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


                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 1-14256

                              Belco Oil & Gas Corp.

             (Exact name of Registrant as specified in its charter)
<TABLE>
<S>                                            <C>
              Nevada                                    13-3869719
  (State or other jurisdiction of                      (IRS Employer
   incorporation or organization)                    Identification No.)
</TABLE>
<TABLE>
<S>                                            <C>
  767 Fifth Avenue, 46th Floor
        New York, New York                                  10153
(Address of principal executive office)                  (Zip Code)
</TABLE>

       Registrant's telephone number, including area code: (212) 644-2200
                                ---------------

       Securities registered pursuant to Section 12(b) of the Act:
<TABLE>
<CAPTION>

                                                     Name of each exchange
              Title of each class                     on which registered
              -------------------                    ---------------------
 <S>                                            <C>
     Common Stock, par value $.01 per share          New York Stock Exchange
     6-1/2% Convertible Preferred Stock,
     par value $.01 per share                       New York Stock Exchange
</TABLE>

         Securities  registered  pursuant to Section 12(g) of the Act:

                                      None

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

         Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.

YES |X|     NO |_|

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

         The aggregate market value of the voting and non-voting common equity
held by non-affiliates of the Registrant at March 15, 2000, was approximately
$105.2 million (based on a value of $8.5625 per share, the closing price of the
Common Stock as quoted by the New York Stock Exchange on such date). 31,092,400
shares of Common Stock, par value $.01 per share, were outstanding on March 15,
2000.

                       DOCUMENTS INCORPORATED BY REFERENCE

         Portions of the definitive proxy statement for the Registrant's 2000
Annual Meeting of Shareholders, to be filed pursuant to Regulation 14A under the
Securities Exchange Act of 1934, are incorporated by reference into Part III.

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

                              BELCO OIL & GAS CORP.
                                    Form 10-K
                                TABLE OF CONTENTS
                                     PART I
<TABLE>
<CAPTION>
                                                                            PAGE
                                                                            ----
<S>      <C>                                                                <C>
ITEM 1 - BUSINESS..............................................................2
         Overview..............................................................2
         Primary Operating Areas...............................................3
         Costs Incurred and Drilling Results...................................7
         Acreage...............................................................8
         Productive Well Summary...............................................9
         Marketing.............................................................9
         Production Sales Contracts...........................................10
         Price Risk Management Transactions...................................10
         Texas Severance Tax Abatement........................................12
         Section 29 Tax Credit................................................12
         Regulation...........................................................12
         Operating Hazards and Insurance......................................13
         Title to Properties..................................................14
         Employees............................................................14
         Office and Equipment.................................................14
         Forward-Looking Information and Risk Factors.........................14
         Executive Officers of the Registrant.................................21
         Certain Definitions..................................................22

ITEM 2 - PROPERTIES...........................................................24
         Oil and Gas Reserves.................................................24

ITEM 3 - LEGAL PROCEEDINGS....................................................25

ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS..................25

                                     PART II

ITEM 5 - MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
           MATTERS............................................................25

ITEM 6 - SELECTED FINANCIAL DATA..............................................26

ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
           RESULTS OF OPERATIONS..............................................27
         Overview.............................................................27
         Results of Operations - 1999 Compared to 1998........................29
         Results of Operations - 1998 Compared to 1997........................30
         Liquidity and Capital Resources......................................31
         Other................................................................34

ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK..........35

ITEM 8 - CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.............37

ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
           FINANCIAL DISCLOSURE...............................................37

                                    PART III

ITEM 10 - DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT..................37

ITEM 11 - EXECUTIVE COMPENSATION..............................................37

ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT......37

ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS......................37

                                    PART IV

ITEM 14 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K....37

                                         i
</TABLE>

<PAGE>

                              BELCO OIL & GAS CORP.

                                     PART I

ITEM 1 -- BUSINESS

Overview

     Belco Oil & Gas Corp. and its subsidiaries ("Belco" or the "Company") is an
independent energy company engaged in the exploration for and the acquisition,
exploitation, development and production of natural gas and oil in the United
States primarily in the Rocky Mountains, the Permian Basin, the  Mid-Continent
region and the Austin Chalk Trend.  Since its inception in April 1992, the
Company has grown its reserve base through a program of exploration and
development drilling and through acquisitions.  The Company concentrates its
activities primarily in four core areas in which it has accumulated detailed
geologic knowledge and has developed significant management and technical
expertise.  Additionally, the Company attempts to structure its participation in
natural gas and oil exploration and development activities to minimize initial
costs and risks, while permitting substantial follow-on investment.

     The Company has achieved substantial growth in reserves,  production,
revenues and EBITDA (Earnings Before Interest, Taxes, Depreciation, Depletion
and Amortization and other non-cash charges) since 1992.  Belco's estimated
proved reserves have increased at a compound annual growth rate of 32%, from 67
Bcfe as of December 31, 1992 to 641 Bcfe as of December 31, 1999 with a reserve
life index of approximately 10.6 years based on 1999 production.  Average daily
production has increased from 4 MMcfe per day in 1992 to approximately 165 MMcfe
per day in 1999.  Similarly, the growth in the Company's EBITDA has been
substantial, increasing from $2.9 million for the year ended December 31, 1992,
to $96.5 million for the year ended  December 31, 1999.  The Company's low cost
structure is evidenced by its general and administrative expenses of $0.08 per
Mcfe and lease operating expenses of $0.65 per Mcfe in 1999.

     The Company's operations are currently focused in the Rocky Mountains,
primarily in the Green River (which includes the Moxa Arch Trend), Wind River
and Big Horn Basins; the Permian Basin in west Texas; the Mid-Continent region
in Oklahoma and North Texas; and the Austin Chalk Trend  primarily in Texas. At
December 31, 1999, the Company had estimated proved reserves of 641 Bcfe with a
pre-tax PV10 value of $635 million.  As of December 31, 1999,  Belco held or
controlled approximately 1.9 million gross (750,000 net) undeveloped acres and
had an interest in approximately 2,755 gross  (1,769 net) oil and gas wells of
which Belco operated 1,998.

     The Company's Permian Basin and Mid-Continent activities concentrate on
exploiting proven properties through secondary  recovery  operations,
the drilling of development wells or infill wells,  workovers,  recompletions in
other  productive  zones and other  exploitation  techniques.  The  Company  has
conducted or intends to conduct significant secondary  recovery/infill  drilling
programs  on many of the  properties  within  these  two core  areas.  Secondary
recovery  projects have been the primary  development  focus in these areas over
the past five years.  Generally,  "secondary  recovery" refers to methods of oil
extraction  in which  fluid or gas  (usually  water,  natural  gas or  CO(2)) is
injected into a formation  through input  (injector)  wells,  and oil is removed
from  surrounding  wells.  "Waterflooding"  is one  proven  method of  secondary
recovery  in which water is injected  into an oil  reservoir  for the purpose of
forcing the oil out of the reservoir rock and into the bore of a producing well.
Waterflood  projects are  engineered  to suit the type of  reservoir,  depth and
condition  of the  field.  The  Company  has  considerable  experience  with and
actively  employs  waterflood  techniques  in many of its  fields  in  order  to
stimulate production.

     Certain  terms  relating  to the oil and gas  industry  are  defined in "--
Certain Definitions" below.

                                       2

<PAGE>

Primary Operating Areas

     The  Company's  operations  are  currently  focused in four core  operating
areas:  (i) the Rocky  Mountains,  principally  in  Wyoming  in the Green  River
(inclusive  of the Moxa Arch Trend),  Wind River and Big Horn  Basins;  (ii) the
Permian  Basin of west Texas;  (iii) the  Mid-Continent  region in Oklahoma  and
north Texas; and (iv) the Austin Chalk Trend, primarily in Texas. In addition to
these core areas,  the Company  conducts  operations  in the onshore  Gulf Coast
region and in several other minor areas.

     The following table sets forth  information,  as of December 31, 1999, with
respect to the  Company's  estimated  net proved  reserves  by  operating  area.
Approximately  83% of the quantities of proved  reserves on an Mcfe basis
aggregating 84% of the pre-tax  present value were  estimated by the independent
petroleum  engineers Miller and Lents, Ltd. ("Miller & Lents").  See "Forward
Looking Information and Risk Factors" below and "Properties."

                                 Proved Reserves
<TABLE>
<CAPTION>
                                                                      Percent
                                                           Gas          of
                                  Oil          Gas      Equivalent     Proved
                                (MBbls)     (MMcf)(1)     (MMcfe)     Reserves
                                -------     ---------   -----------   --------
<S>                             <C>         <C>         <C>           <C>
Rocky Mountains..............    1,497      139,525      148,507        23%
Permian Basin................   34,372       41,150      247,379        39%
Mid-Continent................   15,878       48,394      143,663        22%
Gulf Coast-Austin Chalk......    1,329       93,079      101,055        16%
                                ------      -------      -------       ----
  Total......................   53,076      322,148      640,604       100%
                                ======      =======      =======       ====
</TABLE>

----------
(1)    Includes natural gas liquids.

   Rocky Mountains

     The Company maintains a significant acreage position in the Rocky Mountains
of Wyoming where it conducts an ongoing exploration and development  program. In
June 1992, the Company commenced a development drilling program in the Moxa Arch
Trend  pursuant to a farmout  from  Amoco.  In 1996,  the Company  significantly
expanded  its acreage and  exploration  activities  by  acquiring  the rights to
approximately  750,000 gross (250,000 net) acres in the Green River,  Wind River
and Big Horn Basins in Wyoming, which lie north and east of the Moxa Arch Trend.
At December 31,  1999,  the Company  controlled  approximately  1,152,531  gross
(351,789 net) undeveloped acres in these three basins.

     Moxa Arch Trend. One of the Company's  primary  operating areas is the Moxa
Arch Trend located in the Green River Basin in southwestern Wyoming, principally
in Lincoln,  Sweetwater and Uinta Counties.  Approximately  23% of the Company's
estimated proved reserves at December 31, 1999 were located in this region.  The
Company  participates  in  vertical  gas wells in this  area  which  target  the
Frontier and/or Dakota formations at depths that range from approximately 10,000
to 12,500 feet. The Frontier  formation is a relatively blanket "tight gas sand"
formation, while the Dakota formation,  beneath the Frontier, tends to be a more
prolific,  but less predictable,  channel sand. Production from Moxa Arch wells,
particularly from the Frontier formation, tends to be long-lived,  with 25 to 30
year reserve lives not uncommon.

     Through 1999, the Company had  participated  in 229 gross (75 net) wells in
this field with 158  Frontier  wells,  18 Dakota  wells and 53 dual  completions
(both  Frontier  and  Dakota  completed  in the same  well  bore).  Average  net
production for the year ended December 31, 1999, was  approximately 22 MMcfe per
day.  Forty-seven of the Company's gross wells drilled in 1992 qualified for the
Section 29 Tax Credit of  approximately  $0.59 per Mcf, which is attributable to
all qualified  production  from these wells through 2002. See "-- Section 29 Tax
Credit." The Company drilled 8 wells (5.6 net) in 1999 and anticipates  drilling
approximately 12 wells in 2000. See "-- Regulation -- Environmental Regulation."

                                       3

<PAGE>

     Green River,  Wind River and Big Horn Basins.  Effective  November 1, 1996,
the Company  entered into an agreement with Andex Partners and Andover  Partners
to conduct  exploratory  operations  in the Green River and Wind River Basins of
Wyoming.  Under the  agreement,  the Company has committed to spend a minimum of
$20 million on seismic,  leasing and exploratory activities through December 31,
2001 and will initially earn rights to a 50% interest in  approximately  300,000
net acres after spending 50% of the committed  amount. At December 31, 1999, the
Company had spent  approximately $15 million of its $20 million  commitment with
operations  conducted  by  either  Union  Pacific  Resources  ("UPR")  or  Yates
Petroleum Corporation ("Yates").

     Effective December 31, 1996, the Company entered into two joint development
agreements with Snyder Oil Company, now Santa Fe Snyder ("Santa Fe")  pursuant
to which the Company has acquired  a 50%  interest  in  approximately 87,321 net
acres in the Wind River Basin of Wyoming and  110,859 net acres in the Big Horn
Basin of Wyoming.  Under such agreements, Santa Fe is the operator. A total of 6
wells have been drilled to date on this acreage. The aggregate total gross pro-
ducing rate was approximately 3.1 MMcfe per day gross in December 1999. Two
wells have been drilled in the Big Horn  Basin  and were  producing  at a  com-
bined  rate of 265 Mcfe per day as of December 31, 1999. At least one well is
planned in 2000.

     In June 1997, the Company entered into a  participation  agreement with Tom
Brown,  Inc.  ("Tom Brown") and Andover  Partners  covering an  approximate  one
million  acre AMI in the Big Horn Basin and  acquired  an interest in an initial
100,000  gross  (25,000  net) acres.  The Company is in  negotiations  to set up
drilling units for exploration in 2000.

     The Company expects to participate in a series of exploratory wells in
these basins over the next 12 to 24 months with UPR, Santa Fe, Tom Brown and
Yates serving as operators for most wells. The wells will target multiple forma-
tions, with the Mesa Verde and Frontier formation the most frequent targets. If
initial results are successful, these projects hold the potential for multi-well
developmental  drilling  programs for the Company  over the next several  years.
Belco expects to drill and operate one well in 2000.

   Permian Basin

     Approximately  39% of the Company's  estimated  proved reserves at December
31, 1999 were located in the Company's  Permian Basin core area.  These reserves
are  concentrated  in the Andrews Unit,  the Roundtop Unit, the Shafter Lake San
Andres Unit and the Nolley Wolfcamp Unit.

     The Company's  Permian Basin properties  produce  primarily from either the
Grayburg/San  Andres  formation,  at an  average  depth  of 4,500  feet,  or the
Wolfcamp/Penn  formation  at an  average  depth  of  9,000  feet.  Most  of  the
properties that produce from these horizons are under secondary  recovery,  and,
based on  analogous  properties  nearby,  are  potentially  responsive  to CO(2)
miscible  flooding.  Given the existence of nearby CO(2) pipelines,  the Company
believes many of its properties in the Permian Basin region contain  significant
upside  potential based on application of enhanced  recovery  methods and deeper
drilling which could add to existing reserves.

     A significant  portion of the Company's total estimated  proved reserves in
the Permian  Basin region lie in Andrews  County,  Texas.  The Company  produced
approximately  2,560  gross BOPD in Andrews  County,  and  realized  significant
advantages  as a result of its  large  scale  operation.  The  Company  owns two
electrical  distribution  systems and three  saltwater  gathering  and  disposal
systems. The Company has several yards for both the storage of equipment and the
staging of new  development  projects.  Two of the Company's  larger  production
facilities connect into a water supply system with excess capacity for expanding
existing or initiating new secondary and enhanced recovery projects. The Company
believes  that  these  systems  and  facilities   provide  the  Company  with  a
competitive  advantage in acquiring  additional  operated  properties in Andrews
County.

     The Company's  largest (by value) Permian Basin units are the Andrews Unit,
the Roundtop Unit and the Shafter Lake San Andres Unit.

                                       4
<PAGE>

     Andrews Unit. The Andrews Unit produces from the Wolfcamp/Penn formation at
approximately 8,600 feet. The Company has a 98.6% working interest in this 3,230
acre unit.  Water  injection  began in late 1996 with some response  occuring in
late 1998.  Gross  production in December 1999 was  approximately  765 BOPD with
injection  of over 5,000  barrels of water per day. The Company anticipates
continued  expansion of its  waterflood  operations  during 2000 by drilling 6
wells and converting 2 wells to injection.  The Company also believes that pro-
duction from this waterflood unit can be enhanced with the use of CO(2) or sur-
factants with flooding.

     Roundtop Unit. The Company owns a 61.6% working interest in this 4,559 acre
unit in Fisher County,  Texas.  This Company  operated  secondary  recovery unit
produces from the Palo Pinto formation at approximately  4,700 feet. The Company
became  operator  of  this  unit  in  March  1998.   Gross  oil  production  was
approximately  540 BOPD in December 1999.  The unit was originally  waterflooded
with success on a peripheral  injection pattern prior to changing to a five spot
pattern.  The Company  began the process of  returning  the unit to a peripheral
flood pattern in 1998. The Company plans to continue reconfiguring the injection
pattern during 2000.

     Shafter Lake San Andres Unit.  The Shafter Lake San Andres Unit is a 12,880
acre unit in Andrews County,  Texas that produces from the  Grayburg/San  Andres
formation at approximately  4,500 feet. The Company has a 62.9% working interest
in this secondary recovery unit. Gross oil production averaged 790 BOPD in 1999.
The Company has drilled 42 infill 20 acre locations  since becoming  operator of
the unit in early 1993.  In 2000,  the Company plans to drill 24 infill wells to
continue the downspacing effort. In addition,  the Company believes a large part
of this field has potential for 10 acre infill wells as well as CO(2) potential.

     Mid-Continent Region

     The Company's  Mid-Continent  operations are currently focused in Oklahoma,
north Texas and Kansas,  where  approximately  22% of its total estimated proved
reserves at December 31, 1999 were located.

     Oklahoma.  Six  waterfloods   collectively  represent  a  majority  of  the
Company's proved reserves in the region. These waterfloods are identified as the
Oakdale Unit,  the Calumet Unit,  the Witcher Unit,  the Crooked Creek Unit, the
Cutter South Unit and the Rush Springs Unit. All six waterfloods  were initiated
and unitized by the Company.

     Oakdale Red Fork Unit.  The Company owns an 88.9% working  interest in this
3,600  acre unit in  northwestern  Oklahoma.  This  Company  operated  secondary
recovery  unit  produces  from the Redfork  formation  at 6,400 feet.  Gross oil
production was  approximately  790 BOPD in December 1999. The Company  drilled 2
wells during 1999. Plans for 2000 include drilling 3 infill production wells and
the continued expansion of water injection to the south.

     Calumet Cottage Grove Unit. This Company operated  secondary  recovery unit
consists  of  11,400  acres  in  central   Oklahoma.   Production  is  from  the
Pennsylvanian  Cottage  Grove  formation  at 8,100  feet.  Gross  production  in
December  1999 was  approximately  1,850 BOPD.  The Company has a 44.1%  working
interest  in this  unit.  A total of 8 wells were  drilled  in 1999.  2000 plans
include  drilling  several infill and re-entry wells and converting two wells to
water injection.

     Witcher Red Fork Unit.  The 1,620 acre  Company  operated  Witcher Red Fork
Unit is located in Central Oklahoma. The Company has a 70.7% working interest in
this 6,400 foot  secondary  recovery  unit.  December 1999 gross  production was
approximately 350 BOPD.

     North Texas.  The north Texas region  stretches from the  Chadbourne  Ranch
Field in Coke County in the west to several  individual leases in Grayson County
in the east. The Rhombochasm, Katz, Electra and Burkburnett Fields represent the
properties with the most significant value in the north Texas region.  The Com-
pany has drilled 289 wells in these fields.  In addition to the Company's exten-
sive inventory of oil and gas opportunities in the north Texas region, the Com-
pany owns three electrical distribution systems and has extensive field facili-
ties.

                                       5
<PAGE>

     Rhombochasm  Field.  The Company  acquired a 37.5% working  interest in the
Rhombochasm  Field from the operator,  Burnett Oil Company,  in early 1994.  The
Rhombochasm Field encompasses approximately 3,200 acres in Cottle County, Texas.
Production is from the Bend Conglomerate  formation at an average depth of 8,000
feet.  Gross field  production  in December 1999 was  approximately  90 BOPD and
10,320 Mcfpd. During 1999, the Company  participated in the drilling of 3 wells.
The Company anticipates participating in the drilling of 3 wells during 2000.

     Katz Field.  The Katz Field  consists  of five  secondary  recovery  leases
located in King and Knox  Counties,  Texas.  The Company  became the operator in
March 1998 and has a 100% working  interest in these leases.  Production is from
two  Strawn  sands  at  approximately  4,800  feet and  5,100  feet.  Gross  oil
production  was  approximately  320 BOPD in December  1999. In 1998, the Company
began  reactivating  the  waterflood  in the zone at 4,800  feet  with  response
occuring in late 1998. The Company  anticipates  continuing  reactivation of the
waterflood  by activating  three shut-in  injectors and drilling one producer in
2000.

     Electra Area.  The Electra area produces from shallow Cisco sand at a depth
of 150 to 2,100  feet.  The  Company  operates  22  leases in this area with 233
active oil  producing  wells and 121 active water  injectors.  The Company has a
100% working  interest in 21 of these  leases and a 75% working  interest in the
other lease. Gross production for December 1999 averaged approximately 1,064
BOPD. In 1999 the Company drilled 1 producing well.

     Burkburnett  Area.  The  Burkburnett  area  produces from the Gunsight Sand
formation at a depth of 1,750 feet. The Company  operates 12 leases in this area
with 159  active  oil  producing  wells  and 116  active  water  injectors.  The
Company's working interest is 100% in all leases.  Gross production for December
1999 was approximately 425 BOPD.

   Gulf Coast-Austin Chalk

     Texas -- Giddings Field. Approximately 15% of the Company's estimated total
proved  reserves at December 31, 1999 were located in the Giddings Field of east
central Texas,  principally  in Grimes,  Washington  and Fayette  Counties.  The
Giddings  Field has been and still is one of the most  actively  drilled oil and
gas fields in the United  States.  The primary  producing  zone in the  Giddings
Field is the Austin Chalk formation,  a fractured  carbonate  formation that has
been highly conducive to the application of horizontal drilling technology.  The
Austin Chalk  formation is encountered  in this field at depths ranging  between
approximately 7,000 and 17,000 feet.

     The Company  first  acquired  interests in the Giddings  Field in September
1992. During the year ended December 31, 1999,  average net production from this
field was approximately 61 MMcfe per day. Through December 31, 1999, the Company
had  drilled  260 gross (86 net)  wells in this field and  continues  to control
approximately  217,000 gross (69,000 net)  undeveloped  acres in this area.  The
Company  currently  divides the Giddings  Field into three prospect  areas:  (i)
Navasota  River,  primarily in Grimes County;  (ii)  Independence,  primarily in
Washington  County;  and (iii)  River Bend,  primarily  in Fayette  County.  The
Company expects to drill new wells,  including  infill wells, and re-enter older
wells to drill additional laterals in the Giddings Field.  Currently, a majority
of the Company's  interests in this field are held  pursuant to agreements  with
and are  operated by  Chesapeake  Energy  Corporation  ("CHK")  and, to a lesser
extent,  UPR.  The  Company  serves as operator  for  portions of the River Bend
prospect area.

     Four  wells  were  drilled  in  the   Independence   area  in  1999.  Belco
participated  in the first well in this prolific area in 1998. Five additional
wells are planned in 2000.

     The Company believes that its success in the Giddings Field is attributable
to three principal factors: (i) continued  technological  advances in horizontal
drilling have significantly  lowered finding and development costs in the field;
(ii) the geological setting of the deeper downdip areas of the field has created
more extensive  fracturing  than in other areas of the Texas Austin Chalk Trend;
and (iii) the Company's  acquisition program in cooperation with other operators
has  permitted the creation of larger  spacing  units,  thus  reducing  possible
competition for reserves from offsetting wells. As a result of these

                                       6

<PAGE>

factors,  the Company's deeper downdip wells have, on average,  produced greater
reserves  per well than  average  wells in other areas of the Texas Austin Chalk
Trend.

     The majority of the Company's  acreage in the Giddings Field was classified
as a tight formation or deep wells by the Texas Railroad Commission.  Wells spud
between May 1989 and September 1996 are exempt from the 7.5% state severance tax
on high cost  natural gas  through  August  2001.  See "-- Texas  Severance  Tax
Abatement."

     Louisiana. The Louisiana Austin Chalk Trend is an extension of the 200-mile
long Austin Chalk Trend of Texas and represents a continuation  of the Company's
exploration  and development  activities  using  deep-well  horizontal  drilling
technology.  At December 31, 1999, the Company owned or had the right to acquire
approximately  154,783  net acres in this  trend.  Low oil prices  prompted  the
postponement  of drilling  activity  during 1998 and most of 1999. In late 1999,
Belco added an  additional  lateral to the Turner #1 well. At year-end this 100%
working interest well was producing 700 BOPD. One additional  reentry is planned
in 2000.

   Other Operating Areas

     HLM  Project.  The Company has obtained  3-D seismic on  approximately  140
square miles located mainly in Montgomery and Liberty Counties. This seismic was
interpreted in 1999 and a total of 5 wells were drilled for shallow Yegua,  Frio
and Wilcox target.  At December 31, 1999 the wells were producing an  aggregate
of 6 Mmcfe per day. The Company has a 79% working interest in the formations
shallower than Wilcox.  The Company has identified several additional shallow
prospects that it will pursue in 2000.

     Also in  1999,  Belco  made a trade  with  Newfield Exploration Company
("Newfield") for 33% of the Wilcox rights.  Newfield will pay Belco's remaining
46% share of the costs to drill Wilcox wells until Belco receives a total of
$2.3 million. Belco is operator for all of the drilling activities. Two Wilcox
tests are planned in 2000.

Costs Incurred and Drilling Results

   Drilling Activity

     The  following  table sets forth the wells  participated  in by the Company
during the periods indicated. In the table, "gross" refers to the total wells in
which the  Company  has a working  interest,  and  "net"  refers to gross  wells
multiplied by the Company's working interest therein.

<TABLE>
<CAPTION>

                                       Year Ended December 31,
                     ----------------------------------------------------------
                      1999 (1)          1998 (1) (2)            1997 (3)
                   -------------------------------------------------------------
                   Gross      Net      Gross       Net       Gross       Net
<S>                <C>       <C>       <C>        <C>        <C>        <C>
Development:
  Productive......  46.0      29.4      69.0       47.1        54.0      23.1
  Non-productive..   2.0       1.0       1.0        1.0         4.0       2.2
                   -----     -----     -----      -----       -----     -----
          Total...  48.0      30.4      70.0       48.1        58.0      25.3
                    ====      ====      ====       ====        ====      ====
Exploratory:
  Productive......  11.0       8.2      23.0        9.4        20.0      13.7
  Non-productive..   3.0       2.5       7.0        4.0        18.0       6.4
                   -----       ---     -----       ----       -----      ----
          Total...  14.0      10.7      30.0       13.4        38.0      20.1
                    ====      ====      ====       ====        ====      ====
</TABLE>

----------
(1) Includes 15 gross (11.2 net) and 7 gross (4 net) wells in progress at
    December 31, 1999 and 1998, respectively.
(2) Excludes 343 gross (175 net) productive wells acquired during 1998.
(3) Includes results for Coda Energy, Inc. ("Coda") since November 26, 1997, the
    date Coda was acquired by the Company.

                                       7

<PAGE>

   Volumes, revenue, prices and production costs

     The following table sets forth certain information regarding the production
volumes,  revenue,  average prices  received  (prior to any commodity price risk
management   activities)  and  average  production  costs  associated  with  the
Company's sale of oil and natural gas for the periods indicated.

<TABLE>
<CAPTION>

                                                  Year Ended December 31,
                                           ------------------------------------
                                                1999       1998     1997 (1)
                                              --------   --------   --------
<S>                                           <C>         <C>       <C>
Net Production Data:
  Oil (MBbl).................................    3,439      4,177      1,295
  Gas (MMcf).................................   39,737     37,208     49,710
  Gas equivalent (MMcfe).....................   60,370     62,272     57,479
Oil and Gas Sales ($ in 000's)(2)............ $139,242   $124,199   $129,994
Average Sales Price (Unhedged) (2):
  Oil ($ per Bbl)............................   $17.49     $13.17     $19.28
  Gas ($ per Mcf)............................    $1.99      $1.86      $2.11
Costs ($ per Mcfe):
  Oil and gas operating expenses.............    $0.65      $0.66      $0.22
  General and administrative.................    $0.08      $0.08      $0.07
  Depreciation, depletion and amortization
    of oil and gas properties................    $0.90      $0.90      $0.81
</TABLE>

----------
(1)  Includes  results  for Coda  since  November  26,  1997,  the date Coda was
acquired by the Company.

(2) Oil and gas sales exclude results related to commodity price risk management
activities which are reported separately.

   Development, Exploration and Acquisition Expenditures

     The  following  table sets forth  certain  information  regarding the costs
incurred  by  the  Company  in  its  development,  exploration  and  acquisition
activities during the periods indicated.

<TABLE>
<CAPTION>
                                        Year Ended December 31,
                                  ------------------------------------
                                            ($'s in thousands)
                                   1999           1998         1997 (1)
                                 --------       --------     ----------
<S>                              <C>            <C>           <C>
Property acquisitions costs--
  Proved........................  $17,608        $56,695       $443,930  (2)
  Unproved......................   10,390         14,414         24,226
Exploration costs...............   10,943         18,597         46,939
Development costs...............   29,576         37,969         59,571
Capitalized interest............    4,881          5,123          3,742
Property Sales..................     (215)        (6,292)       (13,949)
                                ---------       --------      ---------
  Total net costs incurred......  $73,183       $126,506       $564,459
                                  =======       ========       ========
</TABLE>

----------
(1) Includes results for Coda since November 26, 1997, the date Coda was
    acquired by the Company.
(2) Acquisition of proved properties includes $437.4 million (exclusive of
    $101.6 million of deferred taxes related to the difference between the book
    and tax basis of assets acquired) relative to the acquisition of Coda.

Acreage

     The following  table sets forth, as of December 31, 1999, the gross and net
acres that the Company owned,  controlled or had the right to acquire  interests
in both developed and undeveloped  acreage.  Developed acreage refers to acreage
within

                                       8

<PAGE>

producing  units and  undeveloped  acreage  refers to acreage  that has not been
placed in producing units.  "Gross" acres refers to the total number of acres in
which the Company  owns a working  interest.  "Net" acres  refers to gross acres
multiplied by the Company's fractional working interest.

<TABLE>
<CAPTION>
                                  Developed                 Undeveloped(1)
                              -----------------          ------------------
                              Gross         Net          Gross         Net
                              -----       ------        -------      -------
<S>                          <C>          <C>           <C>         <C>
Rocky Mountains:
  Green River Basin.......    5,123          480        525,140      138,337
  Moxa Arch Trend.........   24,861       14,619         23,559       14,227
  Wind River Basin........    2,077          720        336,202      113,440
  Big Horn Basin..........      643          321        291,188      100,012
  Denver-Julesburg Basin..  207,365        2,298        177,939       91,279
Permian Basin.............   97,871       49,497             20           20
Mid-Continent Region:
  Oklahoma................  119,100       39,635         30,475       10,898
  North Texas.............   36,593       21,777            640          320
  Kansas..................   37,489       31,488          8,563        8,000
  North Dakota............        0            0          4,000        1,858
Austin Chalk Trend:
  Texas-Giddings Field....  104,370       41,498        216,916       69,014
  Louisiana...............    5,330        2,373        183,183      154,783
Other Operating Areas:
  Arkansas................       56           42          6,001        4,383
  Michigan-Central Basin..    1,664          702         71,055       12,554
  Gulf Coast..............   10,254        7,976         49,790       30,871
                            -------      -------      ---------      -------
          Totals..........  652,796      213,426      1,924,671      749,996
                            =======      =======      =========      =======
</TABLE>
----------
(1) Leases covering less than half of the undeveloped acreage will expire within
    the next three years.  However, the Company expects to evaluate this acreage
    prior to its expiration.  The Company's leases generally provide that the
    leases will continue past their primary terms if oil or gas in commercial
    quantities is being produced from a well on such leases.

Productive Well Summary

     The following table sets forth the Company's  ownership in productive wells
at December  31, 1999.  Gross oil and gas wells  include  multiple  completions.
Wells with  multiple  completions  are  counted  only once for  purposes  of the
following  table.  Production from various  formations in wells without multiple
completions is commingled.
<TABLE>
<CAPTION>

                                 Productive Wells
                              -----------------------
                              Gross              Net
                             -------          -------
              <S>            <C>              <C>
              Gas..........    878.0            344.8
              Oil..........  1,828.0          1,099.8
                             -------          -------
                    Total..  2,706.0          1,444.6
                             =======          =======
</TABLE>

Marketing

     There are a variety of factors  which affect the market for oil and natural
gas, including the extent of domestic production and imports of oil and gas, the
proximity  and  capacity  of  natural  gas  pipelines  and other  transportation
facilities,  demand for oil and gas, the marketing of competitive  fuels and the
effects of state and federal  regulations  on oil and gas  production and sales.
The Company has not  experienced  any  difficulties in marketing its oil or gas.
The oil and gas industry also  competes  with other  industries in supplying the
energy and fuel requirements of industrial, commercial and individual customers.

                                       9

<PAGE>

     Although  the  Company  seeks to  moderate  the impact of price  volatility
through its commodity  price risk  management  activities,  the Company  remains
subject  to price  fluctuations  for  natural  gas sold in the spot  market  due
primarily  to  seasonality  of demand and other  factors  beyond  the  Company's
control.  Domestic oil prices generally  follow worldwide oil prices,  which are
subject to price fluctuations resulting from changes in world supply and demand.

Production Sales Contracts

     In Wyoming,  the Company sells all of its natural gas,  natural gas liquids
and condensate from its Moxa Arch wells under a market sensitive long term sales
contract with Amoco Energy Trading  Corporation (the "Amoco Gas Contract").  The
price  payable  to the  Company  under  the Amoco  Gas  Contract  for gas is the
Northwest Pipeline Rocky Mountain Index, plus $0.03 per MMBtu, less fuel charges
and gathering fees and adjustments  for Btu content.  The Amoco Gas Contract was
renewed  effective  January 1, 1999 for an  additional  three year period on the
same terms.

     All  of  the  Company's  current  Moxa  Arch  Wyoming  oil  and  condensate
production  is sold at market  sensitive  prices  pursuant  to an option held by
Amoco.

     The Company's Moxa Arch wells are subject to various  gathering  agreements
with third  parties.  Wells  drilled  under the Amoco  Farmout  Agreement in the
Wilson Ranch,  Seven Mile Gulch and Bruff areas are subject to the Gas Gathering
and Processing Agreement dated March 20, 1992 with Northwest Pipeline. Gathering
fees under this  agreement are currently  $0.0762 per MMBtu and fuel charges are
0.5%.  Gathering  fees and fuel charges in the Cow Hollow/ Shute Creek areas are
currently $0.1386.

     In Texas,  Louisiana and Oklahoma,  the Company sells its gas to purchasers
under percentage of proceeds or index-based  contracts.  Under the percentage of
proceeds  contract,  the Company receives a fixed percentage of the resale price
received  by the  purchaser  for sales of residue  gas and  natural  gas liquids
recovered after gathering and processing the Company's gas. The Company receives
between 85% and 92% of the  proceeds  from residue gas sales and from 85% to 90%
of the  proceeds  from  natural gas  liquids  sales  received  by the  Company's
purchasers when the products are resold. The residue gas and natural gas liquids
sold by these  purchasers  are sold primarily  based on spot market prices.  The
revenue received by the Company from the sale of natural gas liquids is included
in natural gas sales.  Under  indexed-based  contracts,  the price per MMBtu the
Company  receives  for its gas at the  wellhead is tied to indexes  published in
Inside  FERC or Gas Daily,  and in most  cases is  subject to a discount  to the
relevant index in lieu of a gathering fee.

     All of the Company's oil production is sold under market  sensitive or spot
price contracts to various purchasers.

     Sales to individual customers constituting 10% or more of total revenues in
1999 were made to Aquila  Southwest  Pipeline (25%), Amoco Energy Trading (15%),
GPM Gas Marketing  (13%) and EOTT Energy Operating LP (11%).

     Management  believes that the loss of any one of the above  customers would
not have a material adverse effect on the Company's results of operations or its
financial position.

Price Risk Management Transactions

   Commodity Price Risk Management

     With the objective of achieving  more  predictable  revenues and cash flows
and reducing the exposure to fluctuations in gas and oil prices, the Company has
entered into price risk management transactions of various types with respect to
both  natural  gas  and  oil,  as  described  below.  While  the  use  of  these
arrangements  limits the downside risk of adverse  price  movements to a certain
extent,  it may also limit future revenues from favorable price  movements.  The
Company had entered into price risk  management  transactions  with respect to a
substantial  portion  of its estimated oil  production  and  approximately  50%
of its estimated gas production for 2000 and lesser amounts of its estimated
production for 2001 and beyond. The Company continues

                                       10

<PAGE>

to evaluate  whether to enter into  additional  such  transactions  for 2001 and
beyond.  In addition,  the Company may determine  from time to time to terminate
its then existing hedging and other risk management positions.

     All of the Company's price risk management  transactions are carried out in
the  over-the-counter  market  and  not  on the  New  York  Mercantile  Exchange
("NYMEX").  These financial counterparties all have at least an investment grade
credit  rating.  All  of  these   transactions   provide  solely  for  financial
settlements relating to closing prices on the NYMEX.

     The  following  is  a  summary  of  the  types  of  price  risk  management
transactions in effect as of December 31, 1999.

     Swaps. Since all of the Company's natural gas and oil is sold on "floating"
or  market  related  prices,   the  Company  has  entered  into  financial  swap
transactions  which  convert a floating  price  into a fixed  price for a future
month. For any particular swap transaction, the counterparty is required to make
a payment to the  Company in the event  that the NYMEX  Reference  Price for any
settlement period is less than the swap price for such hedge, and the Company is
required  to make a payment  to the  counterparty  in the  event  that the NYMEX
Reference  Price for any  settlement  period is greater  than the swap price for
such hedge.

     Reverse Swaps. When the Company  determines it desires to reduce the amount
of swaps because of an assumed  favorable  outlook for prices,  it enters into a
reverse swap.  Under such a transaction  the role of the Company and the role of
the counterparty are reversed.

     Collars.  A collar  provides  for an  average  floor  price and an  average
ceiling price.  For any  particular  collar  transaction,  the  counterparty  is
required to make a payment to the Company if the average NYMEX  Reference  Price
for the reference period is below the floor price for such transaction,  and the
Company is required to make  payment to the  counterparty  if the average  NYMEX
Reference Price is above the ceiling price for such transaction.

     Options, Puts and Straddles. When the Company believes that it will receive
a sufficiently high cash premium (or other  consideration)  for  granting the
counterparty a call or put option, it may enter into such a transaction.  If the
Company sold a $20.00 call on oil for $0.40 a barrel in a given month and prices
averaged  $19.00 a barrel  for such  month,  the  Company  would  receive  a net
realization  per barrel of $19.40 ($19.00 plus the $0.40 premium).  However,  if
for that  month the price of oil  averaged  $20.00 or  higher  per  barrel,  the
Company would receive a net realization of $20.40 (the call price,  $20.00, plus
$0.40).

     A  limited  number  of  these  transactions  contain  negotiated  knockout,
extendable  or  leverage   provisions.   These  provisions  either  limit  price
protection beyond a specific level, contain tiered pricing provisions, allow the
option to be extended for a period of time,  or provide for payment based upon a
multiple of the underlying  notional volume. The transactions  described in this
paragraph  and any sold  options are required to be marked to market as to their
value on the last day of the accounting period.

     The Company  sells  Wyoming  natural gas at prices  based on the  Northwest
Pipeline  Rocky  Mountain  Index  ("NPRMI")  and  the  Colorado  Interstate  Gas
Co.-Rocky Mountain Index ("CIGCo.-RMI")  (indices of prices for gas delivered at
various delivery points on the Northwest Pipeline and the CIGCo. pipeline in the
Northern Rocky Mountain area).  For natural gas sold against these indices,  the
Company has entered  into basis swaps that  require the  counterparty  to make a
payment to the Company in the event that the average NYMEX  Reference  Price per
MMBtu for gas delivered to Henry Hub,  Louisiana for a reference  period exceeds
the  average  price for gas  delivered  to the  Northwest  Pipeline in the Rocky
Mountains as reflected  in the NPRMI (the most liquid  Rocky  Mountain  hub) for
such  reference  period by more than a stated  differential,  and  requires  the
Company  to make a  payment  to the  counterparty  in the  event  that the NYMEX
Reference  Price for Henry Hub  exceeds the price for NPRMI gas by less than the
stated  differential (or in the event that the NPRMI price exceeds the Henry Hub
price).

                                       11

<PAGE>

Texas Severance Tax Abatement

     Production  from  natural  gas  wells  that have  been  certified  as tight
formations  or deep  wells by the  Texas  Railroad  Commission  ("high  cost gas
wells") and that were spudded or  completed  during the period from May 24, 1989
to September 1, 1996 qualify for an  exemption  from the 7.5%  severance  tax in
Texas on natural gas and  natural  gas  liquids  produced by such wells prior to
August 31, 2001. The natural gas production from wells drilled on certain of the
Company's properties in the Austin Chalk area qualify for this tax exemption. In
addition,  high cost gas wells that are spudded or  completed  during the period
from  September  1, 1996 to August 31, 2002 are  entitled to receive a severance
tax  reduction  upon  obtaining  a high  cost gas  certification  from the Texas
Railroad Commission within 180 days after first production. The tax reduction is
based on a formula  composed of the  statewide  "median" (as  determined  by the
State of Texas from producer  reports) and the  producer's  actual  drilling and
completion  costs.  More  expensive  wells will receive a greater  amount of tax
credit.  This tax rate  reduction  remains  in effect  for 10 years or until the
aggregate tax credits  received  equal 50% of the total  drilling and completion
costs.

Section 29 Tax Credit

     The natural gas  production  from wells drilled on certain of the Company's
properties  in the  Wyoming  Moxa Arch Trend and Golden  Trend Field in Oklahoma
qualifies for the Section 29 Tax Credit.  The Section 29 Tax Credit is an income
tax credit against regular federal income tax liability with respect to sales of
the Company's production of natural gas produced from tight gas sand formations,
subject to a number of  limitations.  Fuels  qualifying  for the  Section 29 Tax
Credit  must be  produced  from a well  drilled or a facility  placed in service
after November 5, 1990 and before January 1, 1993, and be sold before January 1,
2003.

     The basic credit,  which is currently  approximately $0.52 per MMBtu ($0.59
per Mcf) of natural gas produced from tight sand  reservoirs  and  approximately
$1.06 per MMbtu of natural gas  produced  from  Devonian  Shale,  is computed by
reference  to the  price  of crude  oil and is  phased  out as the  price of oil
exceeds $23.50 per Bbl in 1979 dollars (as adjusted for inflation) with complete
phaseout if such price  exceeds  $29.50 per Bbl in 1979 dollars (as adjusted for
inflation).  Under this formula, the commencement of phaseout would be triggered
if the  average  price  for crude oil rose  above  approximately  $48 per Bbl in
current dollars.  The Company generated  approximately  $0.6 and $0.7 million of
Section 29 Tax Credits in 1999 and 1998, respectively. The Section 29 Tax Credit
may not be credited  against the  alternative  minimum  tax,  but under  certain
circumstances  may be carried over and applied  against regular tax liability in
future years.  Therefore,  no assurances can be given that the Company's Section
29 Tax Credits will reduce its federal  income tax  liability in any  particular
year.

Regulation

     General.  The oil and gas  industry is  extensively  regulated  by federal,
state and local authorities.  In particular,  oil and gas production  operations
and economics are affected by price controls,  environmental protection statutes
and regulations, tax statutes and other laws relating to the petroleum industry,
as well as changes in such laws,  changing  administrative  regulations  and the
interpretations and application of such laws, rules and regulations. Oil and gas
industry  legislation  and  agency  regulation  are under  constant  review  for
amendment and expansion for a variety of political, economic and other reasons.

     Regulation of Natural Gas and Oil Exploration and Production. The Company's
operations are subject to various types of regulation at the federal,  state and
local levels.  Such regulation  includes  requiring  permits for the drilling of
wells,  maintaining bonding  requirements in order to drill or operate wells and
regulating the location of wells,  the method of drilling and casing wells,  the
surface use and  restoration  of  properties  upon which wells are drilled,  the
plugging and

                                       12

<PAGE>

abandoning  of  wells  and  the  disposal  of  fluids  used in  connection  with
operations.  The Company's  operations are also subject to various  conservation
laws and  regulations.  These include the regulation of the size of drilling and
spacing  units or proration  units and the density of wells which may be drilled
and the unitization or pooling of oil and gas properties.  In this regard,  some
states (such as Oklahoma)  allow the forced  pooling or integration of tracts to
facilitate  exploration  while other  states  (such as Texas) rely on  voluntary
pooling of lands and leases. In areas where pooling is voluntary, it may be more
difficult to form units and,  therefore,  more difficult to develop a project if
the  operator  owns  less  than  100%  of  the  leasehold.  In  addition,  state
conservation  laws establish maximum rates of production from oil and gas wells,
generally prohibit the venting or flaring of gas and impose certain requirements
regarding the  ratability of  production.  The effect of these  regulations  may
limit the amount of oil and gas the Company  can produce  from its wells and may
limit the number of wells or the  locations at which the Company can drill.  The
regulatory  burden on the oil and gas industry  increases the Company's costs of
doing business and,  consequently,  affects its profitability.  Inasmuch as such
laws and  regulations are frequently  expanded,  amended or  reinterpreted,  the
Company is unable to predict  the future cost or impact of  complying  with such
regulations.

     The Company has operations located on federal oil and gas leases, which are
administered  by the MMS. Such leases are issued  through  competitive  bidding,
contain  relatively  standardized terms and require compliance with detailed MMS
regulations.  In addition to permits  required from other  agencies (such as the
Army Corps of Engineers and the  Environmental  Protection  Agency (the "EPA")),
lessees must obtain a permit from the MMS prior to the commencement of drilling.
The MMS also has regulations  restricting the flaring or venting of natural gas,
liquid  hydrocarbons  and oil without  prior  authorization.  The MMS  generally
requires that lessees post substantial bonds or other acceptable assurances that
such  obligations  will be met.  The cost of such  bonds or other  surety can be
substantial and there is no assurance that bonds or other surety can be obtained
in  all  cases.  Under  certain  circumstances,  the  MMS  may  require  Company
operations on federal leases to be suspended or terminated.  Any such suspension
or termination  could  materially and adversely  affect the Company's  financial
condition and operations.

     The Company does not  anticipate  that  compliance  with existing  federal,
state  and  local  laws,   rules  and  regulations   will  have  a  material  or
significantly  adverse  effect  upon  the  capital  expenditures,   earnings  or
competitive position of the Company.

     Environmental  Regulation.  Activities  of the Company  with respect to the
exploration,  development  and  production of oil and natural gas are subject to
stringent  environmental  regulation  by state  and  federal  authorities.  Such
regulation has increased the cost of planning,  designing,  drilling,  operating
and in some  instances,  abandoning  wells.  In most  instances,  the regulatory
requirements  relate to the handling  and  disposal of drilling  and  production
waste products and waste created by water and air pollution control  procedures.
The risks of substantial  costs and liabilities  associated with such compliance
are  inherent  in oil and gas  operations,  and there can be no  assurance  that
significant costs and liabilities,  including civil and criminal penalties, will
not be  incurred.  Moreover,  it is possible  that other  developments,  such as
stricter and more  comprehensive  environmental  laws and regulations as well as
claims  for  damages  to  property  or  persons  resulting  from  the  Company's
operations could result in substantial costs and liabilities to the Company. The
Company   believes  that  it  is  in   substantial   compliance   with  existing
environmental  regulations,  and that any noncompliance will not have a material
adverse effect on operations or earnings.

Operating Hazards and Insurance

     Oil and gas  drilling  and  production  activities  are subject to numerous
risks, many of which are beyond the Company's  control.  These risks include the
risk that no  commercially  productive  oil or natural  gas  reservoirs  will be
encountered,  that operations may be curtailed,  delayed or canceled as a result
of  title   problems,   weather   conditions,   compliance   with   governmental
requirements,  mechanical difficulties or shortages or delays in the delivery of
equipment and that the availability or capacity of gathering systems,  pipelines
or  processing  facilities  may  limit  the  Company's  ability  to  market  its
production. There can be no assurance that new wells drilled by the Company will
be  productive  or that the  Company  will  recover  all or any  portion  of its
investment.  Drilling for oil and natural gas may involve unprofitable  efforts,
not only from dry wells,  but from wells that are  productive but do not produce
sufficient net revenues to return a profit after drilling,

                                       13

<PAGE>

operating  and  other  costs.  In  addition,  the  Company's  properties  may be
susceptible  to  hydrocarbon  drainage  from  production  by other  operators on
adjacent properties.

     Industry operating risks include the risk of fire,  explosions,  blow-outs,
pipe failure,  abnormally pressured formations and environmental hazards such as
oil spills, gas leaks,  ruptures or discharges of toxic gases, the occurrence of
any of which could result in substantial  losses to the Company due to injury or
loss of life, severe damage to or destruction of property, natural resources and
equipment,  pollution or other environmental damage, clean-up  responsibilities,
regulatory   investigation   and   penalties  and   suspension  of   operations.
Additionally,  certain of the Company's oil and gas operations are located in an
area that is  subject to  tropical  weather  disturbances,  some of which can be
severe enough to cause substantial  damage to facilities and possibly  interrupt
production.

     The Company  maintains  customary oil and gas related third party liability
coverage, which it must renew annually, that insures the Company against certain
sudden and accidental risks  associated with drilling,  completing and operating
its wells.  There can be no assurance  that this  insurance  will be adequate to
cover any losses or exposure to  liability  or that the Company  will be able to
renew its coverage  annually.  The Company and its  subsidiaries  carry workers'
compensation  insurance in all states in which they  operate.  While the Company
believes  this  coverage  is  customary  in the  industry,  it does not  provide
complete coverage against all operating risks.

Title to Properties

     Title to properties is subject to royalty, overriding royalty, carried, net
profits,  working  and other  similar  interests  and  contractual  arrangements
customary in the oil and gas industry, as well as to liens for current taxes not
yet due and to other  encumbrances.  As is customary in the industry in the case
of undeveloped  properties,  little investigation of record title is made at the
time of acquisition of leasehold  interests (other than a preliminary  review of
local records). Investigations,  including a title opinion of local counsel, are
generally made before commencement of drilling  operations.  To the extent title
opinions or other investigations reflect title defects, the Company, rather than
the seller of the  undeveloped  property,  is typically  responsible to cure any
such title defects at its expense.  If the Company were unable to remedy or cure
title defect of a nature such that it would not be prudent to commence  drilling
operations  on the  property,  the  Company  could  suffer a loss of its  entire
investment in the property. From time to time the Company's title to oil and gas
properties is challenged through legal  proceedings.  Under the terms of certain
of the Company's joint development,  participation and farmout  agreements,  the
Company's  interest (other than interests  acquired through holding of leasehold
interests prior to spudding of the well) in each well is conveyed to the Company
upon the successful completion of the well or satisfaction of other conditions.

Employees

     As of December 31, 1999, the Company had 181 full time  employees,  none of
whom is  represented  by  organized  labor  unions.  The Company  considers  its
employee relations to be good.

Office and Equipment

     The Company maintains its executive offices at 767 Fifth Avenue,  New York,
New York.  The Company  pays Robert A.  Belfer,  Chairman of the Board and Chief
Executive  Officer,  a fee of approximately  $250,000 per annum for office space
and services  provided through such office.  This fee is indexed to the consumer
price index.  The fee is based on the actual cost of such office space pro-rated
to the amount  utilized  in Company  operations.  The Company  believes  the fee
compares  favorably  to  the  terms  which  might  have  been  available  from a
non-affiliated party. See "Certain  Relationships and Related Transactions." The
Company owns a building in Dallas, Texas, containing approximately 65,000 square
feet which  serves as the  operations  headquarters.  The Company  leases  5,796
square  feet of  office  space  in  Tulsa,  Oklahoma  pursuant  to a lease  that
terminates  on August 31,  2000.  The Company  also leases  1,748 square feet of
office space in Midland,  Texas pursuant to a lease that  terminates on February
28,  2001.  Additionally,  the  Company  owns a  property  in  Granger,  Wyoming
consisting of a metal  building and  associated  four acres,  used by Belco as a
production office and yard. The Company also

                                       14

<PAGE>

maintains an inventory of field equipment and materials including tubular goods,
compressors, pumping units and field vehicles.

Forward-Looking Information and Risk Factors

     This document includes  "forward-looking  statements" within the meaning of
Section 27A of the  Securities  Act of 1933, as amended,  and Section 21E of the
Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements
other than statements of historical  facts included in this document  (including
the information incorporated by reference herein),  including without limitation
statements regarding planned capital  expenditures,  the availability of capital
resources to fund capital expenditures, estimates of proved reserves, the number
of  anticipated  wells to be  drilled  in 2000  and  thereafter,  the  Company's
financial position,  business strategy and other plans and objectives for future
operations, are forward-looking  statements.  Although the Company believes that
the expectations reflected in such forward-looking statements are reasonable, it
can give no assurance  that such  expectations  will prove to have been correct.
There are numerous uncertainties inherent in estimating quantities of proved oil
and natural gas reserves and in projecting future rates of production and timing
of  development  expenditures,  including many factors beyond the control of the
Company.  Reserve engineering is a subjective process of estimating  underground
accumulations  of oil and  natural  gas that cannot be measured in an exact way,
and the  accuracy  of any  reserve  estimate  is a  function  of the  quality of
available data and of engineering and geological interpretation and judgment. As
a result,  estimates made by different engineers often vary from one another. In
addition,  results of drilling, testing and production subsequent to the date of
an estimate  may justify  revisions  of such  estimate  and such  revisions,  if
significant, would change the schedule of any further production and development
drilling.  Accordingly,  reserve  estimates  are  generally  different  from the
quantities  of oil and natural  gas that are  ultimately  recovered.  Additional
important  factors that could cause actual results to differ materially from the
Company's  expectations  are described  elsewhere  herein.  All written and oral
forward-looking  statements attributable to the Company or persons acting on its
behalf are expressly qualified in their entirety by such factors.

   Volatility of Oil and Gas Prices; Marketability of Production

     The  Company's  revenue,  profitability  and  future  rate  of  growth  are
substantially  dependent upon the prevailing  prices of, and demand for, oil and
natural  gas.  The  Company's  ability to  maintain or  increase  its  borrowing
capacity  and  to  obtain  additional   capital  on  attractive  terms  is  also
substantially  dependent upon oil and gas prices. Prices for oil and natural gas
are subject to wide  fluctuation in response to relatively  minor changes in the
supply of and demand for oil and natural gas,  market  uncertainty and a variety
of additional factors that are beyond the control of the Company.  These factors
include the level of consumer product demand,  weather conditions,  domestic and
foreign  governmental  regulations,  the price and  availability  of alternative
fuels,  political  conditions in the Middle East,  the foreign supply of oil and
natural gas, the price of oil and gas imports and overall  economic  conditions.
From time to time, oil and gas prices have been depressed by excess domestic and
imported  supplies.  There can be no assurance that current price levels will be
sustained.  It is  impossible  to  predict  future  oil and  natural  gas  price
movements with any  certainty.  Low oil and natural gas prices reduce the amount
of the Company's oil and natural gas that can be produced economically,  and may
adversely  affect the Company's  financial  condition,  liquidity and results of
operations.  Market  prices for oil and gas have  moved over a very broad  range
during  the past two years.  Additionally,  substantially  all of the  Company's
sales of oil and natural  gas are made  pursuant  to  contracts  based on market
indexes and not pursuant to long-term fixed price contracts.  With the objective
of reducing  price risk,  the Company  enters into hedging and other  derivative
type transactions  with respect to a portion of its expected future  production.
There can be no assurance,  however,  that such commodity  price risk management
transactions  will  reduce  risk or mitigate  the effect of any  substantial  or
extended  decline in oil or natural  gas  prices.  Any  substantial  increase or
extended  decline  in the  prices of oil or  natural  gas could  have a material
adverse effect on the Company's financial condition and results of operations.

     In addition, the marketability of the Company's production depends upon the
availability  and capacity of gas gathering  systems,  pipelines and  processing
facilities.  Federal  and  state  regulation  of  oil  and  gas  production  and
transportation, general economic conditions and changes in supply and demand all
could adversely  affect the Company's  ability to produce and market its oil and
natural gas. If market factors were to change dramatically, the financial impact
on the Company could

                                       15

<PAGE>

be substantial.  The availability of markets and the volatility of product
prices are beyond the control of the Company and represent a significant risk.
See "Marketing" and "Management's Discussion and Analysis of Financial Condition
and Results of Operations-- Overview."

     Volatile  oil and gas prices make it  difficult  to  estimate  the value of
producing  properties for acquisition  and often cause  disruption in the market
for oil and gas  producing  properties,  as buyers and sellers  have  difficulty
agreeing on such value.  Price  volatility also makes it difficult to budget for
and project the return on acquisitions and development and exploration projects.

   Uncertainty of Estimates of Oil and Gas Reserves

     This 10-K contains  estimates of the Company's  proved oil and gas reserves
and the  estimated  future  net  revenues  therefrom  based  upon the  Company's
estimates and the reserve  report  prepared by Miller and Lents (the "Miller and
Lents  Report")  that  rely  upon  various  assumptions,  including  assumptions
required by the Securities and Exchange  Commission (the "Commission") as to oil
and gas prices, drilling and operating expenses, capital expenditures, taxes and
availability  of funds.  The  process  of  estimating  oil and gas  reserves  is
complex,  requiring  significant  decisions and assumptions in the evaluation of
available  geological,  geophysical,  engineering  and  economic  data  for each
reservoir.  As a result, such estimates are inherently imprecise.  Actual future
production,  oil and gas  prices,  revenues,  taxes,  development  expenditures,
operating  expenses and quantities of recoverable  oil and gas reserves may vary
substantially from those estimated in the Company's estimates and the Miller and
Lents Report.  Any significant  variance in these  assumptions  could materially
affect the  estimated  quantity and value of reserves set forth in this 10-K. In
addition,  the  Company's  proved  reserves may be subject to downward or upward
revision  based  upon  production  history,  results of future  exploration  and
development,  prevailing oil and gas prices and other factors, many of which are
beyond the Company's control. Actual production,  revenues,  taxes,  development
expenditures and operating  expenses with respect to the Company's reserves will
likely vary from the estimates used, and such variances may be material.

     Approximately  25% of the Company's  total proved  reserves at December 31,
1999 were undeveloped,  which are by their nature less certain. Recovery of such
reserves will require significant  capital  expenditures and successful drilling
operations. The reserve data set forth in the Company's estimates and the Miller
and Lents Report assumes that  substantial  capital  expenditures by the Company
will be required to develop such reserves.  Although cost and reserve  estimates
attributable  to the  Company's  oil and gas  reserves  have  been  prepared  in
accordance with industry standards, no assurance can be given that the estimated
costs are accurate, that development will occur as scheduled or that the results
will be as estimated. See "Properties -- Oil and Gas Reserves."

     The present  value of future net  revenues  referred to in this 10-K should
not be  construed  as the  current  market  value of the  estimated  oil and gas
reserves attributable to the Company's properties. In accordance with applicable
requirements of the Commission,  the estimated  discounted future net cash flows
from proved  reserves are generally  based on prices and costs as of the date of
the estimate, whereas actual future prices and costs may be materially higher or
lower.  Actual  future net cash  flows also will be  affected  by  increases  or
decreases in production,  changes in governmental  regulations or taxation.  The
timing of actual  future  net cash flows from  proved  reserves,  and thus their
actual present value,  will be affected by the timing of both the production and
the incurrence of expenses in connection with  development and production of oil
and gas properties.  In addition,  the 10% discount factor, which is required by
the  Commission to be used in calculating  discounted  future net cash flows for
reporting  purposes,  is not  necessarily the most  appropriate  discount factor
based on interest  rates in effect from time to time and risks  associated  with
the Company or the oil and gas industry in general.

   Reserve Replacement

     As is customary in the oil and gas exploration and production industry, the
Company's  future success  depends upon its ability to find,  develop or acquire
additional oil and gas reserves that are  economically  recoverable.  Unless the
Company replaces its estimated proved reserves (through development, exploration
or acquisition),  the Company's  proved reserves will generally  decline as they
are produced.

                                       16

<PAGE>

     Exploratory drilling and, to a lesser extent,  development drilling involve
a high degree of risk that no commercial production will be obtained or that the
production will be insufficient to recover  drilling and completion  costs.  The
costs of drilling,  completing and operating wells are uncertain.  The Company's
drilling  operations  may be  curtailed,  delayed  or  canceled  as a result  of
numerous factors, including title problems, weather conditions,  compliance with
governmental  requirements and shortages or delays in the delivery of equipment.
Furthermore,  completion of a well does not assure a profit on the investment or
a recovery of drilling,  completion and operating costs. See " -- Costs Incurred
and Drilling Results."

     The Company's current strategy includes increasing its reserve base through
acquisitions of leaseholds with drilling  potential and by continuing to exploit
its existing properties. There can be no assurance,  however, that the Company's
exploration  and  development  projects  will result in  significant  additional
reserves or that the Company will have continuing  success  drilling  productive
wells at economically  viable costs.  Furthermore,  while the Company's revenues
may  increase  if  prevailing  oil and gas prices  increase  significantly,  the
Company's finding costs for additional reserves could also increase.

For a discussion  of the  Company's  reserves,  see  "Properties  -- Oil and Gas
Reserves."

   Ceiling Limitation Writedowns

     The Company reports its operations using the full cost method of accounting
for oil and gas  properties.  Under  the full  cost  accounting  rules,  the net
capitalized  costs of proved  oil and gas  properties  may not exceed a "ceiling
limit",  calculated at the end of each quarter,  which is based upon the present
value of estimated  future net cash flows from proved  reserves,  discounted  at
10%, plus the lower of cost or fair market value of unproved properties,  net of
related tax effects.  If net capitalized  costs of proved oil and gas properties
exceed the  ceiling  limit,  the  Company  is  subject  to a ceiling  limitation
writedown  to the extent of such  excess.  A ceiling  limitation  writedown is a
charge to earnings which does not impact cash flows.  However,  such  writedowns
impact  the  amount of the  Company's  stockholders'  equity.  The risk that the
Company  will be  required to write down the  carrying  value of its oil and gas
properties  increases  when  oil and  gas  prices  are  depressed  or  volatile.
Application  of these rules during  periods of relatively low oil or gas prices,
even if temporary,  may result in a ceiling writedown.  In addition,  writedowns
may  occur if the  Company  makes  additional  acquisitions  or has  substantial
downward revisions in its estimated proved reserves.  Unpredictable  declines in
oil and gas prices increase the risk that the Company will be required to record
a ceiling  limitation  writedown.  See "--  Volatility  of Oil and  Natural  Gas
Prices;  Marketability  of  Production."  No ceiling  limitation  writedown  was
required  for the  calendar  year 1999.  For the year 1998 the Company  recorded
approximately  $229 million  ($149 million  after-tax) of non-cash  ceiling test
provisions  after applying  substantially  lower  commodity  prices to estimated
recoverable  reserves.  At  year-end  1997,  the  Company  recorded  a non- cash
writedown of approximately $150 million ($97.5 million after tax), a significant
portion of which was attributable to the 1997 acquisition of Coda and lower
year-end reserve values due to lower year-end oil and gas prices. No assurance
can be given  that  the  Company  will not  experience  additional  ceiling
limitation writedowns in the future. See "Management's Discussion and Analysis
of Financial Condition and Results of Operations."

   Substantial Capital Requirements

     The  Company   makes,   and  expects  to  continue  to  make,   substantial
expenditures for the development, exploration, acquisition and production of oil
and natural gas reserves.  The Company incurred  capital  expenditures of $133.0
million  during  1998 and $74.0  million  during  1999.  For the year 2000,  the
Company has budgeted $60 million in capital  expenditures  for  exploration  and
development   operations.   Management  believes  that  the  Company  will  have
sufficient cash provided by operating activities to fund capital expenditures in
2000. However, if revenues or cash flows from operations decrease as a result of
lower oil and natural gas prices or operating  difficulties,  the Company may be
limited in its ability to expend the capital  necessary to undertake or complete
its current  drilling  plans,  or it may be forced to raise  additional  debt or
equity proceeds to fund such  expenditures in the future.  The Company's  credit
facility  currently  limits the amounts the Company may borrow to $150  million,
subject to increase or decrease based upon borrowing base adjustments. There can
be no assurance that  additional  debt or equity  financing or cash generated by
operations will be available to meet all these  requirements.  See "Management's
Discussion  and Analysis of Financial  Condition  and Results of  Operations  --
Liquidity and Capital Resources."

                                       17

<PAGE>

   Acquisition Risks

     The Company  continues to pursue the selective  acquisition  of oil and gas
properties and businesses. Although no definitive agreements, other than matters
disclosed  elsewhere  in this  filing,  have  been  reached  regarding  any such
acquisitions, if consummated such acquisitions may have a material impact on the
Company's  business.  Any acquisition by the Company must satisfy the applicable
covenants  set forth in the  indenture  governing  the  Company's  8-7/8% Senior
Subordinated Notes due 2007 (the "8-7/8%  Indenture"),  the indenture  governing
the  Company's  10-1/2%  Senior   Subordinated  Notes  due  2006  (the  "10-1/2%
Indenture") and the credit  agreement (the "Credit  Agreement")  relating to the
Company's Credit Facility (as defined herein).

     The  successful  acquisition  of producing  properties  generally  requires
accurate  assessments  of: (i)  recoverable  reserves;  (ii)  future oil and gas
prices and operating costs; (iii) potential environmental and other liabilities;
and (iv) other  factors.  Such  assessments  are  necessarily  inexact and their
accuracy inherently uncertain.  It generally is not feasible to review in detail
every individual property involved in an acquisition. Ordinarily, review efforts
are  focused  on the  higher-valued  properties.  Nevertheless,  even a detailed
review of all  properties  and  records  may not reveal  existing  or  potential
problems nor will it permit the Company to become sufficiently familiar with the
properties to assess fully their deficiencies and capabilities.  Inspections are
not  always  performed  on  every  well,  and  environmental  problems,  such as
groundwater   contamination,   are  not  necessarily  observable  even  when  an
inspection is undertaken.

   Holding Company Structure

     The  Company   conducts  all  of  its  operations   through   subsidiaries.
Accordingly,  the  Company  relies  on  dividends  and  cash  advances  from its
subsidiaries to provide funds necessary to meet its obligations, and the Company
will  rely  upon such  sources  of funds to pay  interest  on  indebtedness  and
dividends on the  Preferred  Stock.  The ability of any such  subsidiary  to pay
dividends or make cash  advances is subject to applicable  laws and  contractual
restrictions  as well as the financial  condition and operating  requirements of
such subsidiary.

   Restrictions Upon Ability to Pay Dividends

     The ability of the Company to make dividend payments on the Preferred Stock
will  be  dependent  on the  Company's  future  performance  and  liquidity.  In
addition,  the Credit Agreement,  the 8-7/8% Indenture and the 10-1/2% Indenture
contain  restrictions on the ability of the Company to pay cash dividends on its
capital stock,  including the Preferred Stock. The Credit Agreement  permits the
Company  to pay  cash  dividends  of up to $50  million  in  the  aggregate  and
restricts additional  dividends to 50% of the Company's cumulative  consolidated
net income (as defined in the Credit  Agreement)  (or if such  consolidated  net
income is a deficit,  100% of such  deficit)  from  October 1, 1997,  subject to
increases and  decreases to such  cumulative  amount based on other  adjustments
specified in the Credit  Agreement.  The Credit  Agreement  also  prohibits  the
Company  from  paying cash  dividends  if there is a default or event of default
under the Credit Agreement. The 8-7/8% Indenture permits the Company to pay cash
dividends  of up to  $25  million  in the  aggregate  and  restricts  additional
dividends to 50% of the Company's cumulative consolidated net income (as defined
in the 8-7/8% Indenture) (or if such consolidated net income is a deficit,  100%
of such  deficit)  from October 1, 1997,  subject to increases  and decreases to
such  cumulative  amount  based on other  adjustments  specified  in the  8-7/8%
Indenture.  The 8-7/8% Indenture also prohibits the payment of cash dividends in
the  event  that (i) the  Company  would  not be  permitted  to  incur  $1.00 of
additional  indebtedness  under the 8-7/8%  Indenture  at the time of a proposed
dividend payment based on its inability to satisfy a fixed charge coverage ratio
or (ii) there is a default or event of default under the 8-7/8%  Indenture.  The
10-1/2%  Indenture permits the Company to pay cash dividends of up to $5 million
in the aggregate and would restrict additional dividends to 50% of the Company's
cumulative  consolidated net income (as defined in the 10-1/2% Indenture) (or if
such  consolidated net income is a deficit,  100% of such deficit) from April 1,
1996,  subject to increases  and  decreases to such  cumulative  amount based on
other adjustments specified in the 10-1/2% Indenture.  The Company currently has
capacity beyond the $5 million dividend limit under the 10-1/2%  Indenture.  The
10-1/2% Indenture would also prohibit the payment of cash dividends in the event
that  (i) the  Company  would  not be  permitted  to incur  $1.00 of  additional
indebtedness under the 10-1/2% Indenture

                                       18

<PAGE>

at the time of a proposed  dividend  payment based on its inability to satisfy a
fixed charge coverage ratio or (ii) there is a default or event of default under
the 10-1/2% Indenture.

   Operating Hazards and Uninsured Risks; Production Curtailments

     Oil and gas  drilling  and  production  activities  are subject to numerous
risks, many of which are beyond the Company's  control.  These risks include the
risk that no  commercially  productive  oil or natural  gas  reservoirs  will be
encountered,  that  operations  may be  curtailed,  delayed or canceled and that
title problems,  weather conditions,  compliance with governmental requirements,
mechanical difficulties or shortages or delays in the delivery of drilling rigs,
work boats and other  equipment  may limit the  Company's  ability to market its
production. There can be no assurance that new wells drilled by the Company will
be  productive  or that the  Company  will  recover  all or any  portion  of its
investment.  In  addition,  the  Company's  properties  may  be  susceptible  to
hydrocarbon drainage from production by other operators on adjacent properties.

     Industry operating risks include the risk of fire,  explosions,  blow-outs,
pipe failure,  abnormally pressured formations and environmental hazards such as
oil spills, gas leaks,  ruptures or discharges of toxic gases, the occurrence of
any of which could result in substantial  losses to the Company due to injury or
loss of life, severe damage to or destruction of property, natural resources and
equipment,  pollution or other environmental damage, clean-up  responsibilities,
regulatory   investigation   and   penalties  and   suspension  of   operations.
Additionally,  certain of the Company's oil and gas operations are located in an
area that is  subject to  tropical  weather  disturbances,  some of which can be
severe enough to cause substantial  damage to facilities and possibly  interrupt
production.   In  accordance  with  customary  industry  practice,  the  Company
maintains  insurance  against some, but not all, of the risks  described  above.
There can be no assurance that any insurance will be adequate to cover losses or
liabilities.  The Company cannot predict the continued availability of insurance
at premium levels that justify its purchase. Losses and liabilities arising from
uninsured or  under-insured  events could have a material  adverse effect on the
financial condition and results of operations of the Company.

     From time to time, due primarily to contract terms, pipeline  interruptions
or weather conditions, the producing wells in which the Company owns an interest
may be subject to production curtailments.  The curtailments may vary from a few
days to several months.  In most cases the Company will be provided only limited
notice  as to  when  production  will be  curtailed  and  the  duration  of such
curtailments. The Company is currently not curtailed on any of its production.

   Competition

     The  Company  operates  in a highly  competitive  environment.  The Company
competes with major and independent oil and gas companies for the acquisition of
desirable  oil and gas  properties,  as well  as for  the  equipment  and  labor
required to develop and operate such properties.  Many of these competitors have
financial and other resources substantially greater than those of the Company.

   Risks of Price Risk Management Transactions

     In order to manage its exposure to price risks in the  marketing of its oil
and  natural  gas,  the Company has in the past and expects to continue to enter
into oil and natural gas price risk  management  arrangements  with respect to a
portion of its  expected  production.  These  arrangements  may include  futures
contracts on the NYMEX fixed price delivery contracts and financial swaps. While
intended  to reduce the  effects of  volatility  of the price of oil and natural
gas,  such  transactions  may limit  potential  gains by the  Company if oil and
natural gas prices were to rise or fall substantially over the price established
by the arrangement. In addition, such transactions may expose the Company to the
risk of financial loss in certain  circumstances,  including instances in which:
(i)  production  is less than  expected;  (ii) if there is a  widening  of price
differentials  between  delivery  points for the  Company's  production  and the
delivery  point  assumed in the  arrangement;  (iii) the  counterparties  to the
Company's future contracts fail to perform under the contract; or (iv) a sudden,
unexpected  event  materially  impacts oil or natural gas prices.  See "-- Price
Risk  Management  Transactions"  and  "Management's  Discussion  and Analysis of
Financial   Condition  and  Results  of  Operations  --  Liquidity  and  Capital
Resources."

                                       19

<PAGE>

   Governmental Regulation

     Oil and gas operations are subject to various United States federal,  state
and local governmental  regulations that change from time to time in response to
economic  or  political  conditions.   Matters  subject  to  regulation  include
discharge  permits for  drilling  operations,  drilling and  abandonment  bonds,
reports concerning operations, the spacing of wells, and unitization and pooling
of properties and taxation.  From time to time, regulatory agencies have imposed
price controls and  limitations on production by restricting the rate of flow of
oil and gas wells below actual production capacity in order to conserve supplies
of oil and gas. In addition, the production,  handling, storage,  transportation
and  disposal  of oil and gas,  by-products  thereof  and other  substances  and
materials produced or used in connection with oil and gas operations are subject
to regulation  under  federal,  state and local laws and  regulations  primarily
relating to protection of human health and the environment. The Company may also
be subject to substantial  clean-up  costs for any toxic or hazardous  substance
that may exist under any of its current  properties  or  properties  that it has
operated in the past. To date, expenditures related to complying with these laws
and for  remediation  of  existing  environmental  contamination  have  not been
significant in relation to the results of operations of the Company.

     Although  the Company  believes it is in  substantial  compliance  with all
applicable  laws and  regulations,  the  requirements  imposed  by such laws and
regulations are frequently changed and subject to  interpretation.  In addition,
the recent trend toward  stricter  standards in  environmental  legislation  and
regulation is likely to continue. For instance, legislation has been proposed in
Congress from time to time that would  reclassify  certain crude oil and natural
gas exploration and production wastes as "hazardous wastes" which would make the
reclassified  wastes  subject  to much more  stringent  handling,  disposal  and
clean-up  requirements.  If such legislation were to be enacted, it could have a
significant impact on the operating costs of the Company, as well as the oil and
gas industry in general.  The Company  could incur  substantial  costs to comply
with  environmental  laws and regulations,  and the Company is unable to predict
the ultimate cost of compliance  with these  requirements or their effect on its
production. See "-- Regulation."

   Reliance on Key Personnel

     The Company depends, and will continue to depend in the foreseeable future,
on the services of its officers and key employees with extensive  experience and
expertise in evaluating  and  analyzing  producing  oil and gas  properties  and
drilling  prospects,  maximizing  production  from  oil and gas  properties  and
marketing  oil and gas  production.  The  ability  of the  Company to retain its
officers and key employees is important to the  continued  success and growth of
the Company.

     The Company is dependent upon Robert A. Belfer,  the Company's Chairman and
Chief Executive Officer, and Laurence D. Belfer, the Company's Vice Chairman and
Chief Operating Officer, in addition to certain of its other executive officers.
The unexpected  loss of the services of one or more of these  individuals  could
have a detrimental effect on the Company.  The Company does not maintain key man
life  insurance  on any of its officers or key  employees.  See  "Directors  and
Executive Officers of the Registrant."

   Control by Certain Stockholders

     Robert A. Belfer,  his son Laurence D. Belfer, his brother-in-law Jack
Saltz, their spouses, and certain trusts for their respective children and
grandchildren own approximately 60% of the outstanding  shares of the Common
Stock and approximately 16% of the outstanding  shares of the Preferred Stock.
As a result, such stockholders will be able to effectively control the outcome
of certain matters requiring a stockholder vote, including the election of
directors.  Such ownership of Common Stock may have the effect of  delaying,
deferring  or  preventing  a change of control of the Company and may adversely
affect the voting and other rights of other stockholders.



                                       20

<PAGE>


Executive Officers of the Registrant

     Officers  are elected  each year by the Board of  Directors  following  the
Annual  Meeting for a term of one year and until the election and  qualification
of their  successors.  The current  executive  officers of the Company and their
ages, positions with the Company and business experience are presented below:

     Robert A.  Belfer,  age 64, is  Chairman  of the Board and Chief  Executive
Officer of the  Company.  Mr.  Belfer began his career at BPC in 1958 and became
Executive Vice President in 1964, President in 1965 and Chairman of the Board in
1984.  BPC was an  independent  oil and gas  producer  in the United  States and
abroad,  which went public in 1959. It was one of the larger independent oil and
gas companies in the United States and was included in Fortune's  listing of the
500 largest  industrial  companies  in the United  States  prior to merging with
InterNorth,  Inc. (now Enron Corp.) in 1983.  Following  the merger,  Mr. Belfer
became Chief Operating Officer of BelNorth Petroleum Corp., a combination of oil
and gas  producing  operations  of BPC and  InterNorth.  He  resigned  from  his
position with InterNorth in 1986 and pursued personal investments in oil and gas
and other industries. In April 1992, Mr. Belfer founded the Company. In addition
to his position at the Company, Mr. Belfer serves on the board of Enron.
Mr.  Belfer  received his  undergraduate  degree from Columbia College  (A.B.
1955) and a law degree from the Harvard Law School (J.D.  1958).

     Laurence D. Belfer, age 33, is Vice-Chairman and Chief Operating Officer of
the Company.  Mr. Belfer joined the Company as Vice President in September 1992.
He was promoted to  Executive  Vice  President  in May 1995 and Chief  Operating
Officer in December 1995, was named President in April 1997 and Vice-Chairman in
March, 1999. He is a founder and Chairman of Harvest  Management,  Inc., a money
management  firm. Mr. Belfer  graduated from Harvard  University (B.A. 1988) and
from Columbia Law School (J.D. 1992).

     Grant W.  Henderson,  age 41, is  President  of the  Company.  He was named
President effective March 1, 1999 and prior to his promotion he served as Senior
Vice President-Corporate  Development.  Mr. Henderson was formerly President and
Chief  Financial  Officer of Coda and joined Coda in October  1993 as  Executive
Vice President and Chief Financial Officer. He was elected a director of Coda in
1995 and became President of Coda in February 1996. Mr. Henderson was previously
employed by NationsBank,  beginning 1981,  last serving as Senior Vice President
in its Energy  Banking  Group.  Mr. Henderson  is a graduate  of Texas Tech
University  where he  received a B.B.A. degree with a major in finance.

     Dominick  J.  Golio,  age 54, is Senior  Vice  President--  Finance,  Chief
Financial Officer,  Treasurer and Secretary of the Company.  Mr. Golio began his
career at the New York City office of Arthur Andersen & Co. in 1972. In 1975, he
joined Case, Pomeroy & Company and Felmont Oil Corporation,  its publicly traded
affiliate,  where he rose to the position of Vice President  Finance.  Mr. Golio
left Felmont in 1987  following a merger  between  Felmont and Homestake  Mining
Company.  He served as Vice  President  Finance and  Administration  at both AEG
Corporation,  the U.S.  electronics  subsidiary of  Daimler-Benz  North America,
until 1991 and at Millmaster Onyx Group, Inc. until September 1993 at which time
he joined the Company. Mr. Golio is a Certified Public Accountant (NY). He holds
undergraduate  and graduate  degrees from Pace  University  (B.B.A.  Accounting,
1972, M.B.A.-- Taxation, 1978).

     Shiv K.  Sharma,  age 58, is Senior Vice  President --  Engineering  of the
Company.  Mr. Sharma began his career in 1967 as a Reservoir Engineer with Shell
Oil Company. In 1970, he joined BPC as a reservoir engineer and was subsequently
elected to Vice President and Senior Vice President of  Engineering,  a position
he held until his departure  from that company in 1988.  From 1988 to 1992,  Mr.
Sharma  worked as a petroleum  consultant  for several  New York  companies.  He
served as a director and consultant to the Company commencing April 1992 and was
elected to his present position in April 1994.

                                       21

<PAGE>

Mr. Sharma received his degrees in petroleum technology from the Indian School
of Mines (B.S. 1963) and petroleum engineering from Stanford University (M.S.
1966).

     Steven L.  Mueller,  age 47, is Senior Vice  President --  Exploration  and
Production of the Company.  Mr. Mueller began his career in 1975 as a Geological
Engineer  at Tenneco  Oil,  Lafayette.  He  advanced  at Tenneco Oil to Division
Exploration  Manager in 1987. In 1988,  Mr.  Mueller joined Fina Oil in Houston,
Texas as Exploration Manager of South Louisiana,  and in 1992 he joined American
Exploration  in  Houston,  Texas as  Exploitation  Vice  President.  He was with
American  Exploration  until  October  of 1996 when he joined the  Company.  Mr.
Mueller has over 24 years experience in exploring for and exploiting oil and gas
fields both onshore and offshore.  He holds a BS in Geological  Engineering from
the Colorado School of Mines (1975).

Certain Definitions

     The  definitions set forth below shall apply to the indicated terms as used
in this 10-K.  All volumes of natural  gas  referred to herein are stated at the
legal  pressure  base of the state or area  where the  reserves  exist and at 60
degrees  Fahrenheit  and in most  instances  are  rounded to the  nearest  major
multiple.

     AMI.  Area of mutual interest.

     Bbl.  One stock tank barrel,  or 42 U.S. gallons liquid volume, used herein
in reference to crude oil or other liquid hydrocarbons.

     Bcf.  Billion cubic feet.

     Bcfe.  Billion cubic feet  equivalent,  determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil,  condensate or natural gas  liquids.

     BOE.  Barrel of oil equivalent (converting six Mcf of natural gas to one
Bbl of oil).

     BOPD.  Barrels of oil per day.

     Btu.  British  thermal  unit,  which is the heat required to raise the tem-
perature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

     Completion. The installation of permanent equipment for the production of
oil or natural gas, or in the case of a dry hole, the reporting of abandonment
to the appropriate agency.

     Developed acreage.  The number of acres that are allocated or assignable to
producing wells or wells capable of production.

     Development  well.  A well  drilled  within  the  proved  area of an oil or
natural  gas  reservoir  to the  depth of a  stratigraphic  horizon  known to be
productive.

     Dry hole or well. A well found to be incapable of producing hydrocarbons in
sufficient quantities such that proceeds from the sale of such production exceed
production expenses and taxes.

     Exploratory  well.  A well  drilled to find and  produce oil or natural gas
reserves not classified as proved, to find a new reservoir in a field previously
found to be productive of oil or natural gas in another reservoir or to extend a
known reservoir.

     Field. An area consisting of a single reservoir or multiple  reservoirs all
grouped on or  related  to the same  individual  geological  structural  feature
and/or stratigraphic condition.

                                       22

<PAGE>

     Finding costs. Total costs incurred in oil and gas acquisition, exploration
and  development  activities and capitalized  interest  divided by total reserve
additions,  including purchases of minerals in place,  extensions,  discoveries,
revisions and other additions.

     Gross acres or gross wells.  The total acres or wells,  as the case may be,
in which a working interest is owned.

     Infill well. A well drilled between known producing wells to better exploit
the reservoir.

     Liquids.  Crude oil, condensate and natural gas liquids.

     MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.

     Mcf.  One thousand cubic feet.

     Mcf/d.  One thousand cubic feet per day.

     Mcfe. One thousand cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

     MMS.  Mineral Management Service of the United States Department of the
Interior.

     MMBbls. One million barrels of crude oil or other liquid hydrocarbons.

     MMBOE.  One million barrels of oil equivalent.

     MMBtu.  One million Btus.

     MMcf.  One million cubic feet.

     MMcfe. One million cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

     Net acres or net wells. The sum of the fractional  working  interests owned
in gross acres or gross wells, as the case may be.

     Oil.  Crude oil and condensate.

     Operating  cash inflows per Mcfe.  Net operating  cash inflows as listed in
the  Consolidated  Statements  of  Cash  Flows  in  the  Consolidated  Financial
Statements divided by net gas equivalent production for the applicable periods.

     Present  Value or PV10.  When  used with  respect  to oil and  natural  gas
reserves, the estimated future gross revenue to be generated from the production
of proved reserves,  net of estimated  production and future  development costs,
using prices and costs in effect as of the date indicated, without giving effect
to non-property  related expenses such as general and  administrative  expenses,
debt service and future  income tax expenses or to  depreciation,  depletion and
amortization, discounted using an annual discount rate of 10%.

     Productive  well.  A  well  that  is  found  to  be  capable  of  producing
hydrocarbons  in sufficient  quantities such that proceeds from the sale of such
production exceed production expenses and taxes.

     Proved developed nonproducing reserves.  Proved developed reserves expected
to be recovered from zones behind casing in existing wells.

                                       23

<PAGE>

     Proved developed  producing  reserves.  Proved developed  reserves that are
expected to be recovered from  completion  intervals  currently open in existing
wells and capable of production to market.

     Proved  reserves.  The estimated  quantities of crude oil,  natural gas and
natural gas liquids  that  geological  and  engineering  data  demonstrate  with
reasonable  certainty to be  recoverable  in future years from known  reservoirs
under existing economic and operating conditions.

     Proved  undeveloped  location.  A site on which a  development  well can be
drilled  consistent  with  spacing  rules  for  purposes  of  recovering  proved
undeveloped reserves.

     Proved  undeveloped  reserves.  Proved  reserves  that are  expected  to be
recovered  from new wells on undrilled  acreage or from  existing  wells where a
relatively major expenditure is required for recompletion.

     Recompletion.  The  completion  for  production of an existing well bore in
another formation from that in which the well has been previously completed.

     Reservoir.  A porous  and  permeable  underground  formation  containing  a
natural  accumulation  of producible  oil and/or natural gas that is confined by
impermeable  rock or water  barriers and is  individual  and separate from other
reservoirs.

     Royalty interest.  An interest in an oil and natural gas property entitling
the  owner  to a  share  of oil or  natural  gas  production  free of  costs  of
production.

     Undeveloped acreage.  Lease acreage on which wells have not been drilled or
completed to a point that would permit the  production of commercial  quantities
of oil and  natural gas  regardless  of whether  such  acreage  contains  proved
reserves.

     Updip.  A higher point in the reservoir.

     Working interest.  The operating interest that gives the owner the right to
drill,  produce and conduct operating  activities on the property and to a share
of production.

     Workover.  Operations on a producing well to restore or increase produc-
tion.

See also the Consolidated Financial Statements beginning on page F-1.

ITEM 2 -- PROPERTIES

Oil and Gas Reserves

     The following  table sets forth  information  with respect to the Company's
estimated  net proved oil and gas reserves as of December 31, 1999.  Information
in this 10-K as of December  31, 1999  relating  to  properties  with 83% of the
Company's  estimated  net proved oil and gas reserves  (84% of the PV10) and the
estimated future net revenues  attributable thereto is based upon the Miller and
Lents,  Ltd.  Report,  independent  petroleum  engineers.  All  calculations  of
estimated net proved  reserves  have been made in accordance  with the rules and
regulations of the Commission and, except as otherwise indicated, give no effect
to federal or state income taxes otherwise  attributable to estimated future net
revenues from the sale of oil and

                                       24

<PAGE>

gas.  The present  value of estimated  future net  revenues has been  calculated
using a discount factor of 10%. See "Business -- Forward-Looking  Statements and
Risk Factors -- Uncertainty of Estimates of Oil and Gas Reserves."
<TABLE>
<CAPTION>

                                                As of December 31, 1999
                                         -----------------------------------
                                           Proved        Proved
                                         Developed    Undeveloped      Total
                                         ---------    -----------     -------
<S>                                      <C>          <C>             <C>
Estimated Proved Reserves:
  Gas (Bcf).............................   224.1          98.0         322.1
  Oil (MMBbls)..........................    42.4          10.7          53.1
Total Gas Equivalents (Bcfe)............   478.3         162.3         640.6
Estimated Future Net Revenue before
 Income Taxes (in millions)(1)..........$1,014.9        $239.9      $1,254.8
Present Value of Estimated Future
 Net Revenues before Income Taxes
 (discounted at 10% per annum)
 (in millions)(1).......................  $527.8        $106.9        $634.7
</TABLE>

(1) Estimated future net revenue before income taxes represents estimated future
    gross revenue to be generated from the production of proved reserves, net
    of estimated production and future development costs, using average December
    31, 1999 prices, which were $2.14 per Mcf of gas and $23.79 per barrel of
    oil without giving effect to commodities price risk management activities
    accounted for as hedges. At December 31,  1999, the estimated future net
    revenue before income taxes and the present value of such estimated future
    net revenue before income taxes related to such price risk management
    activities were ($8.6) million and ($8.2) million, respectively (based on
    oil and gas prices in effect at December 31, 1999), which amounts have not
    been subtracted from estimated future net revenue before income taxes and
    its present value as shown above. If such amounts were subtracted, estimated
    future net revenue before income taxes would equal $1,006.3 million (Proved
    Developed) and $1,246.2 million (Total) and present values of such estimated
    future net revenues before income taxes would equal $519.2 million (Proved
    Developed) and $626.5 million (Total).

See also "Business."

ITEM 3 -- LEGAL PROCEEDINGS

     The Company is a named  defendant in routine  litigation  incidental to its
business.  While the ultimate results of these  proceedings  cannot be predicted
with  certainty,  the Company does not believe that the outcome of these matters
will have a material adverse effect on the Company.

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

     During the quarter ended  December 31, 1999,  no matters were  submitted by
the Company to a vote of its security holders.

                                     PART II

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

     As of March 15, 2000, the Company  estimates there were  approximately  123
record holders of its Common Stock.  The Company's Common Stock is listed on the
New York Stock Exchange  ("NYSE") and traded under the symbol "BOG." As of March
15, 2000, the Company had 31,092,400 shares outstanding and its closing price on
the NYSE was $8.5625 per share.  The high and low sales prices for the Company's
Common Stock  during each quarter in the two years ended  December 31, 1999 were
as follows:

                                       25

<PAGE>
<TABLE>
<CAPTION>

                                       COMMON STOCK
                                   ---------------------
                                   High              Low
                                  ------           ------
     <S>                          <C>              <C>
     1998
     First Quarter............    $19.00           $16.75
     Second Quarter...........     17.75             8.13
     Third Quarter............     11.25             6.63
     Fourth Quarter...........      6.88             4.38

     1999
     First Quarter............      6.38             4.75
     Second Quarter...........      7.94             5.75
     Third Quarter............      7.56             6.38
     Fourth Quarter...........      7.06             4.94
</TABLE>

     The  Company has never paid a dividend,  cash or  otherwise,  on its Common
Stock.  Certain  provisions of the Company's Credit Agreement,  8-7/8% Indenture
and the 10-1/2% Indenture  restrict the Company's ability to declare or pay cash
dividends  on its  Common  Stock.  See  "Forward-Looking  Information  and  Risk
Factors--Restrictions  Upon Ability to Pay  Dividends".  Other than  payments of
Preferred Stock dividends, the Company currently intends to maintain a policy of
retaining cash for the continued expansion of its business.

ITEM 6 -- SELECTED FINANCIAL DATA

     The  following  table sets forth  selected  financial  data  regarding  the
Company as of and for each of the periods  indicated.  The following data should
be read in conjunction with  "Management's  Discussion and Analysis of Financial
Condition and Results of Operations" and the Company's financial  statements and
notes thereto, which follow.
<TABLE>
<CAPTION>

                                                                               Year Ended December 31,
                                                              -----------------------------------------------------
                                                            1999         1998         1997         1996          1995
                                                         ----------   ----------   ----------   ----------    -------
                                                                           (In thousands, except per share data)
<S>                                                     <C>           <C>          <C>          <C>           <C>
Statement of Operations Data:
Revenues:

  Oil and gas sales.......................................$139,242      $124,200     $129,994     $119,710     $68,767
  Commodity Price Risk Management Activities

    - Cash................................................     248         5,888       (1,551)       3,417       9,480
    - Non-cash............................................ (34,094)       18,912       (4,928)      (9,384)         --
  Interest................................................   1,134         1,730        3,245        2,653         353
                                                          ---------    ---------    ---------     --------    --------
Total revenues............................................ 106,530       150,730      126,760      116,396      78,600
                                                           -------       -------      -------      -------      ------
Costs and expenses:
  Oil and gas operating expenses..........................  39,168        40,847       12,758        7,847       5,824
  Depreciation, depletion and amortization                  54,182        56,102       46,684       40,904      27,590
  Impairment of oil and gas properties....................      --       229,000      150,000           --          --
  Impairment of equity securities.........................     450        24,216           --           --          --
  General and administrative..............................   4,940         5,216        3,913        3,059       2,597
  Interest Expense........................................  21,021        21,013        1,668           --          --
                                                          --------      --------      -------    ---------   ---------
Total costs and expenses.................................. 119,761       376,394      215,023       51,810      36,011
                                                           -------       -------      -------       ------      ------
Income (loss) before income taxes......................... (13,231)     (225,664)     (88,263)      64,586      42,589
Provision (benefit) for income taxes (1)                    (4,631)      (78,107)     (31,355)      21,953      13,852
                                                          ---------   ----------    ----------     -------    --------
Net income (loss) (1)..................................... $(8,600)    $(147,557)    $(56,908)     $42,633     $28,737
                                                           ========    =========     =========     =======     =======
Net income (loss) available to common stock               $(15,484)    $(152,963)    $(56,908)     $42,633     $28,737
                                                          =========    ==========    =========     =======     =======
Basic and diluted earnings (loss) per common share (1)      $(0.49)       $(4.85)      $(1.80)       $1.42       $1.15
                                                            =======       ======       =======       =====       =====
Weighted average common shares outstanding (2)              31,642        31,529       31,538       29,986      25,000
</TABLE>

                                       26

<PAGE>
<TABLE>
<CAPTION>
<S>                                                       <C>           <C>         <C>           <C>          <C>
Statement of Cash Flows Data:

Cash flow from operating activities.......................  78,044        86,345      101,523      108,059      62,037
Cash flow from investing activities....................... (74,542)     (138,526)    (363,136)    (143,826)    (65,133)
Cash flow from financing activities.......................  (3,832)       42,356      230,400       77,684      (2,299)

Capital expenditures......................................  73,183       126,506      564,459      142,712      71,387

Balance Sheet Data:
Working capital ..........................................$ (8,389)(3)   $14,823      $36,757      $48,667        $446
Total assets.............................................. 510,973       505,536      697,109      303,918     145,550
Long-term debt............................................ 306,744       294,990      352,090           --      22,000
Equity.................................................... 113,972       138,291      184,648      233,203     105,015
</TABLE>
------------------
(1)      1996 includes a one-time  non-cash deferred tax charge of $30.1 million
         recognized as a result of the Combination consummated on March 29, 1996
         in connection with the Company's Initial Public Offering.

(2)      Earnings per share have been  computed as if the  25,000,000  shares of
         Common Stock that were issued in connection  with  Combination had been
         outstanding for all years prior to 1996.

(3)      Excluding the commodity  price risk management  mark-to-market  balance
         sheet items,  working  capital would have been positive $6.6 million at
         December 31, 1999.

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

     The following  discussion is intended to assist in the understanding of the
Company's  historical  financial  position  and  results of  operations  for the
periods indicated.  It is based on the Company's historical financial statements
and related  notes thereto which follow and contain  detailed  information  that
should be referred to in conjunction with Management's Discussion and Analysis.

Overview

     Belco  Oil  &  Gas  Corp.  and  its  subsidiaries  (the  "Company")  is  an
independent  energy company engaged in the exploration for and the  acquisition,
exploitation,  development  and  production of natural gas and oil in the United
States  primarily in the Rocky Mountains,  the Permian Basin, the  Mid-Continent
region and the Austin  Chalk  Trend.  Since its  inception  in April  1992,  the
Company has grown its reserve base through a balanced program of exploration and
development  drilling and through  acquisitions.  The Company  concentrates  its
activities  primarily  in four core areas in which it has  accumulated  detailed
geologic  knowledge  and has  developed  significant  management  and  technical
expertise. Additionally, the Company structures its participation in natural gas
and oil  exploration and  development  activities to minimize  initial costs and
risks, while permitting substantial follow-on investment.

     On November 26, 1997, the Company  acquired all of the outstanding  capital
stock of Coda Energy,  Inc.  ("Coda"),  an  independent  energy company that was
principally  engaged in the  acquisition  and  exploitation of producing oil and
natural  gas  properties.  Coda's  properties  were  principally  located in the
Permian Basin of west Texas and the  Mid-Continent  region of Oklahoma and north
Texas. The acquisition  approximately  doubled the Company's reserve base to 604
Bcfe at December 31, 1997,  extended  the  Company's  reserve life index at that
time and established a more balanced reserve mix of

                                       27

<PAGE>

approximately  51%  oil and 49%  natural  gas.  The Company's reserve base was
641 Bcfe with a reserve life index of 10.6 years, based on 1999 production.

     The  Company's  operations  are currently  focused in the Rocky  Mountains,
primarily  in the Green River (which  includes the Moxa Arch Trend),  Wind River
and  Big  Horn  Basins  of  Wyoming;  the  Permian  Basin  in  west  Texas;  the
Mid-Continent  region in Oklahoma and north  Texas;  and the Austin Chalk Trend,
primarily in Texas. These areas accounted for approximately 99% of the Company's
proved reserves at December 31, 1999.

     The  Company's  revenue,  profitability  and  future  rate  of  growth  are
substantially  dependent  upon  prevailing  prices  for  natural  gas,  oil  and
condensate.  These  prices  are  dependent  upon  numerous  factors  beyond  the
Company's control, such as economic,  political and regulatory  developments and
competition from other sources of energy.  Energy markets have historically been
very  volatile,  and there can be no  assurance  that oil and natural gas prices
will not be  subject  to wide  fluctuations  in the  future.  A  substantial  or
extended  decline in oil and  natural gas prices  could have a material  adverse
effect on the Company's financial position,  results of operations and access to
capital,  as well as the  quantities  of natural gas and oil  reserves  that the
Company may economically  produce.  Natural gas produced is sold under contracts
that primarily  reflect spot market  conditions for their  particular  area. The
Company  markets  its oil with  other  working  interest  owners  on spot  price
contracts  and  typically  receives a small premium to the price posted for such
oil. Currently,  approximately 66% of the Company's production volumes relate to
the sale of natural gas (based on six Mcf of gas being considered  equivalent to
one barrel of oil).

     The Company utilizes  commodity swaps and options and other commodity price
risk  management  transactions  related to a portion of its oil and  natural gas
production to achieve a more  predictable  cash flow, and to reduce its exposure
to price  fluctuations.  The Company accounts for these  transactions as hedging
activities or uses  mark-to-market  accounting  for those  contracts that do not
qualify for hedge  accounting.  As of December 31, 1999, the Company has various
natural gas and oil price risk  management  contracts  in place with  respect to
substantial portions of its estimated production for calendar year 2000 and with
respect to lesser  portions of its estimated  production  for 2001 and 2002. The
Company  expects  from time to time to either  add or reduce the amount of price
risk  management  contracts  that it has in place in keeping with its price risk
management strategy.

     The following  table sets forth certain  operations data of the Company for
the periods presented:
<TABLE>
<CAPTION>

                                                                                       Year Ended December 31,
                                                                             -------------------------------------------
                                                                                 1999           1998            1997
                                                                             ------------   ------------    ------------
<S>                                                                           <C>             <C>            <C>
Oil and Gas Sales (Unhedged) (in thousands).................................   $139,242        $124,200       $129,994
Commodity Price Risk Management (in thousands)
  Cash......................................................................        248           5,888         (1,551)
  Non-Cash..................................................................    (34,094)         18,912         (4,928)
Weighted Average Sales Prices (Unhedged):
  Oil (per Bbl).............................................................     $17.49          $13.17         $19.28
  Gas (per Mcf).............................................................      $1.99           $1.86          $2.11
Net Production Data:
  Oil (MBbls)...............................................................      3,439           4,177          1,295
  Gas (MMcf)................................................................     39,738          37,207         49,710
  Gas equivalent (MMcfe)....................................................     60,370          62,272         57,479
  Gas equivalent (Mcfe-daily)...............................................    165,398         170,609        157,477
Operations Data per Mcfe:
  Oil and gas sales revenues (unhedged).....................................      $2.31           $1.99          $2.26
  Oil and gas operating expenses............................................      (0.65)          (0.66)         (0.22)
  General and administrative................................................      (0.08)          (0.08)         (0.07)
  Depreciation, depletion and amortization..................................      (0.90)          (0.90)         (0.81)
                                                                                  ------          ------         ------
  Pre-tax operating profit (1)..............................................      $0.68           $0.35          $1.16
                                                                                  =====           =====          =====
</TABLE>

                                       28

<PAGE>

----------
(1)  Excluding commodity price risk management activities charges, ceiling
     test and securities  impairment  provisions,  interest  income and
     interest expenses.

Results of Operations - 1999 Compared to 1998

   Revenues

     Oil and gas sales  revenues  for the year 1999,  excluding  the  effects of
commodity  price risk  management  activities,  increased 12% to $139.2  million
compared to $124.2 million  realized in 1998. The year over year increase is due
to higher commodity prices and higher natural gas production partially offset by
lower  crude oil  production.  In 1999,  weighted  average  oil prices  realized
(unhedged) totaled $17.49 per barrel, a 33% increase when compared to the $13.17
realized in 1998. The natural gas weighted  average prices  realized  (unhedged)
increased by 7% from $1.86 in 1998 to $1.99 in 1999.  Average  daily  production
volume in 1999 on an Mcfe basis declined by 3% to 165,398 Mcfe.

     Commodity price risk management  activities  resulted in a net pre-tax loss
of $33.8  million for 1999 which  included (1) cash realized  hedging  losses of
$3.2  million,  (2) cash  realized  gains  related to  non-hedging  transactions
totaling $3.4 million,  and (3) non-cash  unrealized  losses for  mark-to-market
accounting  of $34.1  million.  The impact of such  activities  on an Mcfe basis
amounted to net losses of $0.56 ($0.00 cash gain and $0.56 non-cash loss).  This
compares  to net gains of $0.40  ($0.09  cash and $0.31  non-cash)  per Mcfe for
1998.

   Costs and Expenses

     Production  and  Operating  Expenses.  Production  and  operating  expenses
declined  to $39.2  million  or 4% in 1999 when  compared  to the $40.8  million
incurred during 1998. The decrease is identified with cost reduction  efforts in
response to lower  commodity  prices realized in the first half of 1999 combined
with  the  implementation  of other  operating  efficiencies  on newly  operated
properties located in Wyoming.  On a unit basis,  operating costs were $0.65 per
Mcfe for 1999 compared to $0.66 per Mcfe for 1998.

     Depreciation, Depletion and Amortization. Recurring depreciation, depletion
and  amortization  ("DD&A")  costs  for the year  totalled  $54.2  million  when
compared to the $56.1 million recorded for the prior year. The DD&A rate for the
year was  unchanged  at $0.90 per Mcfe.  For the year  1998,  the  Company  also
recorded  $229  million  ($149  million  after-tax)  in  non-cash  ceiling  test
provisions as required by full-cost  accounting  rules.  The provisions were the
result of applying substantially lower commodity prices to estimated recoverable
reserves.

     General and Administrative  Expenses.  General and  administrative  ("G&A")
costs  declined  by 5% during  1999 to $4.9  million  when  compared to the $5.2
million  incurred in 1998.  The decrease is primarily  due to the cost  controls
implemented in response to lower  commodity  prices.  The rate per Mcfe for such
costs was  unchanged at $0.08 for both years.  Exploration  related G&A expenses
for 1999 in the  amount of $5.5  million  have been  capitalized  to oil and gas
property accounts. The decrease of $0.7 million when compared to 1998 comparable
capitalized amount of $6.2 million principally reflects reduced exploration
activities.

     Interest  expense  is  incurred  on  $150  million  of  the  8-7/8%  Senior
Subordinated  Notes due 2007 (the "8-7/8% Notes") issued in September 1997, $109
million of the 10-1/2% Senior  Subordinated Notes due 2006 (the "10-1/2% Notes")
and bank debt  incurred  under the  Company's  Revolving  Credit  Facility.  Net
interest  costs  incurred  for  the  year  1999  totalled  $25.9  million,  with
approximately $4.9 million of this total capitalized to property  accounts.  The
1999 net total  interest cost  declined  modestly when compared to 1998 when net
total interest costs were $26.1 million, with $5.1 million capitalized.

                                       29

<PAGE>

     As a result of the  substantial  decline  in the  market  value of Big Bear
Exploration Ltd. ("Big Bear") securities acquired in June 1998,  impairment
provisions  were  $450,000 and $9.7 million  recorded by the Company in 1999 and
1998, respectively. See "Liquidity and Capital Resources" for additional details
related to the Big Bear investment.

   Income (Loss) Before Income Taxes

     The  Company's  reported  loss before income tax benefits for the year 1999
was $13.2 million.  This compares to a loss of $225.7 million  reported in 1998.
The  substantially  lower loss  reported for 1999  reflects  improved  commodity
prices and the  absence  of  non-cash  ceiling  test and  securities  impairment
provisions of $229.0 million and $24.2 million, respectively, reported in 1998.

   Income Taxes

     Income tax  benefits  were  recorded for 1999 in the amount of $4.6 million
and $78.1 million for 1998 as a result of reported pre-tax losses.

Results of Operations - 1998 Compared to 1997

   Revenues

     Oil and gas sales  revenues  for the year 1998  (unhedged)  declined  5% to
$124.2  million when  compared to the $130.0  million  realized in 1997,  due to
substantially  lower commodity prices.  The year 1997 included only one month of
Coda activities. In 1998 weighted average oil prices realized (unhedged) totaled
$13.17 per barrel,  a 32% decline when compared to the $19.28  realized in 1997.
The natural gas weighted  average prices realized  (unhedged)  declined 12% from
$2.11 in 1997 to $1.86 in 1998.  Average daily  production  volume in 1998 on an
Mcfe basis increased 8% to 170,609 Mcfe.

     Commodity price risk management  activities  resulted in a net pre-tax gain
of $24.8  million for 1998 which  included  (1) realized  hedging  gains of $2.0
million,  (2) net realized  gains related to non-hedging  transactions  totaling
$3.9 million, and (3) non-cash unrealized gains for mark-to-market accounting of
$18.9  million.  The impact of such  activities on an Mcfe basis amounted to net
gains of $0.40 ($0.10 cash and $0.30  non-cash).  This compares to net losses of
$0.11 ($0.13 cash losses and a non-cash gain of $0.02) per Mcfe for 1997.

   Costs and Expenses

     Production  and  Operating  Expenses.  Production  and  operating  expenses
increased to $40.8 million in 1998 when  compared to the $12.8 million  incurred
during  1997.  The  increase  is  identified  with the growth in oil  production
through  secondary  recovery  techniques  following  the  Coda  acquisition  and
reflects the higher costs normally associated with such production when compared
to natural  gas. On a unit basis,  operating  costs were $0.66 per Mcfe for 1998
compared  to  $0.22  per Mcfe for 1997  which  included  only one  month of Coda
activities.

     Depreciation, Depletion and Amortization. Recurring depreciation, depletion
and  amortization  ("DD&A")  costs  for the year  totalled  $56.1  million  when
compared to the $46.7  million  recorded  for the prior year.  The DD&A rate per
Mcfe was $0.90 and $0.81 for 1998 and 1997, respectively. For the year 1998, the
Company also recorded $229 million ($149 million  after-tax) in non-cash ceiling
test provisions as required by full-cost  accounting  rules. The provisions were
the  result of  applying  substantially  lower  commodity  prices  to  estimated
recoverable reserves.

     General and Administrative  Expenses.  General and  administrative  ("G&A")
costs  increased by 33% during 1998 to $5.2  million  when  compared to the $3.9
million  incurred in 1997.  The  increase is  primarily  due to the  addition of
personnel associated with the Coda transaction. The rate per Mcfe for such costs
increased from $0.07 in 1997 to $0.08 in 1998.  Exploration related G&A expenses
for 1998 in the  amount of $6.2  million  have been  capitalized  to oil and gas
property

                                       30

<PAGE>

accounts.  The  increase of $0.4 million  over the 1997  comparable  capitalized
amount of $5.8  million  principally  reflects  additional  personnel  costs and
seismic activities related to a number of exploration projects.

     Interest  expense  is  incurred  on  $150  million  of  the  8-7/8%  Senior
Subordinated  Notes due 2007 (the "8-7/8% Notes") issued in September 1997, $109
million of the 10-1/2%  Notes assumed in the Coda  acquisition  in November 1997
and bank debt incurred under the Revolving Credit  Facility.  Net interest costs
incurred for the year 1998  totalled  $26.1  million,  with  approximately  $5.1
million of this total capitalized to property accounts.

     As a result of the  substantial  decline in the market value of  Chesapeake
Energy Corp. ("CHK") securities  acquired when Hugoton Energy Corp.  ("Hugoton")
was  merged  into  CHK,  the  Company  realized  a loss of  $14.4  million  upon
disposition  of these  securities  during  the first  nine  months  of 1998.  In
addition, a $9.7 million non-cash impairment provision was recorded to recognize
a decline in the value of Big Bear  securities  currently  owned by the Company.
See "Liquidity and Capital  Resources" for additional details related to the Big
Bear investment.

   Income (Loss) Before Income Taxes

     The  Company's  reported  loss before income tax benefits for the year 1998
was $225.7 million.  This compares to a loss of $88.3 million  reported in 1997.
The 1998 loss is primarily  the result of the non-cash  ceiling test  impairment
provisions totalling $229 million ($149 million after-tax) mandated by full-cost
accounting  rules. The 1997 loss was principally  identified with purchase price
allocations related to the Coda acquisition which resulted in a required ceiling
test provision. Income before income taxes, excluding the effect of the non-cash
impairments  and  purchase  accounting  provisions,  was $3.0  million and $61.7
million for 1998 and 1997, respectively.

   Income Taxes

     Income tax benefits  were  recorded for 1998 in the amount of $78.1 million
and $31.4 million for 1997 as a result of reported pre-tax losses.

Liquidity and Capital Resources

   General

     In September 1997, the Company entered into a five-year $150 million Credit
Agreement  dated  September  23,  1997 (the  "Credit  Facility")  with The Chase
Manhattan Bank,  N.A., as  administrative  agent (the "Agent") and other lending
institutions  (the  "Banks").  The Credit  Facility  provides  for an  aggregate
principal  amount of revolving  loans of up to the lesser of $150 million or the
Borrowing  Base (as  defined)  in effect  from time to time,  which  includes  a
sub-facility  from the  Agent for  letters  of  credit.  The  Borrowing  Base at
December  31, 1999 was set at $150 million  with $42.0  million  advanced to the
Company at that date.  The borrowing base is  redetermined  by the Agent and the
Banks  semi-annually  based upon their usual and  customary  oil and gas lending
criteria as such exist from time to time.  In addition,  the Company may request
two  additional  redeterminations  and the  Banks  may  request  one  additional
redetermination per year.

     Indebtedness  of the  Company  under the  Credit  Facility  is secured by a
pledge of the capital stock of each of the Company's material subsidiaries.

     Indebtedness  under the Credit  Facility  bears interest at a floating rate
based (at the  Company's  option)  upon (i) the ABR with respect to ABR Loans or
(ii) the Eurodollar Rate (as defined) for one, two, three or six months (or nine
or twelve months if available to the Banks) Eurodollar Loans (as defined),  plus
the  Applicable  Margin.  The ABR is the  greater  of (i)  the  Prime  Rate  (as
defined),  (ii) the Base CD Rate (as defined) plus 1% or (iii) the Federal Funds
Effective  Rate (as defined) plus 0.50%.  The  Applicable  Margin for Eurodollar
Loans  varies  from  0.50% to 0.875%  depending  on the  Borrowing  Base  usage.
Borrowing  Base  usage is  determined  by a ratio of (i)  outstanding  Loans (as
defined) and letters of credit to (ii) the

                                       31

<PAGE>

then effective  Borrowing  Base.  Interest on ABR Loans is payable  quarterly in
arrears  and  interest  on  Eurodollar  Loans is  payable on the last day of the
interest  period  therefore  and,  if longer than three  months,  at three month
intervals.

     The Company is required to pay to the Banks a  commitment  fee based on the
committed undrawn amount of the lesser of the aggregate  commitments or the then
effective  Borrowing  Base during a  quarterly  period  equal to a percent  that
varies from 0.20% to 0.30% depending on the Borrowing Base usage.

     In September  1997,  the Company  issued $150 million of the 8-7/8%  Notes.
Interest  on the  8-7/8%  Notes  accrues  at the rate of 8-7/8% per annum and is
payable  semi-annually  in  arrears on March 15 and  September  15 of each year,
commencing  on March 15, 1998.  The 8-7/8%  Notes  mature on September  15, 2007
unless previously redeemed. Except under limited circumstances, the 8-7/8% Notes
are not  redeemable  at the  Company's  option  prior  to  September  15,  2002.
Thereafter,  the 8-7/8% Notes will be subject to redemption at the option of the
Company,  in whole or in part, at specified  redemption prices, plus accrued and
unpaid interest, if any, thereon to the applicable redemption date. In addition,
upon a change of control  (as  defined in the  indenture  pursuant  to which the
8-7/8%  Notes were issued) the Company is required to offer to redeem the 8-7/8%
Notes  for  cash  at 101% of the  principal  amount,  plus  accrued  and  unpaid
interest, if any, thereon to the applicable date of repurchase.

     The 8-7/8% Notes are general  unsecured  obligations of the Company and are
subordinated  in right of payment to all  existing  and future  Senior  Debt (as
defined in the 8-7/8% Indenture) of the Company, which includes borrowings under
the Credit Facility  described  above. The 8-7/8% Notes rank pari passu in right
of payment with any existing or future senior  subordinated  debt of the Company
and rank senior in right of payment to all other  subordinated  indebtedness  of
the Company.

     In November  1997,  the Company  completed  the  acquisition  of Coda.  The
Company paid an aggregate of $324 million including  approximately  $192 million
in cash ($150  million  plus a $42  million  adjustment  for  proceeds  from the
disposition  of Taurus  Energy Corp.  ("Taurus"),  a  subsidiary  of Coda (which
occurred on the day prior to closing of the Coda  acquisition)),  assumption  of
$110  million of Coda  long-term  debt  outstanding  and three year  warrants to
purchase  1,666,667  shares of Common  Stock of the  Company at $27.50 per share
issued to the  holders of the  outstanding  common  stock,  preferred  stock and
options to purchase common stock of Coda.  Concurrently  with the closing of the
acquisition  of Coda,  the  Company  contributed  $23  million to Coda that Coda
utilized,  together with the funds from the disposition of Taurus,  to repay all
of the debt outstanding  under Coda's  revolving credit facility  (approximately
$65 million in principal amount), plus accrued interest thereon, and such credit
facility was  thereafter  terminated.  At closing,  the Company  funded the cash
portion of the  consideration  and the cash contribution to Coda through cash on
hand and borrowings of $84 million under its Credit Facility.

     On February 25, 1998,  the Company  merged Coda into Belco and  immediately
thereafter  transferred all of Coda's assets and liabilities,  except for Coda's
obligations under the 10-1/2% Notes to Belco Energy Corp., a Nevada  corporation
and a wholly  owned  subsidiary  of the Company.  As of December  31, 1999,  the
Company also had $109 million  principal  amount  outstanding  under the 10-1/2%
Notes. Interest on the 10-1/2% Notes accrue at the rate of 10-1/2% per annum and
is  payable  semi-annually  in  arrears  on April 1 and  October 1 of each year.
Except under limited circumstances,  the 10-1/2% Notes are not redeemable at the
Company's  option prior to April 1, 2001.  Thereafter  the 10-1/2% Notes will be
subject to redemption at specified prices, plus accrued and unpaid interest,  if
any, thereon to the applicable redemption date.

     The 10-1/2% Notes are general unsecured  obligations of the Company and are
subordinated  in right of payment to all  existing  and future  Senior  Debt (as
defined) of the Company, including any bank debt.

                                       32

<PAGE>

     The Company  entered into  interest  rate swap  agreements  converting  two
long-term debt fixed rate obligations to floating rate obligations as follows:
<TABLE>
<CAPTION>

Agreement      Transaction        Fixed       Floating        Floating Rate
 Amount           Date            Rate          Rate         Expiration Date
--------------------------------------------------------------------------------
<S>             <C>             <C>           <C>           <C>
$100 million     12/97            8.875%       8.280%       March 15, 2000 (a)
$110 million     12/97           10.500%       10.120%      April 1, 2000 (a)
$50 million      1/98             8.875%       8.195%       March 15, 2000 (a)
</TABLE>
-----------------------
(a) Floating rate is redetermined at each six month period following the expira-
    tion through September 15, 2007.

The agreements  obligate the Company to actually pay the indicated floating rate
rather than the original  fixed rate.  The  floating  rates are capped at 8-7/8%
through  September 15, 2001 and at 10% from March 15, 2002 through September 15,
2007 on the  8-7/8%  Notes and  capped at  10-1/2%  through  October 1, 1999 and
11.625%  from April 1, 2000  through  April 1, 2003 on the  10-1/2%  Notes.  The
agreements reduced the Company's 1999 and 1998 interest expense by approximately
$1.1 and $1.0 million, respectively.

     On March 10, 1998 the Company  completed the sale of 4.37 million shares of
its 6-1/2% Preferred Stock. The Preferred Stock has a liquidation  preference of
$25 per share and is  convertible at the option of the holder into shares of the
Company's Common Stock at an initial  conversion rate of 1.1292 shares of Common
Stock for each share of Preferred  Stock,  equivalent  to a conversion  price of
$22.14 per share of Common  Stock.  The Company  received net proceeds  from the
sale of the Preferred Stock of $105.1  million,  which was used to pay down bank
indebtedness. Through December 31, 1999, the Company purchased 384,700 shares of
its 6-1/2%  preferred  stock for a total cost of $5.9 million and 704,900 shares
of its common stock at a total cost of $4.3  million.  All such  purchases  were
made pursuant to the Company's Board approved share re-acquisition program.

     On  June  12,  1998,  the  Company,   through  its  wholly-owned   Canadian
subsidiary,  purchased  approximately $10.5 million of 5% Convertible  Preferred
Stock of Big  Bear  Exploration,  Ltd.,  a  Canadian  oil and gas company,
at approximately  $0.85 per share with each share convertible into one common
share of Big Bear. The Company was also issued approximately $120 million of
Special  Acquisition  Warrants at a price of approximately $0.72 per warrant.
In connection with the issuance of the Special Acquisition Warrants, the Company
deposited a $60 million  letter of credit and 3,436,000  shares of the Company's
common stock into an escrow account.  On November 10, 1998, the Company executed
a restructuring agreement whereby (i) the Company agreed to convert the Big Bear
5% Convertible  Preferred Stock into 21,428,571  shares of Big Bear Common Stock
at a conversion price of  approximately  $0.50 per share (reduced from $0.85 per
share),  (ii) the Special  Acquisition  Warrants were canceled,  (iii) the Belco
representatives  resigned  from  Big  Bear's  Board of  Directors,  (iv) the $60
million letter of credit was canceled,  and (v) the 3,436,000  shares of Company
common  stock  held in the escrow  account  were  returned  to the  Company  and
designated as unissued. The restructuring  agreement closed on January 22, 1999.
Subsequently,  Big Bear  effected  an 11 to 1 reverse  split of Big Bear  common
shares  and  Belco,  through  its  wholly-owned  Canadian  subsidiary,  received
1,948,052  common shares or  approximately  4.6%  ownership at that time, in Big
Bear. In January 2000, shareholders of Big Bear approved its acquisition by Avid
Oil & Gas, Ltd. ("Avid"), a Canadian based energy company providing for Big Bear
shareholders  to receive 1 share of Avid common stock for every 15 common shares
of Big  Bear.  As a result  of the  transaction  described  above,  the  Company
currently owns 129,870 shares of Avid with an approximate market value of
$190,000 (US) as of December 31, 1999.

     In September 1999, the Company acquired 25.1 Bcfe of long lived reserves on
producing  properties  in the Permian  Basin and South  Texas for  approximately
$16.2 million.

     In February 2000, the Company closed a $40.5 million acquisition of oil and
gas properties  expected to add approximately  2,400 BOE per day to the existing
production base.  The transaction was financed through additional borrowings
under the Company's Revolving Credit Facility.

                                       33

<PAGE>

   Cash Flow

     Operating  cash  flow,  a  measure  of  performance   for  exploration  and
production companies,  is generally derived by adjusting net income to eliminate
the effects of the non-cash  components  included in the net income  calculation
such as depreciation, depletion and amortization expense, provision for deferred
income taxes,  ceiling test  provisions,  and the non- cash effects of investing
and  commodity  price  risk  management  activities.  Operating  cash  flow  was
approximately $78.0 and $86.3 million for the years 1999 and 1998, respectively.
The Company had a working  capital  deficit of $8.4  million as of December  31,
1999,  a  decrease  of $23.2  million  from the $14.8  million  available  as of
December  31,  1998.  The  deficit  is  created  by the  recording  of  non-cash
mark-to-market  losses  related to  derivatives  activities  and recorded  under
current  obligations  in the balance  sheet as  required  by current  accounting
rules.  Excluding  the  mark-to-market  items,  working  capital would have been
positive $6.6 million at December 31, 1999,  before  recognizing the unused $108
million available under the Company's revolving credit facility.

   Capital Expenditures

     For 1999, the Company incurred capital  expenditures in the amount of $73.2
million, including approximately $17 million in property acquisitions.

     The Company  intends to fund its future capital  expenditures,  commitments
and working capital requirements through cash flows from operations,  borrowings
under the Credit  Facility  or other  potential  financings.  The  Company has a
preliminary 2000 capital  expenditure  budget for exploration and development of
approximately  $60 million exclusive of producing property acquisitions.  If
there are changes in oil and natural gas prices, however, that correspondingly
affect cash flows and the Borrowing Base under the Credit Facility, the  Company
has the  discretion  and  ability to adjust its capital  budget.  The  Company
believes  that it will have  sufficient  capital resources  and  liquidity to
fund its capital  expenditures  and meet all of its financial obligations as
they come due.

     On December 15, 1998,  the  Company's  Board of  Directors  authorized  the
purchase  from  time to time,  in the open  market  or in  privately  negotiated
transactions, shares of its Common Stock and 6-1/2% Convertible Preferred Stock,
in an aggregate amount not to exceed $10 million. The $10 million  authorization
was exhausted in December  1999,  and on December 27, 1999 the Board  authorized
additional such purchases in an amount not to exceed $10 million.

   Commodity Price Risk Management Transactions

     Certain  of the  Company's  commodity  price risk  management  arrangements
require  the  Company  to  deliver  cash  collateral  or  other   assurances  of
performance  to the  counterparties  in the  event  that the  Company's  payment
obligations  with respect to its commodity  price risk  management  transactions
exceed certain levels.

     With the primary objective of achieving more predictable  revenues and cash
flows and reducing the exposure to  fluctuations  in oil and natural gas prices,
the Company has entered into commodity  price risk  management  transactions  of
various kinds with respect to both oil and natural gas. While the use of certain
of these price risk management  arrangements limits the downside risk of adverse
price  movements,  it may  also  limit  future  revenues  from  favorable  price
movements.  The Company engages in transactions such as selling covered calls or
straddles  which  are  marked-to-market  at the end of the  relevant  accounting
period.  Since the futures market  historically has been highly volatile,  these
fluctuations may cause significant impact on the results of any given accounting
period.  The Company has entered into price risk  management  transactions  with
respect  to  a  substantial   portion  of  its  estimated  oil   production  and
approximately  60% of its natural gas  production  for the year 2000 with lesser
portions of its  production  for periods  thereafter.  The Company  continues to
evaluate whether to enter into additional price risk management transactions for
future years. In addition, the Company may determine from time to time to unwind
its then  existing  price risk  management  positions  as part of its price risk
management strategy.

                                       34

<PAGE>
     At December 31, 1999 the Company had recorded a net current liability of
$14.9 million.  This liability reflected the market value of the Company's
commodity price risk management contracts expiring during 2000.  Due to the sus-
tained higher oil prices subsequent to year-end, the Company expects to incur
additional cash settlement costs and non-cash mark-to-market losses related to
its commodity price risk management activities unless prices at March 31, 2000
decline below levels at December 31, 1999.

Other

   Environmental Matters

     The Company's  operations are subject to various  federal,  state and local
laws and regulations  relating to the protection of the environment,  which have
become increasingly  stringent.  The Company believes its current operations are
in material  compliance with current  environmental laws and regulations.  There
are no environmental claims pending or, to the Company's  knowledge,  threatened
against the Company. There can be no assurance, however, that current regulatory
requirements will not change,  currently unforeseen environmental incidents will
not occur or past  noncompliance  with environmental laws will not be discovered
on the Company's properties.

   Year 2000 Compliance

     The year 2000  issue  dealt with the  potential  inability  of  information
technology  and  non-information  technology  systems and  processes to properly
recognize  and process  date-sensitive  information  before,  during,  and after
December 31, 1999. Given that this date threshold has passed without  incidence,
all of the Company's operating systems,  computer software program applications,
computer  hardware  equipment  and  other  equipment  with  embedded  electronic
circuits,  including  applications  used  in the  Company's  financial  business
systems,  field operations,  and  administrative  functions  (collectively,  the
"systems") are deemed fully capable and currently operating effectively.

     The Company did not  separately  track the costs  associated  with the year
2000 compliance effort, as they were not material and further, no projects with
any significant impact to the Company's operations have been deferred due to the
year 2000 compliance effort. To date, the Company estimates that it has incurred
less than $100,000 in upgrading a limited amount of hardware and does not expect
to incur additional costs in connection with this issue.

   New Accounting Standards

     In June 1998, the Financial Accounting Standards Board issued Statement No.
133,  Accounting for Derivative  Instruments and Hedging Activities ("FAS 133").
FAS 133 is effective  for fiscal years  beginning  after June 15, 2000.  FAS 133
requires all  derivatives  to be recorded on the balance sheet at fair value and
established  "special  accounting"  for the following  three  different types of
hedges:  hedges of changes in the fair  value of  assets,  liabilities,  or firm
commitments  (referred to as fair value  hedges);  hedges of the  variable  cash
flows of  forecasted  transactions  (cash  flow  hedges);  and hedges of foreign
currency  exposures  of  net  investments  in  foreign  operations.  Though  the
accounting  treatment  and  criteria  for each of the  three  types of hedges is
unique,  they all result in  offsetting  changes in fair values or cash flows of
both the hedge and the hedged  item being  recognized  in  earnings  in the same
period  with no net  impact  on  reported  earnings.  Changes  in fair  value of
derivatives  that do not meet the criteria of one of these three  categories  of
hedges  are  included  in income  and  reported  as either  gain or loss for the
current  period.   Transition   adjustments  resulting  from  adoption  must  be
recognized in income and comprehensive  income, as appropriate,  as a cumulative
effect of an accounting change. Belco has not yet determined the effect of total
compliance, but it is not expected to materially impact the financial statements
of the Company.

ITEM 7A -- QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     The Company's market risk exposures  relate primarily to commodity  prices,
interest rates and marketable equity securities. The Company enters into various
transactions  involving commodity price risk management  activities  involving a
variety of derivatives  instruments to, in effect, hedge the impact of crude oil
and natural gas price  fluctuations.  In  addition,  the  Company  entered  into
interest rate swap agreements to reduce current  interest burdens related to its
fixed long-term debt. The derivatives  instruments are generally put in place to
limit the risk of adverse  oil and natural gas price  movements,  however,  such
instruments  can limit  future gains  resulting  from upward  favorable  oil and
natural gas price  movements.  Recognition of both realized and unrealized gains
or losses are  reported  currently  in the  Company's  financial  statements  as
required by existing generally  accepted  accounting  principles.  The cash flow
impact of all derivative  related  transactions  is reflected as cash flows from
operating activities.

                                       35

<PAGE>

     As of December 31, 1999, the Company had substantial  derivative  financial
instruments  outstanding and related to its price risk management  program.  See
"Footnote 7" to the consolidated  financial statements of the Company "Commodity
Price Risk Management  Activities and Fair Value of Financial  Instruments"  for
complete details on the Company's oil and gas related  transactions in effect as
of  December  31,  1999.  Transactions  subsequent  to  year-end  1999  were not
significant.

     The table below provides information related to the Company's interest rate
swaps on long-term debt obligations. For interest rate swaps, the table presents
notional amounts and approximate  weighted average interest rates by contractual
maturity dates.  Notional amounts are used to calculate the contractual payments
to be exchanged under the agreements in place.
<TABLE>
<CAPTION>

                                         Expected Maturity Date
                                  -------------------------------------          Fair Value
                                                                                   as of
                                   2000      2001      2002      Total       December 31, 1999
                                   ----      ----      ----      -----       -----------------
                                                     ($ in thousands)
<S>                              <C>      <C>       <C>         <C>           <C>
Liabilities:
  Bank credit facility...........      -         -   $42,000    $42,000           $42,000
  Variable rate..................  6.25%     6.25%     6.25%
  Belco 8.875% Notes.............      -         -         -   $150,000 (1)      $142,000
  Belco 10.500% Notes............      -         -         -   $109,000 (2)      $112,000
Interest Rate Swaps:
  Fixed to Variable.............$235,000  $235,000  $235,000                     $ (6,549)
  Average pay rate...............  8.92%     9.20%     9.20%
  Average receive rate...........  9.56%     9.56%     9.56%
</TABLE>
----------------
(1) Notes mature 2007
(2) Notes mature 2006

                                       36

<PAGE>

ITEM 8 -- CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     See the Consolidated  Financial Statements and supplementary data listed in
the accompanying Index to Financial Statements and Financial Statement Schedules
on page F-1 herein.  Information  required  by other  schedules  required  under
Regulation  S-X is  either  not  applicable  or is  included  in  the  financial
statements or notes thereto.

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

     None.

                                 PART III

ITEM 10 -- DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

     The information  regarding  Directors and Executive Officers required under
Item 10 will be contained in the definitive  Proxy  Statement of the Company for
its 2000  Annual  Meeting of  Shareholders  (the  "Proxy  Statement")  under the
headings "Election of Directors", "Executive Compensation and Other Information"
and "Section 16(a) Beneficial  Ownership Reporting Compliance" and is incorpora-
ted herein by reference.  The Proxy Statement will be filed pursuant to Regulat-
ion 14A with the  Securities  and Exchange  Commission not later than 120 days
after December 31, 1999.  For  information  regarding  Executive  Officers not
appearing in the Proxy Statement, see "Business--Executive Officers of the Reg-
istrant".

ITEM 11 -- EXECUTIVE COMPENSATION

     The  information  required  under  Item 11 will be  contained  in the Proxy
Statement under the heading  "Executive  Compensation and Other Information" and
is incorporated herein by reference.

ITEM 12-- SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     The  information  required  under  Item 12 will be  contained  in the Proxy
Statement  under the  heading  "Security  Ownership  of  Management  and Certain
Beneficial Owners" and is incorporated herein by reference.

ITEM 13 -- CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     The  information  required  under  Item 13 will be  contained  in the Proxy
Statement  under  the  headings   "Transactions   with  Management  and  Certain
Shareholders"  and  "Executive   Compensation  and  Other  Information"  and  is
incorporated herein by reference.

                                    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:

      1. Financial Statements: See Index to Consolidated Financial Statements
         and Schedules immediately following the signature page of this report.

      2. Financial Statement Schedules: See Index to Consolidated Financial
         Statements and Schedules immediately following the signature page of
         this report.

      3. Exhibits: The following documents are filed as exhibits to this report.

                                       37

<PAGE>
<TABLE>
<CAPTION>

Exhibit
No.                         Description of Exhibit
<S>  <C>
3.1  Articles of Incorporation of Company (Incorporated by reference from
     Exhibit 3.1 of the Registration Statement on Form S-1, Registration No.
     333-1034).
3.2  Amended and Restated Bylaws of Company dated February 5, 1996 (Incorporated
     by reference from Exhibit 3.2(ii) of the Form 10-Q dated March 31, 1996).
4.1  Specimen Common Stock certificate (Incorporated by reference from Exhibit
     4.1 of the Registration Statement on Form S-1, Registration No. 333-1034).
4.2  Indenture  dated as of  September  23,  1997 among the Company,  as issuer,
     and The Bank of New York, as trustee (Incorporated   by   reference   from
     Exhibit 4.1 of Registration  Statement  on  Form  S-4,  Registration  No.
     333-37125).
4.3  Supplemental  Indenture  dated as of February  25, 1998  between  Coda
     Energy, Inc., Diamond Energy Operating Company,  Electra Resources,  Inc.,
     Belco Operating Corp., Belco Energy L.P., Gin Lane Company, Fortune Corp.,
     BOG Wyoming LLC  and  Belco  Finance  Co.  (individually,   the  Subsidiary
     Guarantors),  a subsidiary  of the  Company,  and  The  Bank of New  York,
     a New  York  banking corporation  (as  Trustee)  amending the  Indenture
     filed as Exhibit 4.2 above. (Incorporated  by reference  from Exhibit 4.3
     of the Company's  Annual Report on Form 10-K for the  fiscal  year ended
     December  31,  1997).
4.4  Exchange  and Registration  Rights Agreement dated September 23, 1997 by
     and among the Company and  Chase  Securities Inc., Goldman,  Sachs  &  Co.
     and  Smith  Barney  Inc. (Incorporated  by reference from Exhibit 4.2 of
     Registration  Statement on Form S-4,  Registration No.  333-37125).
4.5  Indenture dated as of March 18, 1996 by and among Coda Energy, Inc., as
     issuer, and Taurus Energy Corp., Diamond Energy Operating Company and
     Electra Resources, Inc. (as guarantors), and Chase Bank of Texas,  N.A.,
     (formerly known as Texas Commerce Bank National Association,  as trustee
     (Incorporated  by reference  from Exhibit 4.1 of the Coda Energy,  Inc.
     Registration  Statement  on Form S-4  filed  April  9,  1996,  Registration
     No. 333-2375).
4.6  First Supplemental Indenture dated as of April 25, 1996 amending the Inden-
     ture filed as Exhibit 4.5 above (Incorporated by reference from Exhibit
     4.12 of the Coda Energy,  Inc.  Quarterly  Report on Form 10-Q for the
     quarterly period ended June 30, 1996, Commission File No. 0-10955).
4.7  Second Supplemental Indenture dated as of February 25, 1998 by and among
     the  Company  and  Chase  Bank of Texas,  N.A.  (formerly  known as Texas
     Commerce Bank National Association), as trustee, amending the Indenture
     filed as Exhibit 4.5 above.  (Incorporated by reference from Exhibit 4.7 of
     the Company's Annual Report on Form 10-K for the fiscal year ended December
     31, 1997).
4.8  Third Supplemental Indenture dated as of February 25, 1998 by and between
     the Company, the Belco subsidiaries who are making a Subsidiary Guarantee
     (the Guarantors) and Chase Bank of Texas, N.A., formerly known as Texas
     Commerce Bank National Association (the Trustee).  (Incorporated by refer-
     ence from Exhibit 4.8 of the Company's  Annual Report on Form 10-K for the
     fiscal year ended  December 31, 1997).
4.9  Certificate of Designations of 6-1/2% Convertible Preferred Stock
     dated  March 5, 1997  (Incorporated  by  reference  from  Exhibit 4.1 of
     current report on Form 8-K dated March 11,  1998).
10.1 1996 Non-Employee Directors' Stock Option Plan (Incorporated  by  reference
     from Exhibit 10.1 of the Registration Statement on Form S-1, Registration
     No. 333-1034).
10.2 1996 Stock Incentive Plan  (Incorporated by reference from Exhibit 10.2 of
     the Registration Statement on Form S-1,  Registration  No.  333-1034).
10.3 Exchange  and Subscription Agreement and Plan of Reorganization dated as of
     January 1, 1996 by and among the  Company,  its  Predecessors  and certain
     individuals  and trusts (Incorporated by reference to Exhibit 10.3 of the
     Registration Statement on Form S-1,  Registration No. 333-1034).
10.4 Form of Registration  Rights Agreement entered  into by parties to Exchange
     Agreement (Incorporated by reference to Exhibit 10.4 of the Registration
     Statement  on  Form  S-1,  Registration  No. 333-1034).
</TABLE>

                                       38

<PAGE>
<TABLE>
<CAPTION>
<S>   <C>
10.5  Supplemental Agreement dated as of January 1, 1996 by and between the
      Company,  Belco Oil & Gas Corp., a Delaware corporation,  Robert A. Belfer
      and certain  officers of the Company  (Incorporated  by  reference  to
      Exhibit 10.5 of the  Registration  Statement  on  Form  S-1,  Registration
      No. 333-1034).
10.6  Form of Indemnification Agreement by and between the Company and its offi-
      cers and directors (Incorporated by reference to Exhibit 10.6 of the
      Registration Statement on Form S-1, Registration No. 333-1034).
10.7  Amended and Restated Well Participation  Letter Agreement dated as of Dec-
      ember 31, 1992 between Chesapeake Operating, Inc. and Belco Oil & Gas
      Corp., as amended by (i) Letter  Agreement  dated April 14, 1983, (ii)
      Amendment dated December 31, 1993, and (iii) Third Amendment dated Decem-
      ber 30, 1994 (Incorporated by reference to Exhibit 10.7 of the Registra-
      tion Statement  on  Form  S-1,  Registration  No. 333-1034).
10.8  Sale Agreement  (Independence)  dated as of June  10,  1994 between Chesa-
      peake  Operating,  Inc. and Belco Oil & Gas Corp.  (Incorporated by
      reference  to  Exhibit  10.10  of  the  Registration   Statement  on  Form
      S-1, Registration No. 333-1034).
10.9  Sale and Area of Mutual Interest  Agreement (Greater Giddings) dated as of
      December 30, 1994 between  Chesapeake  Operating, Inc. and Belco Oil & Gas
      Corp.  (Incorporated  by reference to Exhibit  10.12 of the  Registration
      Statement on Form S-1,  Registration No.  333-1034).
10.10 Golden Trend Area of Mutual  Interest  Agreement  dated as of December 17,
      1992 between Chesapeake Operating, Inc. and Belco Oil & Gas Corp.  (Incor-
      porated by reference to  Exhibit  10.13  of  the  Registration   Statement
      on  Form  S-1, Registration No.  333-1034).
10.11 Form of Participation  Agreement for Belco Oil & Gas Corp. 1992 Moxa Arch
      Drilling  Program  (Incorporated  by reference to Exhibit  10.15 of the
      Registration  Statement  on Form  S-1,  Registration  No. 333-1034).
10.12 Form of Offset Participation Agreement to the Moxa Arch 1992 Offset Drill-
      ing  Program  (Incorporated  by reference  to Exhibit  10.16 of the Regis-
      tration Statement on Form S-1, Registration No. 333-1034).
10.13 Form of Participation Agreement for  Belco Oil & Gas  Corp. 1993 Moxa Arch
      Drilling Program (Incorporated  by  reference  to  Exhibit  10.17  of  the
      Registration Statement on Form S-1,  Registration  No.  333-1034).
10.14 Credit  Agreement dated  as of  September  23,  1997  by and  among  Belco
      Oil & Gas Corp.  (the "Borrower"), and The Chase Manhattan Bank, as admin-
      istrative agent, and certain financial institutions named therein as Lend-
      ers (the "Lenders")(Incorporated by reference to Exhibit 10.1 of Registra-
      tion  Statement on Form S-4,  Registration No.  333-37125).
10.15 First Amendment and Waiver, dated as of November 25, 1997 to (i) Credit
      Agreement dated as of September 23, 1997 among the Borrower, the Lenders
      and The Chase Manhattan Bank, as administrative  agent and (ii) the Pledge
      Agreement,  dated as of September 23, 1997 made by the Borrower and other
      Pledgers (as defined in the Credit  Agreement) in favor of the Administra-
      tive Agent for the ratable  benefit of  Lenders.  (Incorporated  by refer-
      ence  from Exhibit  99.4 to the  Company's  Current  Report  on Form  8-K
      filed  with  the Commission on November 26, 1997).
10.16 Second Amendment and Consent, dated as of February 25, 1998, to the Credit
      Agreement,  dated as of September  23, 1997,  among  the  Borrower,  the
      Lenders  and The  Chase  Manhattan  Bank,  as administrative  agent.
      (Incorporated  by reference  from  Exhibit  10.16 of the Company's  Annual
      Report on Form 10-K for the fiscal  year ended  December  31, 1997).
10.17 Third  Amendment,  dated as of May 29,  1998,  to the  Credit Agreement,
      dated as of September 23, 1997, as amended by the First Amendment and
      Waiver thereto,  dated as of November 25, 1997,  and the Second  Amendment
      and Consent thereto, dated as of February 25, 1998, by and among the Bor-
      rower,  the Lenders and The Chase Manhattan Bank, as administrative agent.
      (Incorporated by reference from Exhibit 10.17 of the Company's Annual
      Report on Form 10-K for the fiscal year ended  December  31,  1998).
10.18 Fourth  Amendment, dated as of December 21, 1998, to the Credit Agreement,
      dated as of September 23, 1997, as amended by the First  Amendment  and
      Waiver  thereto,  dated as of November  25, 1997,
</TABLE>

                                       39

<PAGE>
<TABLE>
<CAPTION>
<S>   <C>
      and the Second Amendment and Consent thereto,  dated as of February 25,
      1998, and the Third Amendment,  dated as of May 29, 1998, by and among the
      Borrower,  the Lenders and The Chase  Manhattan Bank, as  administrative
      agent.  (Incorporated  by reference from Exhibit 10.18 of the Company's
      Annual Report on Form 10-K for the fiscal year ended December 31, 1998).
10.19 Executive Employment  Agreement  with Grant W. Henderson  (Incorporated by
      reference from Exhibit 99.7 of the Coda Energy,  Inc.  Current Report on
      Form 8-K dated October 30, 1995,  Commission File No. 0-10955).
10.20 First Amendment to Belco Oil & Gas Corp. 1996 Nonemployee Directors' Stock
      Option Plan.  (Incorporated by reference from Exhibit 10.1 of the Com-
      pany's Quarterly Report on Form 10-Q for the quarter ended June 30, 1999,
      Commission File No. 1-14256).
*21.1 Subsidiaries of the  Registrant.
*23.1 Consent of Arthur Andersen  LLP.
*23.2 Consent of Miller  and Lents,  Ltd.
*27  Financial  Data Schedule.
</TABLE>
----------

* Filed herewith

     Certain of the exhibits to this filing  contain  schedules  which have been
omitted in accordance with applicable regulations.  The Registrant undertakes to
furnish  supplementally  a copy of any omitted  schedule to the  Securities  and
Exchange Commission upon request.

        (b)       Reports on Form 8-K.

                  None.

                                       40

<PAGE>

                                   SIGNATURES

     Pursuant to the  requirements  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.

                                             BELCO OIL & GAS CORP.



                                        By:  /s/ Laurence D. Belfer
                             ---------------------------------------------------
                                             Laurence D. Belfer
                             Vice-Chairman, Chief Operating Officer and Director

Date: March 30, 2000

     Pursuant to the  requirements of the Securities  Exchange Act of 1934, this
report  has  been  signed  below  by the  following  persons  on  behalf  of the
Registrant and in the capacities and on the dates indicated.
<TABLE>
<CAPTION>

      Signature                             Title                     Date
<S>                             <C>                             <C>
   /s/ Robert A. Belfer          Chief Executive Officer and      March 30, 2000
---------------------------       Chairman of the Board of
     Robert A. Belfer             Directors (Principal
                                  Executive Officer)

  /s/ Laurence D. Belfer         Vice-Chairman, Chief Operating   March 30, 2000
---------------------------       Officer and Director
    Laurence D. Belfer

  /s/ Dominick J. Golio          Senior Vice President--Finance,  March 30, 2000
---------------------------       Chief Financial Officer,
     Dominick J. Golio            Treasurer and Secretary
                                  (Principal Financial Officer
                                  and Principal Accounting
                                  Officer)

    /s/ Graham Allison           Director                         March 30, 2000
---------------------------
      Graham Allison

   /s/ Daniel C. Arnold          Director                         March 30, 2000
---------------------------
     Daniel C. Arnold

    /s/ Alan D. Berlin           Director                         March 30, 2000
---------------------------
      Alan D. Berlin

  /s/ Grant W. Henderson         President and Director           March 30, 2000
---------------------------
    Grant W. Henderson

      /s/ Jack Saltz             Director                         March 30, 2000
---------------------------
        Jack Saltz

/s/ Georgiana Sheldon-Sharp      Director                         March 30, 2000
---------------------------
  Georgiana Sheldon-Sharp
</TABLE>

                                       41

<PAGE>

                     BELCO OIL & GAS CORP. AND SUBSIDIARIES

                 INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND

                          FINANCIAL STATEMENT SCHEDULES
<TABLE>
<CAPTION>

                                                                            Page
<S>                                                                        <C>
CONSOLIDATED FINANCIAL STATEMENTS

  Report of Independent Public Accountants................................   F-2
  Consolidated Balance Sheets as of December 31, 1999 and 1998............   F-3
  Consolidated Statements of Operations for the Years Ended December 31,
    1999, 1998 and 1997...................................................   F-4
  Consolidated Statements of Stockholders' Equity for the Years Ended
    December 31, 1999,  1998 and 1997.....................................   F-5
  Consolidated Statements of Cash Flows for the Years Ended December 31,
    1999, 1998 and 1997...................................................   F-6
  Notes to Consolidated Financial Statements..............................   F-7
</TABLE>

CONSOLIDATED FINANCIAL STATEMENT SCHEDULES

None

     Financial Statement schedules pursuant to regulations of the Securities and
Exchange Commission have been omitted because they are either not required,  not
applicable  or the  information  required  to be  presented  is  included in the
Company's financial statements and related notes.

                                       F-1

<PAGE>

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To Belco Oil & Gas Corp.:

     We have audited the accompanying consolidated balance sheets of Belco Oil &
Gas Corp. (a Nevada  Corporation)  and  subsidiaries as of December 31, 1999 and
1998,  and the related  consolidated  statements  of  operations,  stockholders'
equity and cash flows for each of the three years in the period  ended  December
31, 1999.  These financial  statements are the  responsibility  of the Company's
management.  Our  responsibility  is to express  an  opinion on these  financial
statements based on our audits.

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

     In our opinion,  the consolidated  financial  statements  referred to above
present fairly, in all material respects,  the financial position of Belco Oil &
Gas Corp. and  subsidiaries as of 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.

ARTHUR ANDERSEN LLP

Dallas, Texas
February 23, 2000

                                       F-2

<PAGE>

                     BELCO OIL & GAS CORP. AND SUBSIDIARIES

                           CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>

                                ASSETS                          December 31,
                                                            -------------------
                                                              1999        1998
                                                            --------     ------
<S>                                                         <C>         <C>
CURRENT ASSETS:                                                (in thousands)
  Cash and cash equivalents (including restricted cash
    of $800,000 at December 31, 1999)....................    $2,105      $2,435
  Accounts receivable....................................    24,870      28,464
  Income taxes receivable................................     6,661          --
  Assets from commodity price risk management activities.     2,879      18,643
  Other current assets...................................     3,496       1,005
                                                              -----     -------
       Total Current Assets..............................    40,011      50,547

PROPERTY AND EQUIPMENT:
  Oil and gas properties at cost based on full-cost
    accounting--
     Proved oil and gas properties....................... 1,008,261     931,218
     Unproved oil and gas properties.....................    71,075      74,935
     Less-- Accumulated depreciation, depletion and
       amortization......................................  (619,446)   (566,613)
                                                          ---------    ---------
  Net oil and gas property...............................   459,890     439,540
                                                            -------     -------
  Building and other equipment...........................     9,107       8,633
     Less-- Accumulated depreciation.....................    (2,634)     (1,281)
                                                            -------     -------
  Net building and other equipment.......................     6,473       7,352

OTHER ASSETS.............................................     4,599       8,097
                                                              -----       -----
       Total Assets......................................  $510,973    $505,536
                                                           ========    ========

                             LIABILITIES AND EQUITY

CURRENT LIABILITIES:
  Accounts payable.......................................   $17,970     $18,372
  Liabilities from commodity price risk management
    activities...........................................    17,822       5,393
  Accrued interest.......................................     7,098       6,897
  Other accrued liabilities..............................     5,510       5,064
                                                            -------     -------
       Total Current Liabilities.........................    48,400      35,726

LONG-TERM DEBT...........................................   306,744     294,990

DEFERRED INCOME TAXES....................................    33,638      31,833

LIABILITIES FROM COMMODITY PRICE RISK MANAGEMENT ACTIVI-
  TIES...................................................     8,219       4,696

STOCKHOLDERS' EQUITY:
  Preferred stock, $0.01 par value; 10,000,000 shares
    authorized and 3,985,000 and 4,312,000 outstanding
    at December 31, 1999 and 1998, respectively..........        40          43
  Common Stock, $0.01 par value; 120,000,000 shares
    authorized; 31,797,300 and 31,609,900 issued and
    outstanding at December 31, 1999 and 1998,
    respectively.........................................       318         316
  Additional paid-in capital.............................   297,225     301,416
  Retained earnings deficit..............................  (177,111)   (161,627)
  Treasury Stock, 704,900 shares.........................    (4,317)         --
  Unearned compensation..................................    (1,430)     (1,082)
  Notes receivable for equity interest...................      (753)       (775)
                                                           ---------   ---------
       Total Stockholders' Equity........................   113,972     138,291
                                                            -------    ---------
       Total Liabilities and Stockholders' Equity........  $510,973    $505,536
                                                           ========    ========
</TABLE>


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

                                       F-3

<PAGE>

                     BELCO OIL & GAS CORP. AND SUBSIDIARIES

                      CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>

                                                For the Year Ended December 31,
                                               ---------------------------------
                                                  1999        1998       1997
                                               ---------    ---------   -------

                                                   (in thousands, except per
                                                         share amounts)
<S>                                           <C>          <C>        <C>
REVENUES:

  Oil and gas sales............................ $139,242    $124,200   $129,994
  Commodity price risk management activities
    - Cash.....................................      248       5,888     (1,551)
    - Non-cash.................................  (34,094)     18,912     (4,928)
  Interest.....................................    1,134       1,730      3,245
                                               ---------   ---------  ---------
     Total revenues............................  106,530     150,730    126,760
                                                 -------     -------    -------

COSTS AND EXPENSES:

  Oil and gas operating expenses...............   39,168      40,847     12,758
  Depreciation, depletion and amortization.....   54,182      56,102     46,684
  Impairment of oil and gas properties.........       --     229,000    150,000
  Impairment of equity securities..............      450      24,216         --
  General and administrative...................    4,940       5,216      3,913
  Interest expense.............................   21,021      21,013      1,668
                                                --------    --------  ---------
     Total costs and expenses..................  119,761     376,394    215,023
                                                 -------     -------    -------

INCOME (LOSS) BEFORE INCOME TAXES..............  (13,231)   (225,664)   (88,263)

PROVISION (BENEFIT) FOR INCOME TAXES...........   (4,631)    (78,107)   (31,355)
                                                  -------    --------   --------

NET INCOME (LOSS)..............................   (8,600)   (147,557)   (56,908)

PREFERRED STOCK DIVIDENDS......................   (6,884)     (5,406)        --
                                               ---------- ----------- ---------

NET INCOME (LOSS) AVAILABLE TO COMMON STOCK.... $(15,484)  $(152,963)  $(56,908)
                                                =========  ==========  =========

EARNINGS (LOSS) PER SHARE OF COMMON STOCK,
  BASIC AND FULLY DILUTED......................   $(0.49)     $(4.85)    $(1.80)
                                                  =======     =======    =======

AVERAGE NUMBER OF COMMON SHARES USED IN
  COMPUTATION, BASIC AND FULLY DILUTED.........   31,642      31,529     31,538
                                                  ======      ======     ======
</TABLE>


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


                                       F-4

<PAGE>

                     BELCO OIL & GAS CORP. AND SUBSIDIARIES
                 CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

                                 (in thousands)

<TABLE>
<CAPTION>



                              Preferred Stock    Common Stock    Additional
                              ---------------   ---------------    Paid-In
                              Shares  Amount    Shares   Amount    Capital
<S>                          <C>      <C>       <C>      <C>      <C>
BALANCE, December 31, 1996        --  $   --    31,577   $  316   $186,703
                              ------  ------    ------   ------   --------

Restricted stock issued.......    --      --         5       --        123
Exercise of stock options         --      --         2       --         38
Issuance of warrants..........    --      --        --       --     10,000
Unrealized loss on marketable
 equity securities............    --      --        --       --         --
Net income (loss).............    --  $   --        --       --         --
                              ------  ------    ------    ------  --------

BALANCE, December 31, 1997        --      --    31,584    $ 316   $196,864
                              ------  ======    ======    =====   ========
Comprehensive Income..........


Issuance of Preferred Stock... 4,370  $   44        --       --   $105,025
Repurchase of Preferred Stock.   (58)     (1)       --       --       (806)
Restricted Stock Issued (Net).    --      --        25       --        333
Unrealized loss on marketable
  equity securities...........    --      --        --       --         --
Net income (loss).............    --      --        --       --         --
Preferred Dividend paid.......    --      --        --       --         --
                               -----  ------    ------    -----   --------

BALANCE, December 31, 1998     4,312  $   43    31,609    $ 316   $301,416
                              ======  =======   ======    =====   ========
Comprehensive Income..........


Repurchase of Preferred Stock   (327)    $(3)       --       --    $(5,049)
Restricted Stock Issued.......    --      --       200        2      1,018
Restricted Stock Forfeited....    --      --       (12)      --       (160)
Restricted Stock Amortized....    --      --        --       --         --
Net Income (Loss).............    --      --        --       --         --
Preferred Dividend Paid.......    --      --        --       --         --
Treasury Stock Acquisitions...    --      --        --       --         --
Payment Received..............    --      --        --       --         --
                               -----   -----     -----    -----    -------

BALANCE, December 31, 1999     3,985   $  40    31,797    $ 318   $297,225
                               =====   =====    ======    =====   ========
Comprehensive Income..........

</TABLE>

<TABLE>
<CAPTION>




                                                        Notes
                                         Retained     Receivable
                              Unearned   Earnings     for Equity
                            Compensation (Deficit)     Interest
<S>                         <C>          <C>         <C>
BALANCE, December 31, 1996
Restricted stock issued.....  $(1,285)   $48,244     $  (775)
                              -------    --------    --------
Exercise of stock options...      192         --           --
Issuance of warrants........       --         --           --
Unrealized loss on marketa-
 ble equity securities......       --         --           --
Net income (loss)...........       --         --           --
                                   --    (56,908)          --
                              -------    --------     -------
BALANCE, December 31, 1997    $(1,093)   $(8,664)     $  (775)
                              =======    =======      ========
Comprehensive Income........

Issuance of Preferred Stock.       --         --           --
Repurchase of Preferred Stock      --         --           --
Restricted Stock Issued (Net)      11         --           --
Unrealized loss on marketable
  equity securities.........       --         --           --
Net income (loss)...........       --   (147,557)          --
Preferred Dividend paid.....       --     (5,406)          --
                              -------   ---------     -------
BALANCE, December 31, 1998    $(1,082) $(161,627)    $  (775)
                              ======== ==========    ========
Comprehensive Income........

Repurchase of Preferred Stock     --         --           --
Restricted Stock Issued.....  (1,020)        --           --
Restricted Stock Forfeited..     160         --           --
Restricted Stock Amortized..     512         --           --
Net Income (Loss)...........      --     (8,600)          --
Preferred Dividend Paid.....      --     (6,884)          --
Treasury Stock Acquisitions.      --         --           --
Payment Received............      --         --           22
                              ------     ------     --------
BALANCE, December 31, 1999   $(1,430) $(177,111)    $   (753)
                             ======== ==========    =========
Comprehensive Income........

</TABLE>


<TABLE>
<CAPTION>

                                               Unrealized
                                 Treasury       Loss On
                               Common Stock    Marketable            Compre-
                             ----------------    Equity              hensive
                             Shares   Amount   Securities   Total    Income
                             -------------------------------------------------
<S>                          <C>      <C>       <C>       <C>        <C>
BALANCE, December 31, 1996       --   $   --    $   --    $233,203
                             ------   -------   --------  --------
Restricted stock issued.....     --       --        --         315        --
Exercise of stock options...     --       --        --          38        --
Issuance of warrants........     --       --        --      10,000        --
Unrealized loss on marketa-
 ble equity securities......     --       --    (2,000)     (2,000)   (1,320)
Net income (loss)...........     --       --        --     (56,908)  (56,908)
                             ------   ------   --------   ---------  --------

BALANCE, December 31, 1997       --   $   --   $(2,000)   $184,648
                             ======   ======   ========   ========
Comprehensive Income........                                        $(58,228)
                                                                    =========
Issuance of Preferred Stock.     --       --        --    $105,069        --
Repurchase of Preferred Stock    --       --        --        (807)       --
Restricted Stock Issued (Net)    --       --        --         344        --
Unrealized loss on marketable
  equity securities..........    --       --     2,000       2,000     1,320 (a)
Net income (loss)............    --       --        --    (147,557) (147,557)
Preferred Dividend paid......    --       --   $    --      (5,406)       --
                             ------    -----   -------    --------- --------

BALANCE, December 31, 1998       --    $  --        --    $138,291
                             ======    =====   =======    ========
Comprehensive Income.........                                      $(146,237)
                                                                   ==========

Repurchase of Preferred Stock    --       --        --    $(5,052)        --
Restricted Stock Issued......    --       --        --         --
Restricted Stock Forfeited...    --       --        --         --         --
Restricted Stock Amortized...    --       --        --        512         --
Net Income (Loss)............    --       --        --     (8,600)    (8,600)
Preferred Dividend Paid......    --       --        --     (6,884)        --
Treasury Stock Acquisitions..  (705)  (4,317)       --     (4,317)        --
Payment Received.............    --       --        --         22         --
                             -------  -------  -------    -------- ---------

BALANCE, December 31, 1999     (705)  $(4,317) $    --    $113,972
                               =====  ======== =======    ========
Comprehensive Income.........                                      $ (8,600)
                                                                   =========
</TABLE>
--------------
(a)  Represents a  reclassification  adjustment  for $2.0  million  gross ($1.32
million net of tax) unrealized loss recognized in comprehensive  income in 1997,
but recognized in net income during 1998.

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

                                       F-5

<PAGE>

                     BELCO OIL & GAS CORP. AND SUBSIDIARIES

                      CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
                                                                  For the Year Ended December 31,
                                                             ----------------------------------------
                                                               1999             1998             1997
                                                            ----------       ----------        --------
                                                                           (in thousands)

<S>                                                        <C>              <C>                <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
  Net income (loss).........................................  $(8,600)       $(147,557)        $(56,908)
  Adjustments to reconcile net income (loss) to net
    operating cash inflows--
     Depreciation, depletion and amortization...............   54,182           56,102           46,684
     Impairment of oil and gas properties...................       --          229,000          150,000
     Impairment of equity securities........................      450            9,773               --
     Deferred tax benefit...................................   (4,856)         (78,107)         (31,536)
     Commodity price risk management activities.............    5,901            2,942           (1,248)
     Other..................................................      203              (19)             353
     Changes in operating assets and liabilities--
       Commodity price risk management......................   28,193          (21,869)              --
       Accounts receivable..................................    3,617           15,208            1,850
       Marketable equity securities.........................       --           30,884               --
       Other current assets.................................   (1,292)             247              (65)
       Accounts payable and accrued liabilities.............      246          (10,259)          (7,607)
                                                               ------          -------          -------
          Net operating cash inflows........................   78,044           86,345          101,523
                                                               ------           ------          -------
CASH FLOWS FROM INVESTING ACTIVITIES:
  Exploration and development expenditures..................  (73,932)        (133,078)        (140,975)
  Proceeds from sale of oil and gas properties..............      215            6,292           13,949
  Changes in accounts payable and accrued liabilities for
     oil and gas expenditures...............................       --               --           11,726
  Change in advances to oil and gas operators...............       --               --             (277)
  Purchase of Coda Energy, Inc..............................       --               --         (214,896)
  Purchase of marketable equity securities..................       --          (10,467)         (30,884)
  Changes in other assets...................................     (351)             (22)          (1,779)
  Other property additions..................................     (474)          (1,251)              --
                                                              --------        ---------        ---------
          Net investing cash outflows.......................  (74,542)        (138,526)        (363,136)
                                                              --------        --------         ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
  Long-term borrowings......................................   53,500           68,000           85,000
  Net proceeds from issuance of subordinated notes..........       --               --          145,400
  Long-term debt repayments.................................  (41,100)        (124,500)              --
  Proceeds from issuance of Preferred Stock.................       --          105,069               --
  Dividends on Preferred Stock..............................   (6,884)          (5,406)              --
  Repurchase of Common Stock................................   (4,317)              --               --
  Repurchase of Preferred Stock.............................   (5,052)            (807)              --
  Other.....................................................       21               --               --
                                                              --------        ---------        --------
          Net financing cash inflows (outflows).............   (3,832)          42,356          230,400
                                                               -------          ------          -------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS............     (330)          (9,825)         (31,213)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD............    2,435           12,260           43,473
                                                              -------           ------         --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD..................   $2,105           $2,435          $12,260
                                                               ======           ======          =======
</TABLE>

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

                                       F-6


<PAGE>



                     BELCO OIL & GAS CORP. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 -- ORGANIZATION AND NATURE OF OPERATIONS

Organization

     Belco Oil & Gas Corp. was organized as a Nevada corporation in January 1996
in connection with the combination of assets (the  "Combination")  consisting of
ownership  interests  (the  "Combined  Assets") in certain  entities  and direct
interests in oil and gas properties and certain hedge  transactions owned by the
predecessors and entities  related  thereto.  On March 29, 1996, Belco Oil & Gas
Corp.  completed its initial public offering (the "Offering")  issuing 6,500,000
shares of Common Stock at $19 per share. Belco Oil & Gas Corp. and the owners of
the Combined Assets entered into an Exchange and Subscription Agreement and Plan
of  Reorganization  dated as of January 1, 1996 (the "Exchange  Agreement") that
provided for the issuance by the Company of an aggregate of 25,000,000 shares of
Common  Stock to such owners in exchange  for the  Combined  Assets on March 29,
1996, the date the Offering  closed.  The owners of the Combined Assets received
shares  of  Common  Stock  proportionate  to the  value of the  Combined  Assets
underlying  their  ownership  interests  in  the  predecessors  and  the  direct
interests.

     The  Combination  was accounted for as a  reorganization  of entities under
common control because of the common control of the  stockholders of Belco Oil &
Gas Corp. and by virtue of their direct  ownership of the entities and interests
exchanged.  Accordingly,  the net assets acquired in the  Combination  have been
recorded at the historical cost basis of the affiliated predecessor owners.

     Belco Oil & Gas Corp. and its subsidiaries and prior to March 29, 1996, the
combined  predecessor  entities,  are  referred  to  herein  as  "Belco"  or the
"Company".

Nature of Current Operations

     The Company is an independent  energy company  engaged in the  exploration,
development and production of natural gas and oil. The Company  operates in this
single  industry  segment,  and all  operations  are presently  conducted in the
United States. The Company's operations are focused in four core areas including
the Permian Basin (west Texas),  the Mid- Continent  (Oklahoma,  north Texas and
Kansas),  the  Rocky  Mountains  (Wyoming),  and the  Austin  Chalk  (Texas  and
Louisiana).

     Substantially   all   of   the   Company's   production   is   sold   under
market-sensitive contracts. The Company's revenue, profitability and future rate
of growth are  substantially  dependent  upon the price of, and demand for, oil,
natural gas and natural gas liquids.  Prices for oil and natural gas are subject
to wide fluctuation in response to relatively minor changes in the supply of and
demand for oil and natural gas,  market  uncertainty and a variety of additional
factors that are beyond the control of the Company.  These  factors  include the
level of consumer  product  demand,  weather  conditions,  domestic  and foreign
governmental  regulations,  the price and  availability  of  alternative  fuels,
political  conditions in the Middle East,  the foreign supply of oil and natural
gas,  the price of foreign  imports and overall  economic  conditions.  With the
objective  of reducing  price risk,  the  Company has entered  into  hedging and
related price risk management  transactions with respect to a significant amount
of its expected future production (See Note 7).

NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

     The consolidated  financial statements for the periods presented include
the  accounts of the  Company  and its  wholly-owned  subsidiaries including one
month of Coda operations for 1997. The Company's  interests in the Moxa

                                       F-7


<PAGE>



Arch  investment  programs (the 1992 Moxa Arch Drilling  Program,  the 1993 Moxa
Arch Drilling  Program,  the Moxa Arch 1992 Offset Drilling Program and the Moxa
Arch 1993 Offset Drilling Program) (collectively,  the "Programs") are accounted
for using the proportionate  consolidation  method of accounting for investments
in oil and gas property interests, whereby the Company's share of each program's
assets,  liabilities,  revenues  and  expenses is  included  in the  appropriate
accounts of the consolidated  financial  statements.  All material  intercompany
balances and transactions have been eliminated.

Cash Equivalents

     The  Company  considers  all highly  liquid  investments  with an  original
maturity of three months or less to be cash equivalents.  At December 31, 1999
cash includes $800,000 of funds on deposit with a counterparty and related to
Commodity Price Risk Management Activities.  The depository amount varies from
day to day and dependent on the movement of commodity prices.  Subsequent to
calendar year-end 1999 the Company has deposited substantial amounts due to the
run-up in the price of oil during the first quarter of 2000 through mid-March.

Property and Equipment

     The Company  follows the  full-cost  method of  accounting  for oil and gas
properties. Accordingly, all costs associated with acquisition,  exploration and
development of oil and gas reserves,  including directly related internal costs,
are capitalized.  The Company capitalized $5,492,000,  $6,054,000 and $5,769,000
of related internal costs during 1999, 1998 and 1997, respectively.

     Oil and gas properties are amortized on the unit-of-production method using
estimates of proved reserve  quantities.  Investments in unproved properties are
not  amortized  until  proved  reserves  associated  with  the  projects  can be
determined or until impairment  occurs.  The amortizable base includes estimated
future development costs and, where significant, dismantlement,  restoration and
abandonment costs, net of estimated salvage values.

     In addition,  the capitalization costs of proved oil and gas properties are
subject to a "ceiling  test," which limits such costs to the  estimated  present
value net of related tax effects,  discounted at a 10 percent  interest rate, of
future net cash flows  from  proved  reserves,  based on  current  economic  and
operating  conditions (PV10). If capitalized costs exceed this limit, the excess
is charged to depreciation, depletion and amortization.

     The PV10 value of the Company's  year-end 1999  estimated  proved  reserves
were well in excess of the ceiling test limit.  For the full year ended December
31, 1998 the Company  recorded $229 million ($149 million after tax) in non-cash
ceiling  test  provisions  as  required  by  full  cost  accounting  rules.  The
provisions were the result of applying  substantially  lower commodity prices to
estimated recoverable reserves.

     Sales  and  other  dispositions  of  proved  and  unproved  properties  are
accounted  for as  adjustments  of  capitalized  costs  with  no  gain  or  loss
recognized, unless significant reserves are involved. Abandonments of properties
are accounted for as adjustments of capitalized costs with no loss recognized.

     Buildings,  equipment and gas processing  facilities  are  depreciated on a
straight-line  basis over the estimated useful lives of the assets,  which range
from three to 20 years.

Management Fees

     The Company  manages three  investment  programs,  which were formed during
1992-1994 to acquire and develop interests in certain drilling prospects located
in the Moxa Arch trend in Wyoming.  The Company  offered,  to certain  qualified
investors,  the opportunity to invest in the prospects through  participation in
the Programs. In return for its management activities on behalf of the Programs,
the Company earns an annual management fee of one percent of committed  capital.
After  elimination  of  management  fees  received  from  affiliated   entities,
including  predecessor  owners,  the Company  earned  management  fees  totaling
$305,000 for both 1999 and 1998 and $297,000 during 1997.

                                       F-8


<PAGE>



Capitalization of Interest

     Interest  costs  related to the  acquisition  and  development  of unproved
properties are capitalized to oil and gas properties. Interest costs capitalized
for the years  ended  December  31,  1999,  1998 and 1997,  totaled  $4,881,000,
$5,123,000 and $3,742,000, respectively.

Accounting for Commodity Price Risk Management Activities

     The Company  periodically  engages in price risk  management  activities in
order  to  manage  its  exposure  to oil and  gas  price  volatility.  Commodity
derivatives   contracts,   which  are  usually   placed  with  major   financial
institutions  that the Company  believes are minimal credit risks,  may take the
form of futures  contracts,  swaps or options.  The oil and gas reference prices
upon which these  commodity  derivatives  contracts  are based  reflect  various
market  indices that have a high degree of  historical  correlation  with actual
prices received by the Company. Gains and losses related to qualifying hedges of
the Company's oil and gas production are deferred and are recognized as revenues
as the  associated  production  occurs.  In the  event of a loss of  correlation
between  changes in oil and gas reference  prices under a commodity  derivatives
contract and actual oil and gas prices,  a gain or loss is recognized  currently
to the extent the commodity derivatives have not offset changes in actual oil
and gas prices.

     Estimates of future cash flows  applicable to oil and gas commodity  hedges
are reflected in future cash flows from proved reserves in the  supplemental oil
and gas  disclosures,  with such  estimates  based on prices in effect as of the
date of the reserve report (See Note 14).

     Transactions  that do not qualify for hedge  accounting  are  accounted for
using the mark-to-market  method.  Under such method, the financial  instruments
are reflected at market value at the end of the period with resulting unrealized
gains  and  losses  recorded  as  assets  and  liabilities  in the  consolidated
financial  statements.  Changes in the  market  value of  outstanding  financial
instruments are recognized as a gain or loss in the period of change.

     In June 1998, the Financial Accounting Standards Board issued Statement No.
133,  "Accounting  for  Derivative  Instruments  and Hedging  Activities " ("FAS
133").  FAS 133 is effective for fiscal years beginning after June 15, 2000. FAS
133 requires all  derivatives  to be recorded on the balance sheet at fair value
and established  "special accounting" for the following three different types of
hedges:  hedges of changes in the fair  value of  assets,  liabilities,  or firm
commitments  (referred to as fair value  hedges);  hedges of the  variable  cash
flows of  forecasted  transactions  (cash  flow  hedges);  and hedges of foreign
currency  exposures  of  net  investments  in  foreign  operations.  Though  the
accounting  treatment  and  criteria  for each of the  three  types of hedges is
unique,  they all result in  offsetting  changes in fair values or cash flows of
both the hedge and the hedged  item being  recognized  in  earnings  in the same
period  with no net  impact  on  reported  earnings.  Changes  in fair  value of
derivatives  that do not meet the criteria of one of these three  categories  of
hedges  are  included  in income  and  reported  as either  gain or loss for the
current  period.   Transition   adjustments  resulting  from  adoption  must  be
recognized in income and comprehensive  income, as appropriate,  as a cumulative
effect of an accounting change. Belco has not yet determined the effect of total
compliance, but it is not expected to materially impact the financial statements
of the Company.

Gas Balancing/Revenue Recognition

     The Company  uses the sales  method to account for natural gas  imbalances.
Under the sales method, the Company  recognizes  revenues based on the amount of
gas sold to  purchasers,  which may differ from the amounts to which the Company
is  entitled  based on its  interests  in the  properties.  However,  revenue is
deferred and a liability is recorded for those  properties where production sold
by the Company exceeds its entitled share of remaining natural gas reserves. Gas
balancing obligations as of December 31, 1999 and 1998 were not significant.

                                       F-9


<PAGE>



Income Taxes

     The Company  accounts for income taxes under the provisions of SFAS No. 109
--  "Accounting  for Income  Taxes,"  which  provides for an asset and liability
approach for  accounting  for income taxes.  Under this  approach,  deferred tax
assets  and  liabilities  are  recognized   based  on  anticipated   future  tax
consequences,  using  currently  enacted tax laws,  attributable  to differences
between financial statement carrying amounts of assets and liabilities and their
respective tax bases.  Deferred tax assets are reduced by a valuation  allowance
when,  based  upon  management's  estimate,  it is more  likely  than not that a
portion of the deferred tax assets will not be realized in a future period.

Net Income (Loss) Per Common Share

     Basic and diluted net income  (loss) per common share have been computed in
accordance with SFAS No. 128, "Earnings Per Share," which the Company adopted at
year end 1997. Net income per share amounts for prior periods have been restated
to conform with the provisions of the new standard.  Basic net income per common
share is computed by dividing income available to common shareholders, after the
payment of dividends to preferred  stockholders,  by the weighted average number
of common  shares  outstanding  for the  periods.  Diluted net income per common
share  reflects the  potential  dilution that could occur if securities or other
contracts to issue common stock were  exercised or converted  into common stock.
Calculations  of basic and  diluted  net  income  (loss)  per  common  share are
illustrated in Note 12.

Use of Estimates

     The  preparation  of financial  statements  in  conformity  with  generally
accepted  accounting  principles  requires  management  to  make  estimates  and
assumptions  that  affect the  reported  amounts of assets and  liabilities  and
disclosure of  contingent  assets and  liabilities  at the date of the financial
statements  and the  reported  amounts  of  revenues  and  expenses  during  the
reporting period. Actual results could differ from those estimates.  Significant
estimates with regard to these financial  statements  include the estimated fair
value of oil and gas commodity price risk management  contracts and the estimate
of proved oil and gas reserve volumes and the related discounted future net cash
flows therefrom (See Notes 7 and 14).

NOTE 3 -- ACQUISITION OF CODA ENERGY, INC.

     On November  26, 1997,  Belco  completed  the Merger (the  "Merger") of its
subsidiary Belco  Acquisition  Sub, Inc.  ("Belco Sub"), a Delaware  corporation
with and into Coda Energy, Inc., a Delaware corporation. The Merger was effected
pursuant to the terms of an  Agreement  and Plan of Merger,  dated as of October
31, 1997, by and among Belco, Belco Sub and Coda. In connection with the Merger,
Belco paid $324  million,  including  $214 million in cash,  assumption  of $110
million in debt (face value), and the issuance of warrants to purchase 1,666,667
shares of common stock,  par value $0.01 per share,  of Belco (the "Belco Common
Stock") to the holders of the  outstanding  common  stock,  preferred  stock and
options to purchase  common stock of Coda.  The warrants are  exercisable  for a
period of three years  commencing  on November 26, 1998 at an exercise  price of
$27.50 per share.  The warrant  exercise price and the number of shares of Belco
Common Stock that may be issued pursuant to the exercise of the warrants will be
adjusted to prevent  dilution in the event of stock splits,  stock dividends and
certain other events affecting the capital structure of Belco.

                                      F-10


<PAGE>



     The acquisition of Coda has been accounted for using the purchase method of
accounting  and has been  included in the  financial  statements  of the Company
since the date of  acquisition.  The  purchase  price has been  allocated to the
assets  purchased and the liabilities  assumed based upon the fair values on the
date of acquisition as follows (in thousands):

<TABLE>
    <S>                                                            <C>
    Value of proved and unproved oil and gas properties acquired   $437,431
    Value of building and other assets acquired...................    6,470
    Working capital acquired, net.................................    5,534
    Assumed deferred tax liability................................ (101,616)
    Long-term debt assumed........................................ (117,090)
    Transaction costs and other...................................   (5,833)
    Issuance of warrants..........................................  (10,000)
                                                                   ---------
      Net cash paid, including capital contributed................ $214,896
                                                                   ========
</TABLE>

NOTE 4 -- LONG TERM DEBT

     Long term debt  consists of the following at December 31, 1999 and 1998 (in
thousands):

<TABLE>
<CAPTION>

                                                                  December 31,
                                                                 1999     1998
                                                               -------   -------
<S>                                                            <C>       <C>
   Revolving credit facility due 2002........................   $42,000  $29,500
   8-7/8% Senior Subordinated Notes due 2007.................   150,000  150,000
   10-1/2% Senior Subordinated Notes due 2006,
     including premium totaling approximately $5.7 and $6.5
     million for 1999 and 1998, respectively.................   114,744  115,490
                                                                -------  -------
             Total Debt......................................   306,744  294,990
   Less: Current maturities..................................        --       --
                                                               --------  -------
   Long term debt............................................  $306,744 $294,990
                                                               ======== ========
</TABLE>

     In September, 1997 the Company entered into a five-year $150 million Credit
Agreement dated September 23, 1997 (as amended,  the "Credit Facility") with The
Chase  Manhattan  Bank,  N.A., as  administrative  agent (the "Agent") and other
lending  institutions  (the  "Banks").  The  Credit  Facility  provides  for  an
aggregate  principal  amount  of  revolving  loans of up to the  lesser  of $150
million or the Borrowing Base (as defined) as in effect from time to time, which
includes  a  subfacility  from the  Agent  for  letters  of  credit of up to $25
million.  The  Borrowing  Base at December 31, 1999 was set at $150 million with
$42.0  million  advanced  to the  Company at that date.  The  borrowing  base is
redetermined  by the  Agent and the Banks  semi-annually,  determined  solely at
their  discretion,  predicated on the Company's  oil and gas reserve  value.  In
addition, the Company may request two additional  redeterminations and the Banks
may request one  additional  redetermination  per year.  During 1999, the Credit
Facility weighted average interest rate was approximately 6.0%.

     Indebtedness  of the  Company  under the  Credit  Facility  is secured by a
pledge of the  capital  stock of each of the  Company's  material  subsidiaries.
Covenants  contained  in the Credit  Facility  require  the  Company to maintain
a minimum  Interest Coverage Ratio, Current Ratio and Leverage Ratio (Indebted-
ness to EBITDA). The Company and its subsidiaries may not incur any indebtedness
other  than  indebtedness  falling  within  the enumerated  exceptions contained
in the  Credit  Facility.  In  addition,  the Company's various debt instruments
contain certain  restrictive  covenants that, among other things, limit the
ability of the Company to pay dividends.

     Indebtedness  under the Credit  Facility  bears interest at a floating rate
based (at the Company's option) upon (i) the ABR (as defined below) with respect
to ABR Loans or (ii) the  Eurodollar  Rate for one, two, three or six months (or
nine or twelve  months if  available  to the Banks) with  respect to  Eurodollar
Loans, plus the Applicable Margin. The ABR is the greater of (i) the Prime Rate,
(ii) the Base CD Rate plus 1% or (iii) the  Federal  Funds  Effective  Rate plus
0.50%.  The Applicable  Margin for Eurodollar  Loans varies from 0.50% to 0.875%
depending on the Borrowing  Base usage.  Borrowing Base usage is determined by a
ratio of (i) outstanding  Loans and letters of credit to (ii) the then effective
Borrowing Base. Interest on

                                      F-11


<PAGE>



ABR Loans will be payable  quarterly in arrears and interest on Eurodollar Loans
is payable on the last day of the interest period  therefore and, if longer than
three months, at three month intervals.

     The Company is required to pay to the Banks a  commitment  fee based on the
committed undrawn amount of the lesser of the aggregate  commitments or the then
effective  Borrowing  Base during a  quarterly  period  equal to a percent  that
varies from 0.20% to 0.30% depending on the Borrowing Base usage.

     In September  1997,  the Company  issued $150 million of the 8-7/8%  Notes.
Interest accrues at the rate of 8-7/8% per annum and is payable semi-annually in
arrears on March 15 and September 15 of each year, commencing on March 15, 1998.
The 8-7/8% Notes mature on September 15, 2007 unless previously redeemed. Except
under  limited  circumstances,  the 8-  7/8%  Notes  are not  redeemable  at the
Company's option prior to September 15, 2002. Thereafter,  the 8-7/8% Notes will
be subject to redemption  at the option of the Company,  in whole or in part, at
specified  redemption prices, plus accrued and unpaid interest,  if any, thereon
to the  applicable  redemption  date. In addition,  upon a change of control (as
defined in the indenture pursuant to which the 8-7/8% Notes were issued (the "8-
7/8%  Indenture"))  the Company is required to offer and redeem the 8-7/8% Notes
for cash at 101% of the principal amount,  plus accrued and unpaid interest,  if
any, thereon to the applicable date of repurchase.

     The 8-7/8% Notes are general  unsecured  obligations of the Company and are
subordinated  in right of payment to all  existing  and future  senior  debt (as
defined in the 8-7/8% Indenture) of the Company, which includes borrowings under
the Credit Facility  described  above. The 8-7/8% Notes rank pari passu in right
of payment with any existing or future senior  subordinated  debt of the Company
and rank senior in right of payment to all other  subordinated  indebtedness  of
the Company.

     As of December  31,  1999,  the Company had  outstanding  $109 million face
value of the  10-1/2%  Notes.  The  debt  was  assumed  in  connection  with the
acquisition  of Coda in 1997  and was  recorded  at  $117.1  million,  including
premium, reflecting the fair value at the date of acquisition. The 10-1/2% Notes
bear interest at an annual rate of 10-1/2%  payable  semiannually  in arrears on
April 1 and October 1 of each year. The Notes are general, unsecured obligations
of the  Company,  are  subordinated  in right of payment to all Senior  Debt (as
defined in the Indenture  governing the 10-1/2%  Notes) of the Company,  and are
senior in right of payment to all future  subordinated  debt of the Company.  On
February  25,  1998,  the Company  merged Coda into Belco and Belco  assumed the
obligations  under the Coda  Indenture.  Effective with the merger,  the 10-1/2%
Notes became pari passu in right of payment with the 8-7/8% Notes.

     The 10-1/2%  Notes were issued  pursuant to an  Indenture,  which  contains
certain  covenants that,  among other things,  limit the ability of Coda and its
restricted  subsidiaries  (as  defined  in the  Indenture)  to incur  additional
indebtedness  and issue  Disqualified  Stock (as defined in the Indenture),  pay
dividends, make distributions,  make investments,  make certain other restricted
payments,  enter into certain  transactions with affiliates,  dispose of certain
assets,  incur liens  securing pari passu or  subordinated  indebtedness  of the
Company and engage in mergers and consolidations.

     The 10-1/2% Notes are not redeemable by the Company prior to April 1, 2001.
After April 1, 2001,  the  10-1/2%  Notes will be subject to  redemption  at the
option of the Company,  in whole or in part, at the redemption  prices set forth
in the  Indenture,  plus accrued and unpaid  interest  thereon to the applicable
redemption date.

     In  December  1997,  the  Company  entered  into  two  interest  rate  swap
agreements  converting two fixed rate obligations to floating rate  obligations.
The first agreement  covers $100 million of 8-7/8% long-term debt (comparable to
the  interest  rate on the 8-7/8%  Notes) and  obligates  the  Company to pay an
initial  rate of 8.175%  through  September  15, 1998.  Thereafter,  the rate is
redetermined  at each six month period through  September 15, 2007. The floating
rates are capped at 8-7/8% through  September 15, 2001 and at 10% from March 15,
2002 through  September 15, 2007.  The second  agreement  covers $110 million of
10-1/2%  long-term  debt  (comparable to the interest rate on the 10-1/2% Notes)
and  obligates  the Company to pay an initial rate of 9.8881%  through  April 1,
1998.  Thereafter,  the rate is  redetermined  at each six month period  through
2003.  Floating rates on this agreement are capped at 10-1/2% through October 1,
1999 and 11.625% from April 1, 2000 through April 1, 2003.

                                      F-12


<PAGE>



NOTE 5 -- RELATED-PARTY TRANSACTIONS

     The  Company's   executive   offices  are  leased  from  its  Chairman  and
approximately  $250,000  was paid under such lease in 1999,  1998 and 1997.
Management  believes  the fee  compares  favorably to the terms which might have
been available from a non-affiliated party.

     Certain  employees of the Company had an ownership  interest in certain oil
and gas properties  held by the Company as of December 31, 1995. The Company had
receivables  of  $753,000  and  $775,000  as of  December  31,  1999  and  1998,
respectively,  and related to amounts  loaned to  employees in  connection  with
purchases of oil and gas interests  from such  employees.  The notes  receivable
have been recorded as a reduction of equity in the consolidated  balance sheets,
as such interests were exchanged for Common Stock in the  Combination  (See Note
1).

NOTE 6-- INCOME TAXES
     Total provision (benefit) for income taxes consists of the following:

<TABLE>
<CAPTION>

                                                    Years Ended December 31,
                                                  1999        1998       1997
                                                --------    --------   --------
                                                         (In thousands)
<S>                                            <C>         <C>        <C>
Current:

  Federal (a)................................  $ (6,661)    $   20    $   (192)
  State......................................       225         87         373
                                                -------     -------  ----------
                                                 (6,436)       107         181
Deferred: (a)................................    (1,805)   (78,214)    (31,536)
                                                 -------   --------   ---------
      Total income tax provision (benefit)...   $(4,631)  $(78,107)   $(31,355)
                                                ========  =========   =========
</TABLE>
--------------------
(a) The 1999 federal income tax amount reflects a tax benefit of $6.7 million
for which a refund claim was filed in late 1999.  Accordingly, this amount was
recorded as an income tax refund receivable as of December 31, 1999.  The refund
was received in January 2000.

     The  differences  between  the  statutory  federal  income  taxes  and  the
Company's effective taxes is summarized as follows (in thousands):

<TABLE>
<CAPTION>

                                                   Years Ended December 31,
                                                 1999        1998        1997
                                               --------    --------    --------
<S>                                            <C>         <C>         <C>
Statutory federal income taxes...............   $(4,631)   $(78,982)   $(30,892)
State income tax, net of federal benefit.....       146          57         242
Section 29 tax credits.......................        --          --        (850)
Capital loss valuation allowance.............      (161)        875          --
Other........................................        15         (57)        145
                                               --------    ---------   ---------
Provision (benefit) for income taxes.........   $(4,631)   $(78,107)   $(31,355)
                                               ========    =========   =========

</TABLE>

                                      F-13


<PAGE>



     The principal components of the Company's net deferred income tax liability
are as follows:
<TABLE>
<CAPTION>

                                                    Years Ended December 31,
                                                    ------------------------
                                                       1999         1998
                                                     --------    ---------
                                                         (in thousands)
<S>                                                 <C>          <C>
Deferred income tax assets
  Commodity price risk management activities.....    $    --       $3,940
  Net operating loss.............................     21,416       12,092
  Capital loss...................................      4,495        5,055
  Other..........................................      8,095        5,983
                                                     -------      -------
                                                     $34,006      $27,070
                                                     -------      -------
Deferred income tax liabilities
  Depreciation, depletion and amortization.......   $(60,834)    $(55,369)
  Commodity price risk management actitivities...     (1,875)          --
  Other..........................................     (4,221)      (2,659)
                                                     --------    ---------
                                                     (66,930)     (58,028)
Valuation allowance..............................       (714)        (875)
                                                    ---------    ---------
          Net deferred income tax liability......   $(33,638)    $(31,833)
                                                    =========    =========
</TABLE>

     As a result  of the  acquisition  of Coda,  the  Company  succeeded  to net
operating loss  carryforwards  ("NOLs") for income tax purposes that expire from
2000 through  2004.  Due to a change of ownership  (as defined by the Tax Return
Act of  1986)  which  occurred  prior to the  acquisition  by the  Company,  the
utilization of the Coda NOLs is severely  restricted.  At December 31, 1999, the
Company estimates that approximately $12.4 million of the Coda NOLs is available
to offset  future  income.  For the year ended  December 31,  1999,  the Company
generated an NOL of  approximately  $48.8 million  which can be carried  forward
from 2000 to 2020.  In addition to the NOLs,  at December 31, 1999,  the Company
has approximately $12.8 million of capital loss carry forwards which may be used
to offset capital gains realized over the next four years. A valuation allowance
of $2.0 million was established against the capital loss carryforward since this
amount is not expected to meet the  realization  test. The Company also has $0.6
million of alternative minimum tax ("AMT") credit carryovers. AMT credits may be
carried forward indefinitely.

Section 29 Tax Credit

     The natural gas  production  from wells drilled on certain of the Company's
properties  in the Moxa Arch  Trend and Golden  Trend  Field  qualifies  for the
Section 29 Tax Credit. The Section 29 Tax Credit is an income tax credit against
regular  federal  income tax  liability  with respect to sales of the  Company's
production of natural gas produced from tight gas sand formations,  subject to a
number of  limitations.  Fuels  qualifying for the Section 29 Tax Credit must be
produced from a well drilled or a facility  placed in service after  November 5,
1990 and before January 1, 1993, and be sold before January 1, 2003.

     The  basic  credit,  which is  currently  approximately  $0.52 per MMBtu of
natural gas produced  from tight sand  reservoirs  and  approximately  $1.06 per
MMBtu of natural gas produced from Devonian  Shale,  is computed by reference to
the price of crude oil and is phased out as the price of oil  exceeds  $23.50 in
1979 dollars (as adjusted for  inflation)  with complete  phaseout if such price
exceeds $29.50 in 1979 dollars (as adjusted for inflation).  Under this formula,
the  commencement  of phaseout would be triggered if the average price for crude
oil  rose  above  approximately  $48 per Bbl in  current  dollars.  The  Company
estimates that it generated approximately $0.6 million of Section 29 Tax Credits
in 1999. The Section 29 Tax Credit may not be credited  against the  alternative
minimum tax,  but under  certain  circumstances  may be carried over and applied
against regular tax liability in future years.  Therefore,  no assurances can be
given that the Company's  Section 29 Tax Credits will reduce its federal  income
tax  liability in any  particular  year.  As  production  from  qualified  wells
decline, the produced based tax credit will also decline.

                                      F-14


<PAGE>



Texas Severance Tax Abatement

     Production  from  natural  gas  wells  that have  been  certified  as tight
formations  or deep  wells by the  Texas  Railroad  Commission  ("high  cost gas
wells") and that are spudded or completed during the period from May 24, 1989 to
September 1, 1996 qualify for an exemption  from the 7.5% severance tax in Texas
on natural gas and  natural  gas liquids  produced by such wells prior to August
31,  2001.  The  natural  gas  production  from wells  drilled on certain of the
Company's properties in the Austin Chalk area qualify for this tax reduction. In
addition,  high cost gas wells that are spudded or  completed  during the period
from  September  1, 1996 to August 31, 2002 are  entitled to receive a severance
tax  reduction  upon  obtaining  a high  cost gas  certification  from the Texas
Railroad Commission within 180 days after first production. The tax reduction is
based on a formula  composed of the  statewide  "median" (as  determined  by the
State of Texas from producer  reports) and the  producer's  actual  drilling and
completion  costs.  More  expensive  wells will receive a greater  amount of tax
credit.  This tax rate  reduction  remains  in effect  for 10 years or until the
aggregate tax credits  received  equal 50% of the total  drilling and completion
costs.  The  reduction  in  severance  taxes for such  wells is  reflected  as a
reduction in oil and gas operating  expenses and an increase in the standardized
measure  of  discounted  future net cash  flows  relating  to proved oil and gas
reserves (See Note 14).

NOTE 7-- COMMODITY PRICE RISK MANAGEMENT ACTIVITIES AND FAIR VALUE OF FINANCIAL
INSTRUMENTS

Oil and Gas Hedging Transactions

     With the objective of achieving  more  predictable  revenues and cash flows
and reducing the exposure to fluctuations in gas and oil prices, the Company has
entered into hedging  transactions of various kinds with respect to both gas and
oil.  While the use of these  hedging  arrangements  limits the downside risk of
adverse price movements,  it may also limit future revenues from favorable price
movements.  As of December  31,  1999,  the Company  had  entered  into  hedging
transactions  with  respect  to a  significant  portion  of  its  estimated  oil
production  for  2000  and  approximately  50%  of  its  estimated  natural  gas
production.  Similar transactions were entered into covering lower quantities of
its  estimated  production  for the years  2001-2002.  The Company  continues to
evaluate whether to enter into additional hedging transactions for future years.
In addition,  the Company may determine  from time to time to terminate its then
existing hedging positions if market conditions warrant.

     The  following  table and notes  thereto  cover the  Company's  pricing and
notional volumes on open natural gas and oil commodity hedges as of December 31,
1999:
<TABLE>
<CAPTION>

                                                               Production Periods
                                                             -----------------------
                                                              2000     2001    Total
                                                             ------   ------   -----
<S>                                                          <C>      <C>     <C>
Gas--
  Price swaps-- receive fixed price (thousand MMBtu)(1)(5)..  4,890       -     4,890
     Average price, per MMBtu...............................  $2.29       -     $2.29
  Collars and options (thousand MMBtu)(2)................... 12,785   9,125    21,910
     Average floor price, per MMBtu.........................  $1.47   $1.91     $1.63
     Average ceiling price, per MMBtu.......................  $2.62   $2.85     $2.73
  Price swaps-- pay fixed price (thousand MMBtu)(3).........    310       -       310
     Average price, per MMBtu...............................  $2.81       -     $2.81
  Basis swaps (thousand MMBtu)(4)...........................  7,320       -     7,320
     Average basis differential, per MMBtu.................. ($0.49)      -    ($0.49)
Oil--
  Price swaps-- receive fixed price (MBbls)(1)(3)(7)........    610     268       878
     Average price, per Bbl................................. $18.81  $17.99    $18.56
  Collars and options (MBbls)(2)(6).........................    959     184     1,143
     Average floor price, per Bbl........................... $16.95  $17.71    $17.06
     Average ceiling price, per Bbl......................... $19.81  $20.90    $19.99
</TABLE>

                                      F-15


<PAGE>



----------
(1)      For any particular swap  transaction,  the  counterparty is required to
         make a payment to the  Company  in the event  that the NYMEX  Reference
         Price for any  settlement  period is less than the swap  price for such
         hedge,   and  the  Company  is  required  to  make  a  payment  to  the
         counterparty  in the  event  that the  NYMEX  Reference  Price  for any
         settlement period is greater than the swap price for such hedge.

(2)      For any particular collar transaction,  the counterparty is required to
         make a payment to the Company if the average NYMEX  Reference Price for
         the reference period is below the floor price for such transaction, and
         the  Company is  required to make  payment to the  counterparty  if the
         average  NYMEX  Reference  Price is above  the  ceiling  price for such
         transaction.

(3)      In order to close certain commodity price hedge positions,  the Company
         entered  into  various  swap   positions   where  the  Company  is  the
         fixed-price payer on the swap. In these transactions,  the counterparty
         is  required  to make a payment  to the  Company  in the event that the
         NYMEX  Reference  Price for any  settlement  period is greater than the
         swap  price,  and the  Company  is  required  to make a payment  to the
         counterparty  in the  event  that the  NYMEX  Reference  Price  for any
         settlement period is less than the swap price.

(4)      The Company sells its Wyoming gas at prices based on the Northwest
         Pipeline  Rocky  Mountain Index and has entered into basis swaps that
         require the counterparty to make a payment to the  Company in the event
         that the NYMEX  Reference Price per MMBtu for a reference  period ex-
         ceeds the Northwest  Pipeline Rocky  Mountain  Index  Price by more
         than a stated  differential and requires the Company to make a payment
         to the counterparty in the event that the NYMEX  Reference  Price ex-
         ceeds the Northwest  Pipeline  Rocky Mountain  Index  Price by less
         than a stated differential (or in the event that the Northwest Pipeline
         Rocky Mountain Index Price is greater than the NYMEX Reference Price).

(5)      Does not include 920, 19,155 and 3,650 thousand MMBtu of swaps in 2000
         through 2002, respectively, that are extendable at the election of the
         counterparty.

(6)      Does not include 108 and 13 MBbls collars in 2001 and 2002, respective-
         ly, that are extendable at the election of the counterparty.

(7)      Does not include 333, 840, 966, 590 and 31 thousand  Bbls of swaps in
         2000 through 2004, respectively  that are extendable at the option of
         the counterparty.

     All of the above  transactions  were  carried  out in the  over-the-counter
market, and not on the NYMEX.  These financial  counterparties all have at least
an investment grade credit rating. All of these transactions  provide solely for
financial settlements related to closing prices on the NYMEX.

     A realized hedging gain (loss) of $3.9 million,  $1.9 million and $(13.1)
million for 1999, 1998 and 1997,  respectively,  was included in Commodity Price
Risk Management  revenues.  As of December 31, 1999 and 1998, the Company had no
accrued liabilities settled derivative contracts.  These amounts are included in
Price Risk Management activities as assets or liabilities as appropriate.

                                      F-16


<PAGE>



Non-Hedging Transactions

     As  described  in Note 2, the  Company  uses the  mark-to-market  method of
accounting for instruments  that do not qualify for hedge  accounting.  The 1999
results of  operations  included  an  aggregate  pre-tax  loss of $33.8  million
related to these  activities which included (1) net premiums  received  totaling
$248,000 and (2) the unrealized  loss resulting from net change in the value
of the Company's  market-to-market portfolio of price risk management activities
for the year ended December 31, 1999 of $34.1 million, all included in Commodity
Price Risk Management revenues. At December 31, 1999, the Company's consolidated
balance sheet reflects $3.0 million and $26.0 million of price risk  management
assets and liabilities, respectively.

     The  following  table and notes  thereto  cover the  Company's  pricing and
notional  volumes on open natural gas and oil financial  instruments at December
31, 1999, that do not qualify for hedge accounting:
<TABLE>
<CAPTION>

                                                                                 Production Periods
                                                              -----------------------------------------------
                                                                 2000         2001        2002        2003       Total
                                                              ----------   ----------  ----------  ----------  -------
<S>                                                             <C>         <C>         <C>         <C>        <C>
Gas--
  Calls bought (thousand MMBtu)(2)............................    2,120           -           -           -      2,120
     Average price, per MMBtu.................................    $2.98           -           -           -      $2.98
  Calls Sold (thousand MMBtu)(2)..............................    7,320       7,300           -           -     14,620
     Average price, per MMBtu.................................    $2.78       $3.23           -           -      $3.00
  Puts Sold (thousand MMBtu)(2)...............................    3,620           -           -           -      3,620
     Average price, per MMBtu.................................    $2.28           -           -           -      $2.28
  Price Swaps-- receive fixed price (thousand MBbls)(3)(4)....    7,320       3,650           -           -     10,970
     Average price, per MMBtu.................................    $2.30       $2.51           -           -      $2.37

Oil--
  Straddles (MBbls)(1)........................................       25           -           -           -         25
     Average price, per Bbl...................................   $17.48           -           -           -     $17.48
  Price Swaps-- pay fixed price (thousand MMBtu)..............       45           -           -           -         45
     Average price, per MMBtu.................................   $22.65           -           -           -     $22.65
  Price Swaps-- receive fixed price (MBbls) (3)(5)............    1,051         151          13           -      1,215
     Average price, per Bbl...................................   $19.27      $17.72      $17.25           -     $19.06
  Calls Bought (MBbls)(2).....................................      150           -          -           -         150
     Average price, per Bbl...................................   $19.00           -           -           -     $19.00
  Calls Sold (MBbls)(2).......................................    2,148         996         714          75      3,933
     Average price, per Bbl...................................   $20.06      $20.05      $21.86      $22.00     $20.42
  Puts Sold (MBbls)(2)........................................      986         199          19           -      1,204
     Average price, per Bbl...................................   $18.70      $15.81      $16.00           -     $18.18
  Puts Bought (MBbls)(2)......................................      404          38           -           -        442
     Average price, per Bbl...................................   $17.82      $17.17           -           -     $17.76
</TABLE>
----------
(1)  A straddle is a combination  of a put sold and a call sold at the same
     strike price.  The Company is required to make a payment to the  counter-
     party in the event that the NYMEX Reference Price for any settlement period
     is greater than the ceiling price or less than the floor price. The Company
     receives a significant  premium upon entering into such contract.

(2)  Calls sold or puts sold under  written  option  contracts,  in return for a
     premium  received  by  the  Company  upon  initiation  of  the contract.
     The Company is required to make a payment to the counterparty in the event
     that the NYMEX  Reference  Price  for any  settlement  period is greater
     than the price of the call sold,  or less than the price of the put sold.
     Conversely,  calls or puts bought in return for the Company's payment of a
     premium or require the counterparty to make a payment to the company in the
     event that the NYMEX  Reference  Price on any settlement  period is greater
     than the call  price or less  than the put price.

                                      F-17


<PAGE>



(3)  For any particular swap transaction, the counterparty is required to make a
     payment to the Company in the event that the NYMEX  Reference Price for any
     settlement  period is less than the swap price for such  instrument and the
     Company is required to make a payment to the counterparty in the event that
     the NYMEX  Reference  Price for any  settlement  period is greater than the
     swap price for such  instrument.  All of these swaps listed will double the
     volumes  swapped when the NYMEX Reference Price is above the swap price for
     such instrument.

(4)  Does not include 3,660 thousand MMBtu of gas swap which have tiered pricing
     at which the swap is canceled when the NYMEX Reference Price falls below
     $1.80 per MMBtu.

(5)  Does not  include  341 and 38 MBbls  of oil  swaps  for  2000  and  2001,
     respectively,  which have tiered pricing at which the swap is canceled when
     the NYMEX  Reference  Price  falls  below  $16.50  per Bbl as to 52% of the
     volumes and $18.00 for the remaining volume.

Fair Value of Financial Instruments

     The following table presents the carrying amounts and estimated fair values
of the Company's  financial  instruments at December 31, 1999 and 1998. SFAS No.
107 defines the fair value of a financial  instrument as the amount at which the
instrument could be exchanged in a current transaction between willing parties.
<TABLE>
<CAPTION>

                                       December 31, 1999    December 31, 1998
                                       -----------------    -----------------
                                       Carrying    Fair     Carrying    Fair
                                        Amount    Value      Amount    Value
                                       --------   -----     --------   ------
                                                  (In thousands)
<S>                                    <C>      <C>         <C>       <C>

Cash and cash equivalents..............  $2,105   $2,105      $2,435   $2,435
Long-term debt......................... 306,744  296,323     294,990  277,180
Interest rate swaps....................      --   (6,549)         --      196
Oil and gas commodity-- Hedges.........      --   (8,603)         --    4,584
                     -- Non-hedges..... (23,066) (23,066)     11,028   14,368
</TABLE>

     The carrying values of trade receivables and trade payables included in the
accompanying consolidated  balance sheets  approximated market value at December
31, 1999 and 1998.The following  methods and assumptions were used to estimate
the fair value of the financial instruments  summarized in the above table.

Cash and Cash Equivalents

     The carrying  amounts  approximate fair value because of the short maturity
of those instruments.

Marketable Equity Securities

     In June 1997 the  Company  purchased  2,940,000  shares of common  stock of
Hugoton Energy Corp.  ("Hugoton") at $10.50 per share for a total  investment of
$30.9 million. At December 31, 1997 a non-cash investment valuation provision in
the amount of $2 million  was  charged to  stockholder's  equity to reflect  the
value of this  investment at that date.  In March 1998,  Hugoton was acquired by
Chesapeake  Energy  Corporation  ("CHK").  In the  merger  each share of Hugoton
common stock was converted into 1.3 shares of CHK common stock.  During 1998 the
Company disposed of its holdings in CHK and realized a loss of $14.4 million.

                                      F-18


<PAGE>



     On  June  12,  1998,  the  Company,   through  its  wholly-owned   Canadian
subsidiary,  purchased  approximately $10.5 million of 5% Convertible  Preferred
Stock of Big  Bear  Exploration,  Ltd.  ("Big  Bear"),  a  Canadian  oil and gas
company,  at approximately  $0.85 per share with each share convertible into one
common share of Big Bear. Through a subsequent restructuring agreement,  Belco's
preferred  stock  holdings were converted to common stock and then subject to an
11:1 reverse stock split. As a result of the aforementioned transactions,  Belco
became the owner of 1,948,052 common shares or  approximately  4.6% ownership in
Big Bear. The substantial  decline in the market value of Big Bear securities at
year-end  1999 and 1998 required the Company to record $0.45 and $9.7 million in
impairment provisions, respectively.

     In January 2000,  shareholders of Big Bear approved its acquisition by AVID
Oil & Gas, Ltd. ("AVID"), a Canadian based energy company providing for Big Bear
shareholders  to receive 1 share of AVID common stock for every 15 common shares
of Big Bear.  As a result of the transaction described above, the Company cur-
rently owns 129,870 shares of Avid with an approximate market value of $190,000
(US) as of December 31, 1999.

Long-Term Debt

     The fair value of the  Company's  revolving  credit  facility debt of $42.0
million is assumed to be the same as the  carrying  value  because the  interest
rate is  variable  and is  reflective  of market  rates.  The fair  value of the
10-1/2% Notes is based upon the quoted  market  prices for that issue.  The fair
value of the 8-7/8%  Notes is based upon  estimates  provided  to the Company by
independent banking firms.

Interest Rate Swaps and Oil and Gas Commodity Financial Instruments

     The estimated  fair values of interest rate swaps and oil and gas commodity
financial  instruments  have been  provided  by  responsible  third  parties and
determined  by using  available  market  data  and  applying  certain  valuation
methodologies.  In some cases,  quotes of  termination  values  were  available.
Judgment  is  usually  required  in  interpreting  market  data,  and the use of
different  market  assumptions  or  estimation  methodologies  could  result  in
different estimates of fair value.

NOTE 8 -- COMMITMENTS AND CONTINGENCIES

Future Contingencies Related to the Moxa Arch Programs

     From 1992 to 1994,  the  Company  established  three  Moxa Arch  investment
programs:  the 1992  Moxa Arch  Drilling  Program,  the 1993 Moxa Arch  Drilling
Program,  and the Moxa Arch 1992 Offset  Drilling  Program.  The  Programs  were
established  to develop  certain  drilling  prospects  acquired as a result of a
farmout agreement with Amoco Production  Company and others. The Company offered
certain  qualified  investors (the  Investors) the  opportunity to invest in the
prospects  through  participation in the Programs.  Through  October 30, 1996,
the  Company  owned  approximately  55.20  percent  of the 1992 Moxa Arch
Drilling  Program,  32.45  percent of the 1993 Moxa Arch Drilling  Program,  and
58.21 percent of the Moxa Arch 1992 Offset Drilling Program. On October 31, 1996
the  Company  purchased  from  certain  third-party   investors  interests  (the
"Acquired  Interests") in the Belco Oil & Gas Corp.  1992,  1993 and 1992 Offset
Moxa Arch Drilling Programs.  The effective date of the purchase was October 31,
1996  for  financial  reporting  purposes.   The  Acquired  Interests  represent
incremental  working  interests in the  Company's  natural gas wells in the Moxa
Arch trend  located in Lincoln,  Sweetwater  and Uinta  Counties,  Wyoming.  The
Company  paid  aggregate  cash   consideration  of  $9.9  million  plus  an  80%
participation  in  potential  natural gas price  increases  (net of  incremental
production  costs)  associated  with  production from the wells through July 31,
1999 (the "Price  Participation  Right").  In November 1999, pursuant to the 80%
Price  Participation Right provision the Company paid out $2.3 million to former
third party  investors in the Moxa Program.  After the  purchase,  the Company's
interest in these programs was increased to 81.5% of the 1992 Moxa Arch Drilling
Program,  74.0% of the 1993 Moxa Arch Drilling  Program,  80.5% of the Moxa Arch
1992 Offset  Drilling  Program,  and 74% of the Moxa Arch 1993  Offset  Drilling
Program.  The  transaction  was  accounted  for  using  the  purchase  method of
accounting.

                                      F-19


<PAGE>



     The  remaining  third-party  investors  in the  Programs  may  "put"  their
interest to Belco annually  through 2003, based upon a valuation by a nationally
recognized  independent petroleum engineering firm of the discounted net present
value of the future net revenues from production of proved reserves attributable
to the  interests.  The  put  amount  is to be  calculated  based  upon  certain
specified  parameters  including  prices,  discount factors and reserve life. No
investor under the Programs  exercised the put right through  December 31, 1999.
The Company is not  obligated to  repurchase  in any one calendar year more than
30% of the interests  originally  acquired by the program investors  (including,
for  purposes  of this  calculation,  the  Company's  interest).  The  Company's
purchase  price  under  the put  right  has not been  calculated  given  that no
investors have exercised such right. However,  using reserve values presented in
Note 14,  Standardized  Measure of Discounted  Future Net Cash Flows Relating to
Proved Oil and Gas Reserves  (SEC basis using year end prices and a 10% discount
rate), the maximum purchase price if all remaining  investors  exercised the put
option would not be material to the Company as of December 31, 1999.

Lease Commitments

     At December 31, 1999,  the Company had  operating  leases  covering  office
space.  Minimum rental  commitments  under operating  leases are $44,000 for the
year 2000.  For the years ended December 31, 1999, 1998 and 1997,  total rental
expense was approximately $316,000, $512,000 and $438,000, respectively.

Legal Proceedings

     The Company is a named  defendant in routine  litigation  incidental to its
business.  While the ultimate results of these  proceedings  cannot be predicted
with  certainty,  the Company does not believe that the outcome of these matters
will have a material adverse effect on the Company.

Environmental Matters

     The Company's  operations are subject to various  federal,  state and local
laws and regulations  relating to the protection of the environment,  which have
become increasingly  stringent.  The Company believes its current operations are
in material  compliance with current  environmental laws and regulations.  There
are no environmental claims pending or, to the Company's  knowledge,  threatened
against the Company. There can be no assurance, however, that current regulatory
requirements will not change,  currently unforeseen environmental incidents will
not occur or past  noncompliance  with environmental laws will not be discovered
on the Company's properties.

NOTE 9 -- CASH FLOW INFORMATION

Supplemental Disclosure of Cash Flow Information
<TABLE>
<CAPTION>

                                                     For Year Ended December 31,
                                                     ---------------------------
                                                        1999     1998     1997
                                                       ------   ------   ------
                                                            (in thousands)
<S>                                                  <C>       <C>      <C>
Cash paid (received) during the year for:

  Interest, including amounts capitalized...........  $26,823  $26,139   $  307
  Income and other taxes, net of (refunds)..........      487     (788)   1,345
</TABLE>

     In November  1997,  the company  acquired  Coda for cash,  warrants and the
assumption of certain liabilities. See Note 3.

                                      F-20


<PAGE>



NOTE 10 -- CUSTOMER INFORMATION

Concentrations of Credit Risk

     The Company's revenues are derived from uncollateralized sales to customers
in the oil and gas  industry.  The  concentration  of  credit  risk in a  single
industry affects the Company's overall exposure. The Company has not experienced
significant credit losses on such sales.

Major Customers

     Oil and gas sales for 1999 include  $26.6  million,  $16.1  million,  $14.1
million and $11.9 million in revenues  received from four customers.  Also, 1999
revenues included net losses in the amount of $33.8 million related to Commodity
Price  Risk  Management  Activities.  Oil and gas sales for 1998  include  $28.9
million and $16.9 million in revenues  received from two customers.  Also,  1998
revenues  include  Commodity  Price Risk  Management  net gains  totaling  $24.8
million.  Oil and gas sales for 1997 include  $40.6  million,  $27.9 million and
$25.5 million in revenues received from three customers and Commodity Price Risk
Management net losses of $6.5 million. No other customers individually accounted
for 10 percent or more of revenues.

NOTE 11 -- EMPLOYEE BENEFIT PLANS

Retirement Plan

     The  Company  provides  a 401(k)  and  savings  plan for all its  full-time
employees.  The plan qualifies under Section 401(k) of the Internal Revenue Code
as a salary reduction plan.  Under the plan, but subject to certain  limitations
imposed under the Internal Revenue Code, eligible employees are permitted to (a)
defer  receipt  of up to 15  percent of their  compensation  on a pre-tax  basis
(salary  deferral  contributions)  or (b)  contribute  up to 10 percent of their
compensation to the plan on an after-tax  basis. The plan provides for a Company
matching  contribution  in an amount equal to 50 percent (75% for employees with
more  than  three  years  of  service)  of  a   participant's   salary  deferral
contributions  that  are  not in  excess  of 6  percent  of  such  participant's
compensation. The plan also permits the Company, in its sole discretion, to make
a  contribution  that is  allocated  on the  last day of each  calendar  year to
certain eligible participants.  Company matching and discretionary contributions
are vested over a period of five years at the rate of 20 percent per year.

     During  1999, 1998 and 1997, the Company incurred contribution expenses of
$378,000, $398,000 and $99,000, respectively, in connection with this plan.

NOTE 12 -- CAPITAL STOCK

     On March 10, 1998 the Company  completed the sale of 4.37 million shares of
its 6-1/2% Convertible  Preferred Stock (the "Preferred  Stock").  The Preferred
Stock has a liquidation  preference of $25 per share and is  convertible  at the
option of the holder into  shares of the  Company's  Common  Stock at an initial
conversion  rate of 1.1292  shares of Common  Stock for each share of  Preferred
Stock, equivalent to a conversion price of $22.14 per share of Common Stock. The
Company  received net proceeds  from the sale of the  Preferred  Stock of $105.1
million, which was used to pay down bank indebtedness.

     In December 1998, the Company's Board of Directors (the "Board") authorized
the purchase  from time to time,  in the open market or in privately  negotiated
transactions,  shares of its Common Stock and 6-1/2% Convertible Preferred Stock
in an  aggregate  amount  not to exceed  $10  million.  This  authorization  was
exhausted in December 1999.  Subsequently, the Board authorized an additional
$10 million for the purchase of additional Common and Preferred Shares.

Net Income (Loss) Per Common Share

     Potential common stock not included in the calculation of diluted earnings
per share because to do so would have been antidilutive amounted to 7,673,000,
7,690,000 and 7,562,000 for 1999, 1998 and 1997, respectively.

                                      F-21


<PAGE>

Stock Incentive Plans

     On March 25, 1996,  the Company  adopted a Stock  Incentive Plan (the Plan)
under  which  options  for  shares of  Belco's  Common  Stock may be  granted to
officers and  employees for up to 2,250,000  shares of Common  Stock.  Under the
Plan,  options  granted may either be incentive  stock options or  non-qualified
stock  options  with a maximum  term of 10 years and are granted at no less than
the fair  market of the stock at the date of  grant.  Options  vest 20% per year
until fully vested five years from the date of grant.

     A separate  plan has been  established  under  which  options for shares of
Belco's  Common  Stock  may be  granted  to non-employee  directors  for up to
approximately  158,000  shares  of Common  Stock.  The plan  provides  that each
non-employee  director be granted stock options for 3,000 shares  annually as of
the date of the Annual  Meeting.  The option price of shares  issued is equal to
the fair market  value of the stock on the date of grant.  All  options  vest 33
1/3% per year,  beginning  one year from date of grant,  until fully  vested and
expire ten years after the date of grant.

     A summary of the status of the Company's plans (the Plans) as of December
31, 1999 and 1998 and the changes during the years then ended is presented be-
low:

<TABLE>
<CAPTION>

                                                  1999                           1998
                                        -------------------------------------------------------
                                        Shs. Under     Wtd. Avg.       Shs. Under     Wtd. Avg.
                                          Option      Exer. Price        Option     Exer. Price
                                        ----------    -----------      ----------   -----------
<S>                                     <C>            <C>             <C>            <C>
Outstanding, beginning of year.......... 1,154,000       $16.25          960,500       $20.31
  Granted...............................   414,500         5.19          433,000         9.82
  Exercised.............................        --           --               --           --
  Forfeited.............................   (62,000)       15.00         (239,500)       19.37
                                         ----------     -------        ---------       ------
Outstanding, end of year................ 1,506,500       $13.68        1,154,000       $16.25
                                         =========       ======        =========       ======
Exercisable, end of year................   432,300       $18.62          201,500       $20.24
                                           =======       ======        =========       ======
Available for grant, end of year........   901,600                     1,254,100
                                           =======                     =========
Weighted average fair value of options
  granted during the year............... $    2.78                     $   10.36
                                         =========                     =========
</TABLE>


                                      F-22


<PAGE>



     The following table summarizes  information about stock options outstanding
at December 31, 1999.
<TABLE>
<CAPTION>

                            Options Outstanding          Options Exercisable
                --------------------------------------  -----------------------
                                  Weighted                             Number
                   Number         Average     Weighted   Exercis-     Weighted
                Outstanding at   Remaining     Average    able at     Average
                 December 31,   Contractual   Exercise  December 31,  Exercise
Range of Prices     1999            Life        Price      1999        Price
---------------  -------------  -----------   --------  ------------  ---------
<S>              <C>            <C>           <C>       <C>           <C>
$4.88 - $6.50      369,500         9.19         $4.99          -            -
$7.41 - $11.00     389,500         8.53         $9.80     71,200        $9.99
$12.47 - $17.63     35,000         8.34        $15.42      9,000       $14.26
$18.88 - $28.13    709,500         7.29        $19.00    350,300       $20.42
$28.81 - $29.00      3,000         6.58        $29.00      1,800       $29.00
</TABLE>

     As permitted  by SFAS No. 123,  the Company  applies APB Opinion No. 25 and
related  Interpretations in accounting for its stock option plans.  Accordingly,
no  compensation  expense has been  recognized for the Plans.  Had  compensation
costs been determined based on the fair value at the grant dates consistent with
the  method of SFAS No.  123,  the  Company's  pro forma net  income  (loss) for
calendar  years 1999 and 1998 would have been  reduced to the pro forma  amounts
indicated below (in thousands, except for per share amounts):

<TABLE>
<CAPTION>

                                                    1999             1998
                                               -------------     -----------
<S>                                             <C>              <C>
Net Income (Loss) Available to Common Stock
  As Reported..................................  $ (15,484)       $(152,963)
  Pro Forma....................................  $ (15,886)       $(154,625)
Basic and Diluted Net Income (Loss) Per Share

  As Reported..................................  $   (0.49)       $   (4.85)
  Pro Forma....................................  $   (0.50)       $   (4.90)
</TABLE>

     The fair  value of  grants  was  estimated  on the date of grant  using the
Black-Scholes   options  pricing  model  with  the  following  weighted  average
assumptions used in 1999 and 1998, respectively: risk-free interest rate of 5.43
and 5.60 percent,  expected volatility of 48.3 and 49.0 percent,  expected lives
of 6.0 years and no dividend yield.

     Under the Stock Incentive Plan,  participants  may be granted stock without
cost (restricted  stock).  During 1999 and 1998, the Company granted 200,000 and
34,700 shares,  respectively,  of restricted  stock with a weighted average fair
value  based on the price of the  Company's  stock on the date of grant of $5.09
and $15.69  per share,  respectively.  At  December  31,  1999,  223,120  shares
remained  unvested,  net of 17,800 shares  forfeited.  The weighted average fair
value of shares forfeited was $18.57.  The restrictions on disposition lapse 20%
each year and  non-vested  shares  must be  forfeited  in the  event  employment
ceases. Unearned compensation was charged for the market value of the restricted
shares at the date the shares were issued. The unearned compensation is shown as
a reduction of  stockholders'  equity in the accompanying  consolidated  balance
sheet and is being amortized ratably as the restrictions  lapse. During 1999 and
1998,  $512,000 and  $344,100,  respectively,  was charged to costs and expenses
relating to the Plan.

NOTE 13 -- SUPPLEMENTAL QUARTERLY FINANCIAL DATA (In Thousands, Except Per Share
Amounts):
<TABLE>
<CAPTION>

                                                                           Quarters
                                                         ----------------------------------------------
                                                          First       Second        Third        Fourth
                                                         -------      ------        ------       ------
                                                                          (Unaudited)
<S>                                                     <C>           <C>          <C>          <C>
1999

Revenues................................................ $24,725       $19,572      $15,246      $49,986
Costs and Expenses...................................... $29,666       $29,751      $29,830      $30,514
Net Income (Loss)....................................... $(3,212)      $(6,617)     $(9,480)     $10,709
Basic and Diluted Net Income (Loss) Per Common Share.... $ (0.16)      $ (0.26)     $ (0.35)     $  0.29

</TABLE>

                                      F-23


<PAGE>


<TABLE>
<CAPTION>
<S>                                                     <C>           <C>          <C>         <C>
1998

Revenues...............................................  $33,351       $37,503      $34,690    $  45,186
Costs and Expenses..................................... $119,286      $108,879      $29,423     $118,805
Net Income (Loss)...................................... $(59,393)     $(43,846)     $ 3,439     $(47,756)
Basic and Diluted Net Income (Loss) Per Common Share... $  (1.90)     $  (1.43)     $  0.05    $   (1.57)
</TABLE>

     The sum of the individual  quarterly pro forma basic and diluted net income
(loss) per share  amounts  may not agree with  year-to-date  pro forma basic and
diluted  net  income  per  share as each  period's  computation  is based on the
weighted  average  number of common shares  outstanding  during that period.  In
addition,  certain potentially  dilutive securities were not included in certain
of the quarterly  computations of diluted net income per common share because to
do so would have been antidilutive.

Note 14 --  SUPPLEMENTAL  INFORMATION ON OIL AND GAS  EXPLORATION  AND PRODUCING
ACTIVITIES (Unaudited):

Capitalized Costs

     The  following  table  sets  forth  the   capitalized   costs  and  related
accumulated  depreciation,  depletion and amortization relating to the Company's
oil and gas production,  exploration  and development  activities as of December
31, 1999 and 1998 (in thousands):
<TABLE>
<CAPTION>

                                                   1999          1998
                                                -----------  -----------
<S>                                             <C>          <C>
Proved properties...............................$1,008,261     $931,218
Unproved properties.............................    71,075       74,935
                                                ----------   ----------
Total capitalized costs......................... 1,079,336    1,006,153
Less-- Accumulated depreciation, depletion and
   amortization.................................  (619,446)    (566,613)
                                                -----------   ---------
Net capitalized costs...........................  $459,890     $439,540
                                                  ========     ========
</TABLE>

Costs Not Being Amortized

     The  following  table sets forth a summary of unproved oil and gas property
costs not being  amortized at December 31, 1999, by the year in which such costs
were incurred (in thousands):
<TABLE>
<CAPTION>

                             1999     1998     1997     1996    1995    Total
                             ----     ----     ----     ----    ----    -----
<S>                         <C>      <C>      <C>       <C>     <C>    <C>
Leasehold and seismic.......$8,046   $6,128   $56,184   $177    $542   $71,077
</TABLE>

Costs Incurred

     The  following  table  sets  forth  the  costs  incurred  in  oil  and  gas
acquisition,  exploration  and  development  activities as of December 31, 1999,
1998 and 1997 (in thousands):
<TABLE>
<CAPTION>

                                   1999               1998               1997
                                 ----------       ------------       -----------
<S>                             <C>               <C>                <C>
Property Acquisitions Costs--
  Proved(1)...................... $17,608            $56,695           $443,930
  Unproved.......................  10,390             14,414             24,226
Exploration costs................  10,943             18,597             46,939
Development costs................  29,576             37,969             59,571
Capitalized interest.............   4,881              5,123              3,742
Property sales...................    (215)            (6,292)           (13,949)
                                 ---------         ---------          ----------
  Total costs incurred........... $73,183           $126,506           $564,459
                                  =======           ========           ========
</TABLE>



                                      F-24


<PAGE>



----------
(1)  Acquisition of proved  properties in 1997 includes $437.4 million  relative
     to the  acquisition  of Coda of which $50 million was allocated to unproved
     property costs.

Results of Operations for Oil and Gas Producing Activities

     The following table sets forth revenue and direct cost information relating
to the  Company's  oil and  gas  exploration  and  production  activities  as of
December 31, 1999, 1998 and 1997 (in thousands):
<TABLE>
<CAPTION>

                                                  1999        1998       1997
                                                --------    --------    -------
<S>                                            <C>         <C>         <C>
Oil and gas revenues (including commodity price
  risk management activities)...................$105,396    $149,000   $123,515
Costs and expenses--
  Lease operating expenses......................  33,683      36,969      9,365
  Production taxes..............................   5,485       3,878      3,393
  Impairment of oil and gas properties..........      --     229,000    150,000
  Depreciation, depletion and amortization......  52,833      54,863     46,684
                                                 --------    -------   --------
Results of operations from producing activities
  before income taxes...........................  13,395    (175,710)   (85,927)
Provision (benefit) for income taxes............   4,688     (61,498)   (30,537)
                                                 -------    --------    --------
Results of operations from producing activities.  $8,707   $(114,212)  $(55,390)
                                                  ======   ==========  =========
Amortization rate per Mcf equivalent, recurring. $  0.88   $    0.88   $   0.81
                                                  =======  =========   =========
</TABLE>

Oil and Gas Reserve Information

     The following  summarizes the policies used by the Company in preparing the
accompanying  oil and gas reserves and the  standardized  measure of  discounted
future net cash flows relating to proved oil and gas reserves and the changes in
such standardized measure from period to period.

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

     Proved oil and gas reserve quantities and the related discounted future net
cash flows  (without  giving  effect to hedging  activities)  as of December 31,
1999,  1998  and  1997  are  based  on  estimates  prepared  by  Miller & Lents,
independent petroleum engineers. Such estimates have been prepared in accordance
with guidelines established by the Securities and Exchange Commission (SEC).

     There are  numerous  uncertainties  inherent in  estimating  quantities  of
proved  reserves  and in  projecting  future rates of  production  and timing of
development  expenditures,  including  many  factors  beyond the  control of the
Company.  The reserve data set forth herein  represent only  estimates.  Reserve
engineering is a subjective process of estimating  underground  accumulations of
oil and gas that  cannot be measured  in an exact way,  and the  accuracy of any
reserve  estimate  is a  function  of  the  quality  of  available  data  and of
engineering and geological  interpretation and judgment. As a result,  estimates
made by  different  engineers  often vary.  In  addition,  results of  drilling,
testing  and  production  subsequent  to the  date of an  estimate  may  justify
revision of such  estimates,  and such  revisions may be material.  Accordingly,
reserve  estimates are often  different  from the quantities of oil and gas that
are ultimately recovered.

     The  standardized   measure  of  discounted  future  net  cash  flows  from
production of proved  reserves was developed by first  estimating the quantities
of proved  reserves and the future  periods during which they are expected to be
produced based on year end economic conditions.  The estimated future cash flows
from proved  reserves were then determined  based on year end prices,  except in
those  instances  where fixed  contracts  provide for a higher or lower  amount.
Estimates of future cash

                                      F-25


<PAGE>



flows  applicable  to oil and gas  commodity  hedges  have been  prepared by the
Company and are  reflected in future cash flows from proved  reserves  with such
estimates  based on  prices  in  effect  as of the date of the  reserve  report.
Additionally,  future cash flows were  reduced by  estimated  production  costs,
costs to develop and produce the proved reserves, and when significant,  certain
abandonment  costs, all based on year end economic  conditions.  Future net cash
flows have been discounted by 10 percent in accordance with SEC guidelines.

     The  standardized  measure  of  discounted  future  net cash flows does not
purport,  nor  should  it be  interpreted,  to  present  the  fair  value of the
Company's oil and gas  reserves.  An estimate of fair value would also take into
account,  among other things, the recovery of reserves not presently  classified
as proved,  anticipated future changes in prices and costs and a discount factor
more representative of the time value of money and the risks inherent in reserve
estimates.

     Under SEC rules,  companies that follow  full-cost  accounting  methods are
required to make quarterly "ceiling test" calculations.  Under this test, proved
oil and gas property costs may not exceed the present value of estimated  future
net revenues from proved  reserves,  discounted  at 10 percent,  as adjusted for
related tax effects and deferred tax reserves. Application of these rules during
periods of relatively  low oil and gas prices,  even if of short-term  duration,
may result in write-downs.

                                      F-26


<PAGE>



            Standardized Measure of Discounted Future Net Cash Flows

                     Relating to Proved Oil and Gas Reserves

                                 (In thousands)
<TABLE>
<CAPTION>

                                                        December 31,
                                            ------------------------------------
                                               1999         1998        1997
                                            ----------    --------   ----------
<S>                                         <C>          <C>         <C>
Future cash inflows(1)......................1,945,175    $1,215,691  $1,569,976
Future production costs..................... (588,932)     (405,171)   (531,583)
Future development costs.................... (110,091)      (99,342)   (100,427)
                                            ----------     --------   ----------
Future net inflows before income taxes(1)...1,246,152       711,178     937,966
Discount at 10% annual rate................. (619,610)     (350,562)   (427,562)
                                            ----------    ---------    ---------
Discounted future net cash flows before
  income taxes..............................  626,542       360,616     510,404
Pro forma discounted future income taxes(2). (161,213)       (7,457)    (84,196)
                                            ----------    ---------     --------
Standardized measure of discounted future
   net cash flows........................... $465,329      $353,159    $426,208
                                             ========      ========    ========
</TABLE>
----------

(1)  Oil and gas commodity hedges included in future cash inflows totaled $(8.6)
     million,  $4.6 million and $5.9 million at December  31,  1999,  1998,  and
     1997, respectively,  and such hedges included in discounted future net cash
     flows before income taxes  totaled  $(8.2)  million,  $4.3 million and $5.5
     million at December 31, 1999, 1998 and 1997, respectively.

(2)  The estimated  undiscounted  future  income taxes related to future net
     inflows were $354.5,  $32.6 and $146.4  million for the years 1999,  1998
     and 1997, respectively.

       Changes in Standardized Measure of Discounted Future Net Cash Flows

                                 (In thousands)
<TABLE>
<CAPTION>

                                                  1999         1998        1997
                                                --------     --------    --------
<S>                                             <C>         <C>        <C>
Balance, beginning of year......................$353,159    $426,208   $280,573
Sales and transfers of oil and gas produced,
  net of production costs.......................(100,075)    (83,353)  (111,819)
Net change in sales price and production costs.. 239,549    (142,014)  (216,169)
Extensions and discoveries......................  65,424      29,730     65,741
Purchases of minerals in place..................  21,346      66,409    312,148
Sale of reserves in place.......................    (112)     (1,401)        --
Changes in estimated future development costs...  33,925      21,382     32,222
Revisions in quantities.........................  (8,841)    (39,163)    (9,099)
Accretion of discount...........................  36,062      51,040     41,553
Other, principally revisions in estimates of
   timing of production......................... (21,352)    (53,923)   (22,267)
Change in income taxes..........................(153,756)     78,244     53,325
                                                ---------   --------  ---------
Balance, End of year............................$465,329    $353,159   $426,208
                                                ========    ========   ========
</TABLE>

                                      F-27


<PAGE>


                          Reserve Quantity Information

                                 Proved Reserves

<TABLE>
<CAPTION>

                                                            Oil           Gas
                                                          -------       -------
                                                          (MBbls)       (MMcf)

<S>                                                       <C>           <C>
Balance at December 31, 1996...........................     3,327       284,992
                                                          -------       -------
  Purchases of minerals in place.......................    45,646        44,855
  Extensions, discoveries and other additions..........     2,004        39,248
  Revisions of previous estimates......................     1,478       (22,200)
  Production...........................................    (1,295)      (49,710)
                                                          -------      --------
Balance at December 31, 1997...........................    51,160       297,185
                                                           ------       -------
  Purchases of minerals in place.......................     9,800        25,903
  Extensions, discoveries and other additions..........       249        34,279
  Revisions of previous estimates .....................    (3,775)      (33,977)
  Sales of minerals in place...........................      (203)         (649)
  Production...........................................    (4,177)      (37,208)
                                                           -------      --------
Balance at December 31, 1998...........................    53,054       285,533
                                                           ------       -------
  Purchases of minerals in place.......................     1,066        20,982
  Extensions, discoveries and other additions..........     3,342        57,881
  Revisions of previous estimates......................      (947)       (2,322)
  Sales of minerals in place...........................         -          (189)
  Production...........................................    (3,439)      (39,737)
                                                           -------      --------
Balance at December 31, 1999...........................    53,076       322,148
                                                           ======       =======
Proved Developed Reserves
December 31, 1996......................................     2,070       184,904
December 31, 1997......................................    41,255       226,071
December 31, 1998......................................    41,475       213,449
December 31, 1999......................................    42,352       224,143

</TABLE>


                                      F-28


<PAGE>

NOTE 15 -- SUBSEQUENT EVENTS (Unaudited)

     In February 2000, the Company closed a $40.5 million acquisition of oil and
gas properties expected to add approximately 2,400 BOE per day to the existing
production base.  The transaction was financed through additional borrowings
with the Company's Revolving Credit Facility.

     Due to the sustained higher oil prices subsequent to year-end, the Company
expects to incur additional cash settlements costs and non-cash mark-to-market
losses related to its commodity price risk management activities unless prices
at March 31, 2000 decline below levels at December 31, 1999.

<PAGE>

                                  EXHIBIT INDEX

<TABLE>
<CAPTION>

Exhibit
No.                         Description of Exhibit
-------                     ----------------------
<S>  <C>
3.1  Articles of Incorporation of Company (Incorporated by reference from
     Exhibit 3.1 of the Registration Statement on Form S-1, Registration No.
     333-1034).
3.2  Amended and Restated Bylaws of Company dated February 5, 1996 (Incorporated
     by reference from Exhibit 3.2(ii) of the Form 10-Q dated March 31, 1996).
4.1  Specimen Common Stock certificate (Incorporated by reference from Exhibit
     4.1 of the Registration Statement on Form S-1, Registration No. 333-1034).
4.2  Indenture  dated as of  September  23,  1997 among the Company,  as issuer,
     and The Bank of New York, as trustee (Incorporated   by   reference   from
     Exhibit 4.1 of Registration  Statement  on  Form  S-4,  Registration  No.
     333-37125).
4.3  Supplemental  Indenture  dated as of February  25, 1998  between  Coda
     Energy, Inc., Diamond Energy Operating Company,  Electra Resources,  Inc.,
     Belco Operating Corp., Belco Energy L.P., Gin Lane Company, Fortune Corp.,
     BOG Wyoming LLC  and  Belco  Finance  Co.  (individually,   the  Subsidiary
     Guarantors),  a subsidiary  of the  Company,  and  The  Bank of New  York,
     a New  York  banking corporation  (as  Trustee)  amending the  Indenture
     filed as Exhibit 4.2 above. (Incorporated  by reference  from Exhibit 4.3
     of the Company's  Annual Report on Form 10-K for the  fiscal  year ended
     December  31,  1997).
4.4  Exchange  and Registration  Rights Agreement dated September 23, 1997 by
     and among the Company and  Chase  Securities Inc., Goldman,  Sachs  &  Co.
     and  Smith  Barney  Inc. (Incorporated  by reference from Exhibit 4.2 of
     Registration  Statement on Form S-4,  Registration No.  333-37125).
4.5  Indenture dated as of March 18, 1996 by and among Coda Energy, Inc., as
     issuer, and Taurus Energy Corp., Diamond Energy Operating Company and
     Electra Resources, Inc. (as guarantors), and Chase Bank of Texas,  N.A.,
     (formerly known as Texas Commerce Bank National Association,  as trustee
     (Incorporated  by reference  from Exhibit 4.1 of the Coda Energy,  Inc.
     Registration  Statement  on Form S-4  filed  April  9,  1996,  Registration
     No. 333-2375).
4.6  First Supplemental Indenture dated as of April 25, 1996 amending the Inden-
     ture filed as Exhibit 4.5 above (Incorporated by reference from Exhibit
     4.12 of the Coda Energy,  Inc.  Quarterly  Report on Form 10-Q for the
     quarterly period ended June 30, 1996, Commission File No. 0-10955).
4.7  Second Supplemental Indenture dated as of February 25, 1998 by and among
     the  Company  and  Chase  Bank of Texas,  N.A.  (formerly  known as Texas
     Commerce Bank National Association), as trustee, amending the Indenture
     filed as Exhibit 4.5 above.  (Incorporated by reference from Exhibit 4.7 of
     the Company's Annual Report on Form 10-K for the fiscal year ended December
     31, 1997).
4.8  Third Supplemental Indenture dated as of February 25, 1998 by and between
     the Company, the Belco subsidiaries who are making a Subsidiary Guarantee
     (the Guarantors) and Chase Bank of Texas, N.A., formerly known as Texas
     Commerce Bank National Association (the Trustee).  (Incorporated by refer-
     ence from Exhibit 4.8 of the Company's  Annual Report on Form 10-K for the
     fiscal year ended  December 31, 1997).
4.9  Certificate of Designations of 6-1/2% Convertible Preferred Stock
     dated  March 5, 1997  (Incorporated  by  reference  from  Exhibit 4.1 of
     current report on Form 8-K dated March 11,  1998).
10.1 1996 Non-Employee Directors' Stock Option Plan (Incorporated  by  reference
     from Exhibit 10.1 of the Registration Statement on Form S-1, Registration
     No. 333-1034).
10.2 1996 Stock Incentive Plan  (Incorporated by reference from Exhibit 10.2 of
     the Registration Statement on Form S-1,  Registration  No.  333-1034).
10.3 Exchange  and Subscription Agreement and Plan of Reorganization dated as of
     January 1, 1996 by and among the  Company,  its  Predecessors  and certain
     individuals  and trusts (Incorporated by reference to Exhibit 10.3 of the
     Registration Statement on Form S-1,  Registration No. 333-1034).
10.4 Form of Registration  Rights Agreement entered  into by parties to Exchange
     Agreement (Incorporated by reference to Exhibit 10.4 of the Registration
     Statement  on  Form  S-1,  Registration  No. 333-1034).
</TABLE>

                                       38

<PAGE>
<TABLE>
<CAPTION>
<S>   <C>
10.5  Supplemental Agreement dated as of January 1, 1996 by and between the
      Company,  Belco Oil & Gas Corp., a Delaware corporation,  Robert A. Belfer
      and certain  officers of the Company  (Incorporated  by  reference  to
      Exhibit 10.5 of the  Registration  Statement  on  Form  S-1,  Registration
      No. 333-1034).
10.6  Form of Indemnification Agreement by and between the Company and its offi-
      cers and directors (Incorporated by reference to Exhibit 10.6 of the
      Registration Statement on Form S-1, Registration No. 333-1034).
10.7  Amended and Restated Well Participation  Letter Agreement dated as of Dec-
      ember 31, 1992 between Chesapeake Operating, Inc. and Belco Oil & Gas
      Corp., as amended by (i) Letter  Agreement  dated April 14, 1983, (ii)
      Amendment dated December 31, 1993, and (iii) Third Amendment dated Decem-
      ber 30, 1994 (Incorporated by reference to Exhibit 10.7 of the Registra-
      tion Statement  on  Form  S-1,  Registration  No. 333-1034).
10.8  Sale Agreement  (Independence)  dated as of June  10,  1994 between Chesa-
      peake  Operating,  Inc. and Belco Oil & Gas Corp.  (Incorporated by
      reference  to  Exhibit  10.10  of  the  Registration   Statement  on  Form
      S-1, Registration No. 333-1034).
10.9  Sale and Area of Mutual Interest  Agreement (Greater Giddings) dated as of
      December 30, 1994 between  Chesapeake  Operating, Inc. and Belco Oil & Gas
      Corp.  (Incorporated  by reference to Exhibit  10.12 of the  Registration
      Statement on Form S-1,  Registration No.  333-1034).
10.10 Golden Trend Area of Mutual  Interest  Agreement  dated as of December 17,
      1992 between Chesapeake Operating, Inc. and Belco Oil & Gas Corp.  (Incor-
      porated by reference to  Exhibit  10.13  of  the  Registration   Statement
      on  Form  S-1, Registration No.  333-1034).
10.11 Form of Participation  Agreement for Belco Oil & Gas Corp. 1992 Moxa Arch
      Drilling  Program  (Incorporated  by reference to Exhibit  10.15 of the
      Registration  Statement  on Form  S-1,  Registration  No. 333-1034).
10.12 Form of Offset Participation Agreement to the Moxa Arch 1992 Offset Drill-
      ing  Program  (Incorporated  by reference  to Exhibit  10.16 of the Regis-
      tration Statement on Form S-1, Registration No. 333-1034).
10.13 Form of Participation Agreement for  Belco Oil & Gas  Corp. 1993 Moxa Arch
      Drilling Program (Incorporated  by  reference  to  Exhibit  10.17  of  the
      Registration Statement on Form S-1,  Registration  No.  333-1034).
10.14 Credit  Agreement dated  as of  September  23,  1997  by and  among  Belco
      Oil & Gas Corp.  (the "Borrower"), and The Chase Manhattan Bank, as admin-
      istrative agent, and certain financial institutions named therein as Lend-
      ers (the "Lenders")(Incorporated by reference to Exhibit 10.1 of Registra-
      tion  Statement on Form S-4,  Registration No.  333-37125).
10.15 First Amendment and Waiver, dated as of November 25, 1997 to (i) Credit
      Agreement dated as of September 23, 1997 among the Borrower, the Lenders
      and The Chase Manhattan Bank, as administrative  agent and (ii) the Pledge
      Agreement,  dated as of September 23, 1997 made by the Borrower and other
      Pledgers (as defined in the Credit  Agreement) in favor of the Administra-
      tive Agent for the ratable  benefit of  Lenders.  (Incorporated  by refer-
      ence  from Exhibit  99.4 to the  Company's  Current  Report  on Form  8-K
      filed  with  the Commission on November 26, 1997).
10.16 Second Amendment and Consent, dated as of February 25, 1998, to the Credit
      Agreement,  dated as of September  23, 1997,  among  the  Borrower,  the
      Lenders  and The  Chase  Manhattan  Bank,  as administrative  agent.
      (Incorporated  by reference  from  Exhibit  10.16 of the Company's  Annual
      Report on Form 10-K for the fiscal  year ended  December  31, 1997).
10.17 Third  Amendment,  dated as of May 29,  1998,  to the  Credit Agreement,
      dated as of September 23, 1997, as amended by the First Amendment and
      Waiver thereto,  dated as of November 25, 1997,  and the Second  Amendment
      and Consent thereto, dated as of February 25, 1998, by and among the Bor-
      rower,  the Lenders and The Chase Manhattan Bank, as administrative agent.
      (Incorporated by reference from Exhibit 10.17 of the Company's Annual
      Report on Form 10-K for the fiscal year ended  December  31,  1998).
10.18 Fourth  Amendment, dated as of December 21, 1998, to the Credit Agreement,
      dated as of September 23, 1997, as amended by the First  Amendment  and
      Waiver  thereto,  dated as of November  25, 1997,
</TABLE>

                                       39

<PAGE>
<TABLE>
<CAPTION>
<S>   <C>
      and the Second Amendment and Consent thereto,  dated as of February 25,
      1998, and the Third Amendment,  dated as of May 29, 1998, by and among the
      Borrower,  the Lenders and The Chase  Manhattan Bank, as  administrative
      agent.  (Incorporated  by reference from Exhibit 10.18 of the Company's
      Annual Report on Form 10-K for the fiscal year ended December 31, 1998).
10.19 Executive Employment  Agreement  with Grant W. Henderson  (Incorporated by
      reference from Exhibit 99.7 of the Coda Energy,  Inc.  Current Report on
      Form 8-K dated October 30, 1995,  Commission File No. 0-10955).
10.20 First Amendment to Belco Oil & Gas Corp. 1996 Nonemployee Directors' Stock
      Option Plan.  (Incorporated by reference from Exhibit 10.1 of the Com-
      pany's Quarterly Report on Form 10-Q for the quarter ended June 30, 1999,
      Commission File No. 1-14256).
*21.1 Subsidiaries of the  Registrant.
*23.1 Consent of Arthur Andersen  LLP.
*23.2 Consent of Miller  and Lents,  Ltd.
*27  Financial  Data Schedule.
</TABLE>
----------

* Filed herewith


                                       40