           (12.4)     --             (.3)      --        (12.7)
Exploration                                (21.7)     (18.3)        (9.4)     (21.7)     (71.1)
Depletion, depreciation, amortization
  and impairments                         (179.5)     (20.4)       (13.1)      (2.4)    (215.4)
Gain (loss) on disposition of assets        (1.5)     --           --          --         (1.5)
                                       ---------   ----------    --------    -------    ------
                                           (79.8)     (13.1)        (5.3)     (24.6)    (122.8)
Income tax (expense) benefit                27.9        3.3          1.8        9.8       42.8
                                       ---------   ----------    --------    -------    ------
                                           (51.9)      (9.8)        (3.5)     (14.8)     (80.0)
                                       =========   ==========    ========    =======    ======
1997
Revenues                                   446.2       27.5         40.6       --        514.3
Production costs                          (128.9)     (16.7)       (13.3)      --       (158.9)
Production taxes                           (17.8)     --             (.4)      --        (18.2)
Cost of crude oil purchased                (22.0)     --           --          --        (22.0)
Exploration                                (37.9)      (6.3)        (3.7)      (1.2)     (49.1)
Depletion, depreciation, amortization
  and impairments                         (106.1)      (7.3)        (9.2)       (.2)    (122.8)
Gain (loss) on disposition of assets         3.6      --           --          --          3.6
                                       ---------   ----------    --------    -------    ------
                                           137.1       (2.8)        14.0       (1.4)     146.9
Income tax (expense) benefit               (48.0)        .8         (4.9)        .6      (51.5)
                                       ---------   ----------    --------    -------    ------
                                            89.1       (2.0)         9.1        (.8)      95.4
                                       =========   ==========    ========    =======    ======
</TABLE>

Income taxes are computed by applying the appropriate statutory rate to the
results of operations before income taxes. Applicable tax credits and allowances
related to oil and gas producing activities have been taken into account in
computing income tax expenses. No deduction has been made for indirect cost such
as corporate overhead or interest expense.

                                       66
<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 ON THE 9TH DAY OF MARCH
2000.

                                               SANTA FE SNYDER CORPORATION
                                                       (Registrant)
                                                             *
                                          By:________________________________
                                                      MARK A. JACKSON
                                                 EXECUTIVE VICE PRESIDENT AND
                                                   CHIEF FINANCIAL OFFICER
                                                (PRINCIPAL FINANCIAL OFFICER)

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

<TABLE>
<CAPTION>
                      SIGNATURE                                            TITLE
------------------------------------------------------  --------------------------------------------
<C>                                                     <S>
                          *
           __________________________________           Chairman of the Board and Director
                    JOHN C. SNYDER

                          *
           __________________________________           Chief Executive Officer and Director
                    JAMES L. PAYNE                      (Principal Executive Officer)

                          *
           __________________________________           Executive Vice President and Chief Financial
                   MARK A. JACKSON                      Officer (Principal Financial Officer)

                          *
           __________________________________           Director
                  WILLIAM E. GREEHEY

                          *
           __________________________________           Director
                     JOHN A. HILL

                          *
           __________________________________           Director
                   MELVYN N. KLEIN

                          *
           __________________________________           Director
                 HAROLD R. LOGAN, JR.

                          *
           __________________________________           Director
                   ALLAN V. MARTINI

                          *
           __________________________________           Director
                  JAMES E. MCCORMICK

                          *
           __________________________________           Director
                  REUBEN F. RICHARDS

                          *
           __________________________________           Director
                      E.T. STORY

                          *
           __________________________________           Director
                  KATHRYN D. WRISTON

                          *
           __________________________________           Vice President and Controller (Principal
                  MICHAEL S. WILKES                     Accounting Officer)

Dated  March 9, 2000

*By:/s/DAVID L. HICKS
       DAVID L. HICKS, ATTORNEY-IN-FACT
</TABLE>

                                       67
<PAGE>
                               INDEX OF EXHIBITS
<TABLE>
<CAPTION>
        EXHIBIT
         NUMBER                                           DESCRIPTION
------------------------  ----------------------------------------------------------------------------
<C>                       <S>
           3(a)       --  Restated Certificate of Incorporation of Santa Fe Snyder Corporation ("SFS
                          Corp.") (incorporated by reference to Exhibit 3.1 of the Form 8-A/A
                          Registration Statement of SFS Corp. filed on May 11, 1999, Commission File
                          No. 001-07667).
           3(b)       --  Bylaws of SFS Corp., as amended June 30, 1999 (incorporated by reference to
                          Exhibit 3(b) to SFS Corp.'s Quarterly Report on Form 10-Q for the quarter
                          ended June 30, 1999).
           4(a)       --  Senior Indenture dated as of June 1, 1999 between SFS Corp. and The Bank of
                          New York, as Trustee, relating to SFS Corp.'s senior debt securities,
                          including form of senior debt security (incorporated by reference to Exhibit
                          4.1 to SFS Corp.'s Form 8-K filed on June 15, 1999).
           4(b)       --  First Supplemental Indenture dated as of June 14, 1999 to Senior Indenture
                          dated June 1, 1999 between SFS Corp. and The Bank of New York, as Trustee,
                          relating to SFS Corp.'s 8.05% Senior Notes due 2004, including form of 8.05%
                          Senior Notes due 2004 (incorporated by reference to Exhibit 4.2 to SFS
                          Corp.'s Form 8-K filed on June 15, 1999).
           4(c)       --  Certificate of Trust of SFS Capital Trust I (incorporated by reference to
                          Exhibit 4.3 to Form S-3 Registration Statement of SFS Corp., Commission File
                          No. 333-78265).
           4(d)       --  Declaration of Trust of SFS Capital Trust I dated as of May 11, 1999
                          (incorporated by reference to Exhibit 4.4 to Form S-3 Registration Statement
                          of SFS Corp., Commission File No. 333-78265).
           4(e)       --  Certificate of Trust of SFS Capital Trust II (incorporated by reference to
                          Exhibit 4.5 to Form S-3 Registration Statement of SFS Corp., Commission File
                          No. 333-78265).
           4(f)       --  Declaration of Trust of SFS Capital Trust II dated as of May 11, 1999
                          (incorporated by reference to Exhibit 4.6 to Form S-3 Registration Statement
                          of SFS Corp., Commission File No. 333-78265).
           4(g)       --  Indenture dated as of June 10, 1997 between Snyder Oil Corporation ("Snyder
                          Oil") and Texas Commerce Bank National Association relating to Snyder Oil's
                          8 3/4% Senior Subordinated Notes due 2007 (incorporated by reference to
                          Exhibit 4.1 to Snyder Oil's Form 8-K dated June 10, 1997 [Commission File
                          No. 1-10509]).
           4(h)       --  First Supplemental Indenture dated as of June 10, 1997 to Indenture dated as
                          of June 10, 1997 between Snyder Oil and Texas Commerce Bank National
                          Association relating to Snyder Oil's 8 3/4% Senior Subordinated Notes due
                          2007 (incorporated by reference to Exhibit 4.2 to Snyder Oil's Form 8-K
                          dated June 10, 1997 [Commission File No. 1-10509]).
          4(i)        --  Second Supplemental Indenture dated as of June 10, 1997 to Indenture dated
                          as of June 10, 1997 between Snyder Oil and Texas Commerce Bank National
                          Association relating to Snyder Oil's 8 3/4% Senior Subordinated Notes due
                          2007 (incorporated by reference to Exhibit 4.3 to Snyder Oil's Form 8-K
                          dated June 10, 1997).
          10(a)       --  SFER, Inc. Incentive Compensation Plan, as amended. (incorporated by
                          reference to Exhibit 10(a) to SFER, Inc.'s Annual Report on Form 10-K for
                          the year ended December 31, 1998).
          10(b)       --  SFER, Inc. 1990 Incentive Stock Compensation Plan, Third Amendment and
                          Restatement (incorporated by reference to Exhibit 10(a) to SFER, Inc.'s
                          Quarterly Report on Form 10-Q for the quarter ended March 31,1996).
          10(c)       --  Examples of Employment Agreements entered into with executive officers of
                          SFER, Inc. (incorporated by reference to Exhibit 10(d) to SFER, Inc.'s
                          Annual Report on Form 10-K for the year ended December 31, 1996).
          10(d)       --  Example of Indemnification Agreements with SFER Inc.'s directors and
                          officers (incorporated by reference to Exhibit 10(b) to SFER, Inc.'s Annual
                          Report on Form 10-K for the year ended December 31, 1995).
          10(e)       --  SFER, Inc. Supplemental Retirement Plan effective as of December 4, 1990
                          (incorporated by reference to Exhibit 10(h) to SFER, Inc.'s Annual Report on
                          Form 10-K for the year ended December 31, 1996).
</TABLE>
                                       68
<PAGE>
<TABLE>
<C>                       <S>
          10(f)       --  SFER, Inc. Deferred Compensation Plan, effective as of January 1, 1991 as
                          amended and restated, effective February 1, 1994 (incorporated by reference
                          to Exhibit 10(p) to SFER, Inc.'s Annual Report on Form 10-K for the year
                          ended December 31, 1993).
          10(g)       --  Agreement for the Allocation of Consolidated Federal Income Tax Liability
                          and State and Local Taxes among the members of the SFER, Inc. Affiliated
                          Group dated November 19, 1996 (incorporated by reference to Exhibit 10.2 to
                          Monterey Resources, Inc.'s (Commission File No. 1-12311) Annual Report on
                          Form 10-K for the year ended December 31, 1996).
          10(h)       --  Agreement Concerning Taxes and Tax Indemnifications upon Spin Off, dated
                          November 19, 1996, between Monterey Resources, Inc. and SFER, Inc.
                          (incorporated by reference to Exhibit 10.3 to Monterey Resources, Inc.'s
                          (Commission File No. 1-12311) Annual Report on Form 10-K for the year ended
                          December 31, 1996).
          10(i)       --  Agreement Regarding Shelf Registration Statement dated March 24, 1995,
                          between SFER, Inc. and HC Associates, GKH Partners, L.P., GKH Investments,
                          L.P., Ernest H. Cockrell Texas Testamentary Trust and Carol Cockrell
                          Jennings Texas Testamentary Trust (incorporated by reference to Exhibit
                          10(o) to SFER, Inc.'s Annual Report on Form 10-K for the year ended December
                          31, 1995).
          10(j)       --  Conveyance and Contribution Agreement dated as of November 1, 1996, between
                          Monterey Resources, Inc. and SFER, Inc. (incorporated by reference to
                          Monterey Resources, Inc.'s (Commission File No. 1-12311) Annual Report on
                          Form 10-K for the year ended December 31, 1996).
          10(k)       --  Credit Agreement dated as of May 5, 1999 among SFS Corp., the banks
                          signatory thereto, and Chase Bank of Texas, N.A. as Administrative Agent;
                          Bank of America National Trust and Savings Association as Syndication Agent;
                          Wells Fargo Bank (Texas), N.A. as Documentation Agent; Bank One, Texas, N.A.
                          as Managing Agent; ABN AMRO Bank N.V., Credit Lyonnais New York Branch and
                          Salomon Brothers Holding Company Inc. as Co-Agents (incorporated by
                          reference to Exhibit 10(a) to SFS, Corp.'s Quarterly Report on Form 10-Q for
                          the quarter ended June 30, 1999).
          10(l)       --  364-Day Credit Agreement dated as of May 5, 1999 among SFS Corp., the banks
                          signatory thereto, and Chase Bank of Texas, N.A. as Administrative Agent;
                          Bank of America National Trust and Savings Association as Syndication Agent;
                          Wells Fargo Bank (Texas), N.A. as Documentation Agent; Bank One, Texas, N.A.
                          as Managing Agent; ABN AMRO Bank N.V., Credit Lyonnais New York Branch and
                          Salomon Brothers Holding Company Inc. as Co-Agents (incorporated by
                          reference to Exhibit 10(b) to SFS, Corp.'s Quarterly Report on Form 10-Q for
                          the quarter ended June 30, 1999).
          10(m)      --   SFS Corp., 1999 Stock Compensation Retention Plan (incorporated by refer-
                          ence to Exhibit 10(a) to SFS Corp.'s Quarterly Report on Form 10-Q for the
                          quarter ended September 30, 1999).
         *10(n)       --  Amendment dated November 17, 1999 to Credit Agreement dated as of May 5,
                          1999 among SFS Corp., the banks signatory thereto, and Chase Bank of Texas,
                          N.A. as Administrative Agent; Bank of America National Trust and Savings
                          Association as Syndication Agent; Wells Fargo Bank (Texas), N.A. as
                          Documentation Agent; Bank One, Texas, N.A. as Managing Agent; ABN AMRO Bank
                          N.V., Credit Lyonnais New York Branch and Salomon Brothers Holding Company
                          Inc. as Co-Agents.
         *10(o)       --  Snyder Oil Supplemental Executive Retirement Plan, effective January 12,
                          1999.
         *10(p)       --  Restricted Stock Grant Agreement with Chief Executive Officer dated December
                          14, 1999.
         *21          --  Subsidiaries of the registrant.
         *23(a)       --  Consent of PricewaterhouseCoopers LLP
         *23(b)       --  Consent of Ryder Scott Company
         *24          --  Powers of Attorney
         *27          --  Financial Data Schedule
</TABLE>
------------

* Filed herewith

                                       69