<PAGE>

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                      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 Year Ended December 31, 2000

                                      or

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

                 For the Transition Period from       to

                          Commission File No. 1-13446

                         BARRETT RESOURCES CORPORATION
            (Exact name of registrant as specified in its charter)

<TABLE>
<S>                                         <C>
                 Delaware                                   84-0832476
      (State or other jurisdiction of                    (I.R.S. Employer
      incorporation or organization)                    Identification No.)
</TABLE>

<TABLE>
<S>                                         <C>
           1515 Arapahoe Street,
            Tower 3, Suite 1000
             Denver, Colorado                                  80202
 (Address of principal executive offices)                   (Zip Code)
</TABLE>

                                (303) 572-3900
             (Registrant's telephone number, including area code)

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

<TABLE>
<CAPTION>
            Title of Each Class                Name of Exchange on which registered:
            -------------------                -------------------------------------
<S>                                         <C>
  Common Stock ($.01 Par Value Per Share)          New York Stock Exchange, Inc.
      Preferred Stock Purchase Rights
</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 there are no delinquent filers to disclose herein
pursuant to Item 405 of Regulation S-K, and there will not be any delinquent
filers to disclose, 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. [X]

   As of March 15, 2001, the Registrant had 33,461,004 common shares
outstanding, and the aggregate market value of the common shares held by non-
affiliates was approximately $1,962,981,137. This calculation is based upon
the closing sale price of $ 61.76 per share for the stock on March 15, 2001.
Without asserting that any director or executive officer of the issuer is an
affiliate, the shares of which they are the beneficial owners have been deemed
to be owned by affiliates solely for this calculation.

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<PAGE>

                               TABLE OF CONTENTS

<TABLE>
<CAPTION>
   Item                                                                   Page
   ----                                                                   ----

                                     PART I

 <C>      <S>                                                             <C>
 1 and 2. Business and Properties.......................................    1
 3.       Legal Proceedings.............................................   15
 4.       Submission of Matters to Vote of Security Holders.............   16

                                    PART II

 5.       Market for the Company's Common Stock and Related Security
          Holders Matters...............................................   17
 6.       Selected Financial Data.......................................   17
 7.       Management's Discussion and Analysis of Financial Condition
          and Results of Operations.....................................   17
 7A.      Quantitative and Qualitative Disclosures About Market Risk....   22
 8.       Financial Statements and Supplementary Data...................   24
 9.       Changes in and Disagreements with Accountants on Accounting
          and Financial Disclosure......................................   24

                                    PART III

 10.      Directors and Executive Officers of the Company...............   25
 11.      Executive Compensation........................................   28
 12.      Security Ownership of Certain Beneficial Owners and
          Management....................................................   32
 13.      Certain Relationships and Related Transactions................   33

                                    PART IV

 14.      Exhibits, Financial Statement Schedules, and Reports on Form
          8-K...........................................................   34
</TABLE>
<PAGE>

                                    PART I

Items 1. and 2. Business and Properties

General

   Barrett Resources Corporation ("Barrett") is an independent gas and oil
exploration and production company. Unless the context otherwise requires, the
terms "Barrett" or "Company" refer to Barrett and its subsidiaries.

   The Company's corporate offices are located at 1515 Arapahoe Street, Tower
3, Suite 1000, Denver, Colorado 80202, where the telephone number is (303)
572-3900.

   On March 12, 2001, Shell Oil Company, acting through its indirect wholly-
owned subsidiary SRM Acquisition Company ("Sub"), commenced an unsolicited
tender offer (the "Shell Offer") in which it offered to purchase all the
outstanding shares of the Company for $55.00 per share, subject to certain
conditions. On March 22, 2001, the Company announced that the Company's Board
of Directors had voted unanimously to recommend that the Company's
stockholders reject the Shell Offer as inadequate and not in the best
interests of the Company's stockholders. The full text of the Board's
recommendation is contained in the Company's Schedule 14D-9 filed with the
Securities and Exchange Commission. In connection with the Shell Offer, Shell
filed a preliminary consent statement and other solicitation materials in
which it indicated its intent to solicit written consents of Barrett's
stockholders to remove the current directors of Barrett and replace them with
Shell's nominees (the "Shell Consent Solicitation"). The Company has filed
preliminary consent revocation solicitation materials in which the Company
indicates it will solicit the revocation of any consents granted to Shell.
Copies of these filings with the SEC may be viewed on the SEC's web site at
www.sec.gov. A description of litigation filed against the Company and its
directors that is related to the Shell Offer is described below under "Item 3.
Legal Proceedings--Litigation Concerning Shell Oil Company Offer."

Oil and Gas Exploration and Development

   Barrett's core areas of activity are in the Rocky Mountain Region of
Colorado, Wyoming and Utah and the Mid-Continent Region of Kansas and
Oklahoma. At December 31, 2000, the Company's estimated proved reserves were
1,372 Bcfe (96% natural gas and 4% crude oil) with an implied reserve life of
11.6 years based on 2000 total production of 117.6 Bcfe. The Company's net
daily production averaged 321 MMcfe for the year ended December 31, 2000.

   The Company concentrates its activities in core areas in which it has
accumulated detailed geologic knowledge and developed significant technical
expertise. The Company continues to build on its interests in the Piceance
Basin in northwestern Colorado, the Wind River Basin in central Wyoming, the
Powder River Basin of northeastern Wyoming. and the Unita Basin of northern
Utah. In October 2000, the Company acquired a new coal bed methane property in
the Raton Basin of south central Colorado. The Company also has significant
interests in the Hugoton Embayment in southwestern Kansas, the Niobrara play
in northeastern Colorado, and the Anadarko Basin in Oklahoma. At December 31,
2000, these principal areas represented approximately 97% of the Company's
estimated proved reserves.

   As of December 31, 2000, the Company owned an interest in 4,284 wells, of
which 3,441 were producing. Of these producing wells, 2,680 were operated by
the Company. These operated wells contributed approximately 91% of the
Company's natural gas and oil production for the year ended December 31, 2000.
The Company also owns and operates a natural gas gathering system, a 27-mile
pipeline and a natural gas processing plant in the Piceance Basin.

   Barrett markets all of its own natural gas and oil production from wells
that it operates. In addition, the Company engages in natural gas trading
activities, which involve purchasing natural gas from third parties and
selling natural gas to other parties at prices and volumes that management
anticipates will result in profits to the Company. See "Natural Gas and Oil
Marketing and Trading."

                                       1
<PAGE>

Employees

   As of December 31, 2000, the Company employed 231 persons. The Company's
employees are not represented by any union. Relations between the Company and
its employees are considered to be satisfactory. The Company has had no work
stoppages or strikes.

Core Areas of Activity

   The following table sets forth reserves and production concerning the
Company's core areas of activity:

<TABLE>
<CAPTION>
                                                               Average Daily
                         Estimated Proved  Estimated Proved   Production for
                            Reserves at       Reserves at       Year Ended
     Basin or Field      December 31, 1999 December 31, 2000 December 31, 2000
     --------------      ----------------- ----------------- -----------------
                              (Bcfe)             (Bcfe)           (MMcfe)
<S>                      <C>               <C>               <C>
Rocky Mountain Region
  Wind River............        126.3              76.5             56.4
  Piceance..............        461.1             613.4            102.9
  Powder River--Oil.....         17.7              18.2             12.8
  Powder River--CBM.....        231.0             344.6             67.9
  Raton Basin...........          --               77.0              1.0
  Green River...........         11.9              11.5              2.7
  Uinta.................         41.0              46.4              3.3
  Niobrara..............         25.4              24.8              6.0
Mid-Continent Region
  Anadarko..............         17.0              14.1             16.9
  Hugoton Embayment.....        142.3             131.4             31.5
Gulf of Mexico Region...         23.5              13.8             16.6
Other Natural Gas and
 Oil Activities (1).....         36.6                .2              3.1
                              -------           -------            -----
Total...................      1,133.8           1,371.9            321.1
                              =======           =======            =====
</TABLE>
--------
(1) The reserves as of December 31, 1999 included 11.9 Bcfe located in the
    Permian Basin of west Texas and southeast New Mexico, 19.7 Bcfe located in
    the Arkoma Basin of Oklahoma, and 4.9 Bcfe located in the Meeteetse Field
    in northwest Wyoming. The Company sold its Permian Basin reserves,
    effective February 1, 2000, for $16.3 million, and sold its Arkoma Basin
    reserves for $25 million, effective April 1, 2000. The Meeteetse Field
    reserves were sold for $1.8 million, effective June 1, 2000.

Rocky Mountain Region

   Piceance Basin. The Piceance Basin is located in northwestern Colorado. The
Company's operations in the basin are focused on the Parachute, Rulison and
Grand Valley Fields. The primary geologic target is the lenticular sandstone
of the Williams Fork Formation of the Mesaverde Group.

   As of December 31, 2000, the Company owned interests in 530 Piceance Basin
wells, 504 of which it operates. Ninety-one of these wells were drilled during
2000. Its Piceance Basin properties represented 45% of the Company's year-end
2000 reserves. Thirty-two percent of the Company's 2000 production was from
the Piceance Basin. Net production at year-end was 103 Mmcfd.

   In January 2000, Barrett purchased the remaining six percent working
interest in the Company operated wells in the Basin and the remaining interest
in the Grand Valley Gathering System for approximately $34.4 million. In
addition, in October 2000, the Colorado Oil and Gas Conservation Commission
(the "COGCC") granted the Company's application for 20-acre well density on
approximately 9,000 acres in the basin. On March 5, 2001, the Company filed a
new application with the COGCC requesting approval for 20-acre well density on
an additional 16,000 acres of Federal land.

                                       2
<PAGE>

   The Company has developed a new Piceance Basin exploratory prospect to
target the Mesaverde formation northeast of the Rulison Field. Approximately
26,000 acres have been accumulated for this prospect and the Company has sold
a 40 percent working interest to another exploration and production company.
During the second quarter of 2001, two exploratory wells, the No. 1 Halandras
(total depth 12,500 feet) and No. 1 Woodward (total depth 10,200 feet), are
intended to be drilled on this prospect.

   Approximately 46 percent of the Company's 2001 capital budget will be
devoted to drilling 115 wells in the Piceance Basin. In addition to the two
exploratory wells noted above, the Company is planning to drill one well to
the Mancos Formation, one horizontal well in the Corcoran Formation and over
100 Williams Fork wells. The Company will employ a fifth rig for the drilling
of Williams Fork wells beginning in the first half of 2001. In addition, the
Company is planning a 40 square mile 3-D seismic program to enhance the
evaluation of the Williams Fork and Cozzette/Corcoran Formations.

   Grand Valley Gathering System. The Grand Valley Gathering System ("System")
consists of a gathering system, a 27-mile pipeline and a gas processing plant.
As of December 31, 2000, the System was connected to 425 producing wells. The
System has the flexibility to deliver natural gas to four interstate pipelines
as well as Public Service Company of Colorado's ("PSCo") western Colorado
distribution system. Subject to the take-away capacity of the four interstate
pipelines and the PSCo line, this System is capable of delivering over 150
MMcf of gas per day.

   Powder River Basin. In the Powder River Basin of northeastern Wyoming, the
Company is active in a coal bed methane exploration and development program
and continues to produce oil from a Minnelusa sandstone play.

   Coal Bed Methane. In October 1997, the Company entered into a joint
development agreement to participate, with a 50% working interest, in a coal
bed methane ("CBM") project covering a 2.1 million acre area of mutual
interest ("AMI") located north and south of Gillette, Wyoming. In 2000, the
Company increased its coal bed methane leasehold position to over 1,051,000
gross acres (468,000 net). The coal seams lie 300 to 2,000 feet below the
surface, making drilling and completion of the wells relatively inexpensive.
In 2000, the Company participated in the drilling of 978 wells in the Wyodak
Development fairway and 100 wells in the Big George Exploratory fairway. Of
this total, 260 were producing and 818 wells were waiting on pipeline
connection at year-end. A total of 1,444 coal bed methane wells were producing
at year-end 2000. Additionally, the Company has a 10% working interest in the
90-mile Fort Union Gas Gathering System that was completed in September 1999.

   The Bureau of Land Management ("BLM") required an Environmental Impact
Study ("EIS") prior to approving additional drilling on Federal leases in the
Powder River Basin. Approximately half of the Company's acreage in the Powder
River Basin is on Federal leases. The Record of Decision ("ROD") for the
Wyodak EIS was issued in November 1999. Due to a greater than expected
development on fee and State lands, industry development on Federal lands was
limited to approximately 890 additional wells. A new basin-wide EIS is in
progress and is expected to be completed by the first half of 2002. In the
case where Federal acreage is being drained from adjoining fee as provided by
EIS and State locations, the BLM is permitting the drilling of additional
"drainage protection wells" on Federal lands. An Environmental Assessment
covering "drainage protection wells" was approved on March 19, 2001. It is
anticipated that this Environmental Assessment will allow industry to drill
additional "drainage protection wells."

   At December 31, 2000, the Powder River Basin CBM play represented 25% of
the Company's proved reserves and 21% of the Company's total 2000 production.
The Company currently intends to spend 14% of its 2001 capital expenditure
budget in the CBM project by participating in approximately 920 wells,
including 188 "drainage protection wells" which are expected to be permitted
as a result of the March 19 approval of the Environmental Assessment.


                                       3
<PAGE>

   Conventional Oil and Gas. As of December 31, 2000, the Powder River Basin
Minnelusa sandstone conventional oil operations represented 1% of the
Company's proved reserves, and 4% of the Company's total 2000 production.
Minnelusa production contributed approximately 39% of the Company's 2000 daily
oil production

   Wind River Basin. In 1994, following its major natural gas discovery in the
Cave Gulch Field, the Company began a focused exploration and development
program in the Wind River Basin of central Wyoming, particularly along the Owl
Creek Thrust fault. The Company has continued to acquire additional acreage in
this core area and currently owns working interests ranging from 25% to 100%
in 12,650 gross (9,617 net) leasehold acres in the Cave Gulch area, including
a 94% working interest in the Cave Gulch Federal Unit covering the Fort Union
and Lance Sandstones.

   The Company's seventh Cave Gulch area deep test well, the Cave Gulch No. 4-
19, reached total depth of 18,750 feet in May 2000. The Company moved uphole
to the First, Third, and Fifth Frontier Formations and fracture stimulated
those zones in mid-February 2001. These formations tested wet and, therefore,
were not commercial. The Company currently holds over 7,600 net acres in this
area, and owns an 81% working interest in this well.

   Owl Creek Thrust. The Company is presently evaluating a 123 square mile 3-D
seismic survey on the East Madden prospect. This survey targets the Lance and
Mesa Verde formations at a depth range of 9,000 to 17,500 feet. The Company
has also entered into an agreement with another third party to acquire, at the
third party's sole cost, a 120 square mile 3-D seismic survey covering the
Boone Dome Prospect in exchange for certain leasehold interests along the Owl
Creek Thrust. The Company retained a 33.3% working interest in the Boone Dome
Prospect. The 3-D seismic data is presently being acquired.

   At December 31, 2000, the Wind River Basin represented 5.6% of the
Company's estimated proven reserves and 17.6% of the Company's total 2000
production. The Company intends to spend 4% of its 2001 capital expenditure
budget in the Wind River Basin for development, leasehold acquisition, seismic
surveys and exploration. The Company plans to recomplete at least five deep
Frontier-Muddy-Lakota wells and two Lance wells. Along the Owl Creek Thrust
the Company plans to drill at least two exploratory tests, targeting the Lance
and Mesaverde Sands.

   Raton Basin. Effective October 1, 2000, Barrett acquired a new coal bed
methane property in the Raton Basin of southern Colorado for $52.9 million.
This property represents a new core area for the Company and is expected to
yield significant production and reserve growth during the next 3 to 5 years.
The properties include 54,600 net acres of lease and mineral interests, 77 Bcf
of proved reserves (79% proved undeveloped), 58 producing coal bed methane
wells and a gas gathering/compression system. Current gross gas sales from the
properties are approximately 8,000 mcfd.

   A continuous drilling program began in mid-November. This drilling targets
the Vermejo and Raton formation coals. Ten new wells were drilled in late
2000. Additional activities included the expansion of the low-pressure
gathering system to accommodate the anticipated future increased gas volumes.

   During 2001, the Company plans to spend 14% of its capital expenditure
budget to drill over 140 new wells in the Raton Basin.

   Hanna Basin. During 2000, the Company drilled seven coal bed methane wells
(51% working interest) to evaluate the 42,000 acres it had assembled in the
Hanna Basin, which is located just east of the Greater Green River Basin in
Carbon County, Wyoming. These wells targeted the Hanna Formation (Ft.Union-age
equivalent), which contains over 130 net feet of coal in three separate coal
seams at depths ranging from 1,000 feet to 4,500 feet. A six-well pilot area
was drilled to begin the dewatering process of the lowermost coalbed, the
Hanna #2 coal bed. A seventh well was drilled as a stepout to evaluate the
potential of a second pilot area. After being completed without fracture
stimulations, the six pilot wells are pumping 650 barrels of water per day and
producing traces of gas after approximately 70 days. The target coal seams
contain higher gas contents than the Powder River coal beds. In addition to
the three deeper target coal seams, shallower coal seams containing over 50
feet of net coal are also present under selected areas of the acreage block.

                                       4
<PAGE>

   During 2001, the Company anticipates drilling 18 additional wells. Of
these, 11 wells are intended to expand the current pilot with 80-acre well
density, five wells are to begin a second pilot, and two wells are to further
investigate the extent of the target coal seams. The Company intends to spend
1% of its 2001 capital budget in the Hanna Basin for drilling these 18 wells.

   Green River Basin. The Green River Basin is located in southwest Wyoming.
Barrett has begun production testing on a five well coal bed methane pilot,
the Rock Ridge Prospect. Four wells are currently completed in coals near the
middle of the Rock Springs Formation, and fifth pilot has been completed in a
five-spot pattern around a pre-existing test well. Each of the five wells is
testing approximately 20 feet of net coal within a gross 120 to 150 foot
interval at 3,900 to 4,000 feet. The Rock Springs Formation contains 100 feet
of coal within the pilot area. In 2001, Barrett intends to spend 2% of its
capital expenditure budget drilling approximately 12 wells within this project
area.

   Uinta Basin--Brundage Canyon Field. Brundage Canyon field is located in
Duchesne County, Utah on the southwestern side of the Uinta Basin in the
northeastern part of the state. The multiple sandstone and carbonate
reservoirs in this field are part of the lower Green River Formation and
currently produce oil and associated natural gas from depths ranging from
3,500 to 6,100 feet.

   The Company has completed the necessary regulatory filings for its 640-acre
Douglas Creek pilot waterflood project. Water source wells have been drilled
and injection into four Douglas Creek wells will begin during 2001. Secondary
recovery from the Douglas Creek reservoirs is anticipated to recover an
additional 15% of the oil in place.

   On December 31, 2000, the Brundage Canyon Field represented 3% of the
Company's estimated proved reserves, and 1% of the Company's total 2000
production. The Company intends to spend 16% of its 2001 capital budget on
Brundage Canyon field development, including the drilling of more than 40
wells and the construction of related facilities and infrastructure.

   Northeastern Colorado--Niobrara. This is a shallow natural gas play
targeting a 20 to 50 foot thick chalk reservoir in the Upper Cretaceous
Niobrara Formation. During 2000, the Company acquired 31 miles of proprietary
seismic data. The Company drilled three Niobrara wells during 2000, none of
which were successful.

   At December 31, 2000, the Niobrara represented 2% of the Company's
estimated proved reserves, and 2% of the Company's total 2000 production. The
Company intends to spend 2% of its 2001 capital budget in the play for the
drilling of more than 20 wells and to acquire additional leases and seismic
data.

Mid-Continent Region

   Hugoton Embayment. The Hugoton Embayment is located in southwestern Kansas,
the Oklahoma panhandle and the Texas panhandle. The Company produces natural
gas from two fields in the Hugoton Embayment: the Hugoton and Panoma Fields.

   Hugoton Field. In the Hugoton Field, the Company has a working interest in
342 gross wells. It operates 293 of these wells, which produce from the Chase
Formation. One well was drilled and placed on production during 2000.

   Panoma Field. Panoma is the field designation for natural gas produced from
the Council Grove Formation, located beneath the Chase Formation. The Council
Grove Formation has similar reservoir rocks as the Chase Formation, however,
the productive limits are not as extensive. Presently, the Company has a
working interest in 55 gross Panoma wells and operates 51 of those wells.

   At December 31, 2000, the Hugoton Embayment represented 10% of the
Company's estimated proved reserves and 10% of the Company's total 2000
production. The Company intends to spend 1% of its 2001 capital expenditure
budget in the Hugoton Embayment.

                                       5
<PAGE>

   Hugoton Gas Trust Agreement. Approximately 50,000 acres in Finney and
Kearny Counties, Kansas, are subject to a payment of $0.06 per Mcf for natural
gas produced from the acreage. Quarterly payments are made by the Company to
the Hugoton Gas Trust, a publicly held trust created in 1955. Payments
terminate when the estimated gross recoverable natural gas reserves decline to
50 Bcf or less. As of December 31, 2000, the gross proved natural gas reserves
attributable to the leases burdened by this agreement were estimated to be 60
Bcf. The Company treats the natural gas payments as lease operating expenses.
At December 31, 2000, the Company had working interests in 196 wells that were
subject to these payments.

   Anadarko Basin. During 2000, the Company participated in drilling six wells
in the Anadarko Basin with working interests ranging from 3% to 50%. All six
of the gas wells drilled were completed as producers.

   At December 31, 2000, the Anadarko Basin represented 1% of the Company's
estimated proved reserves, and 5% of the Company's total 2000 production. The
Company intends to spend less than 1% of its 2001 capital expenditure budget
for the drilling of two wells.

   Arkoma Basin. The Company sold its Arkoma Basin properties for $25 million,
effective April 1, 2000. At December 31, 1999, the Arkoma Basin represented 2%
of the Company's estimated proved reserves and 4% of the Company's total 1999
production.

   Permian Basin. Effective February 1, 2000, the Company sold its Permian
Basin properties for $16.3 million. At December 31, 1999, the Permian Basin
represented 1% of the Company's estimated proved reserves, and 3% of the
Company's total 1999 production.

Gulf of Mexico Region

   During 2000, the Company participated in drilling one well and performed
various maintenance operations at a net cost of $342,000.

   At December 31, 2000, the Gulf of Mexico represented 1% of the Company's
estimated proved reserves, and 5% of the Company's total 2000 production. The
Company intends to spend less then 1% of its 2001 capital budget in the Gulf
of Mexico.

International Operations

   In January 1997, the Company entered into an agreement with industry
partners that provided the Company with a 45% working interest in Block 67,
covering two million gross acres in the Maranon Basin of northeastern Peru. In
March 1998, the Company acquired an additional 25% working interest. During
1998, the Company drilled and temporarily abandoned three exploratory wells,
each of which resulted in an oil discovery in Cretaceous and basal Tertiary
Sandstone reservoirs. In May 1999, as required under the license agreement,
Barrett relinquished 30% of the acreage within Block 67, reducing the acreage
within Block 67 to 1.4 million acres. The Company is currently attempting to
sell at least a 60% working interest in Block 67. Barrett must elect during
January 2002 to proceed into the next Exploration Period or relinquish all
acreage within Block 67 except for a five kilometer radius surrounding each of
the discovery fields. If the Company elects to proceed, it must commit to
drilling two exploration wells and one delineation well.

   In September 1999, the Company entered into a contract to acquire Block 39,
a new license area covering approximately 1.0 million acres, located
immediately to the south and east of Block 67. During 2000, an industry
partner agreed to complete the obligations of the second exploration program,
consisting of the acquisition of 350 kilometers of 2-D seismic data, in
exchange for a 60% working interest in the Block. By August 2001, the Company
and its partner must commit to the third exploration program, consisting of
drilling one exploratory well to retain its interest in Block 39.


                                       6
<PAGE>

Certain Definitions

   Unless otherwise indicated in this document, natural gas volumes are stated
at the legal pressure base of the state or area in which the reserves are
located at 60 Fahrenheit. Natural gas equivalents are determined using the
ratio of six Mcf of natural gas to one barrel of crude oil, condensate or
natural gas liquids so that one barrel of oil is referred to as six Mcf of
natural gas equivalent or "Mcfe."

   As used in this document, the following terms have the following specific
meanings: "Mcf" means thousand cubic feet of gas, "Mcfe" means thousand cubic
feet of gas equivalent, "Mcfed" means thousand cubic feet of gas equivalent
per day, "MMcf" means million cubic feet of gas, "MMcfd" means million cubic
feet of gas per day, "MMcfe" means million cubic feet of gas equivalent,
"MMcfed" means million cubic feet of gas equivalent per day, "Bbl" means
barrel of oil, "MBbl" means thousand barrels of oil, "BOPD" means barrels of
oil per day, "MMBtu" means million British thermal units, "Bcf" means billion
cubic feet of gas and "Bcfe" means billion cubic feet of gas equivalent.

   With respect to information concerning the Company's working interests in
wells or drilling locations, "gross" natural gas and oil wells or "gross"
acres is the number of wells or acres in which the Company has an interest,
and "net" gas and oil wells or "net" acres are determined by multiplying
"gross" wells or acres by the Company's working interest in those wells or
acres. A working interest in an oil and natural gas lease is an interest that
gives the owner the right to drill, produce, and conduct operating activities
on the property and to receive a share of production of any hydrocarbons
covered by the lease. A working interest in an oil and gas lease also entitles
its owner to a proportionate interest in any well located on the lands covered
by the lease, subject to all royalties, overriding royalties and other
burdens, to all costs and expenses of exploration, development and operation
of any well located on the lease, and to all risks in connection therewith.

   "Capital expenditures" means costs associated with exploratory and
development drilling (including exploratory dry holes); leasehold
acquisitions; seismic data acquisitions; geological, geophysical and land
related overhead expenditures; delay rentals; producing property acquisitions;
and other miscellaneous capital expenditures. "Capital expenditure budget"
means an estimate prepared by management for the total expenditures
anticipated to be incurred during the subject time period. This amount can
deviate or fluctuate due to the timing of drilling of wells, environmental
considerations, acquisition of important fee, state and federal leases, and
natural gas and oil prices.

   A "development well" is a well drilled as an additional well to the same
horizon or horizons as other producing wells on a prospect, or a well drilled
on a spacing unit adjacent to a spacing unit with an existing well capable of
commercial production and which is intended to extend the proven limits of a
prospect. An "exploratory well" is a well drilled to find commercially
productive hydrocarbons in an unproved area, or to significantly extend a
known prospect.

   "Present value of estimated future net revenues" means the present value of
estimated future revenues to be generated from the production of proved
reserves calculated in accordance with the Securities and Exchange Commission
guidelines, net of estimated production and future development costs, using
prices and costs as of the date of estimation without future escalation,
without giving effect to non-property related expenses such as general and
administrative expenses, debt service, future income tax expense and
depreciation, depletion and amortization, and discounted using an annual
discount rate of 10%.

   A "recompletion" is the completion of an existing well for production from
a formation that exists behind the casing of the well.

   "Reserves" means natural gas and crude oil, condensate and natural gas
liquids on a net revenue interest basis, found to be commercially recoverable.
"Proved developed reserves" includes proved developed producing reserves and
proved developed behind-pipe reserves. "Proved developed producing reserves"
includes only those reserves expected to be recovered from existing completion
intervals in existing wells. "Proved undeveloped reserves" includes those
reserves expected to be recovered from new wells on proved undrilled acreage
or from existing wells where a relatively major expenditure is required for
recompletion.

                                       7
<PAGE>

Production

   The table below sets forth information with respect to the Company's net
interests in producing natural gas and oil properties for each of its last
three years, respectively:

<TABLE>
<CAPTION>
                                                Natural Gas and Oil Production
                                                ------------------------------
                                                   Year Ended December 31,
                                               --------------------------------
                                                  1998       1999       2000
                                               ---------- ---------- ----------
<S>                                            <C>        <C>        <C>
Quantities Produced and Sold
  Natural gas (Bcf)...........................       94.9       95.0      112.4
  Oil and condensate (MMBbls).................        2.0        1.4         .9
Average Sales Price
  Natural gas ($/Mcf)......................... $     1.92 $     2.02 $     3.07
  Oil and condensate ($/Bbl).................. $    11.42 $    12.71 $    26.28
Average Production Costs ($/Mcfe)............. $     0.55 $     0.63 $     0.77
</TABLE>

Productive Wells

   The productive wells in which the Company owned a working interest as of
December 31, 2000 are described in the following table:

<TABLE>
<CAPTION>
                                                         Productive Wells(1)
                                                     ---------------------------
                                                       Gas Wells     Oil Wells
                                                     -------------- ------------
                                                     Gross   Net    Gross  Net
                                                     ----- -------- ----- ------
<S>                                                  <C>   <C>      <C>   <C>
Rocky Mountain Region
  Wind River........................................    52    42.48   18    1.57
  Piceance..........................................   517   489.76    0    0.00
  Raton.............................................    63    63.00    0    0.00
  Niobrara..........................................   143   100.50    0    0.00
  Conventional Powder River.........................    11     3.59  266   64.80
  Powder River-CBM.................................. 1,627   791.02    0    0.00
  Green River.......................................    16     9.17    0    0.00
  Uinta.............................................     2     1.93   49   46.86
Mid-Continent Region:
  Anadarko..........................................   158    35.81    9    1.50
  Hugoton Embayment.................................   420   353.64    1    1.00
Gulf of Mexico Region...............................    67    22.38    6    1.18
Other ..............................................     1      .01   15     .24
                                                     ----- --------  ---  ------
    Total........................................... 3,077 1,913.29  364  117.15
                                                     ----- --------  ---  ------
</TABLE>
--------
(1) Each well completed to more than one producing zone is counted as a single
    well. The Company has royalty interests in certain wells that are not
    included in this table.

                                       8
<PAGE>

Drilling Activity

   The following table summarizes the Company's natural gas and oil drilling
activities during 1998, 1999 and 2000, all of which were located in the United
States, with the exception of 3 gross (2.1 net) exploratory wells drilled in
the Republic of Peru during 1998:

<TABLE>
<CAPTION>
                                                      Wells Drilled
                                          --------------------------------------
                                                 Year Ended December 31,
                                          --------------------------------------
                                              1998         1999         2000
                                          ------------ ------------ ------------
                                          Gross  Net   Gross  Net   Gross  Net
                                          ----- ------ ----- ------ ----- ------
<S>                                       <C>   <C>    <C>   <C>    <C>   <C>
Development
  Natural gas............................  372  191.49  660  351.15 1,115 567.90
  Oil....................................    8     .14    0    0.00    17  12.85
  Non-productive.........................   17    8.58    7    4.26     8   5.30
                                           ---  ------  ---  ------ ----- ------
    Total................................  397  200.21  667  355.41 1,140 586.05
                                           ===  ======  ===  ====== ===== ======
Exploratory
  Natural gas............................   13    8.52   11    8.94    80  40.89
  Oil....................................    8    3.78    0    0.00     0   0.00
  Non-productive.........................    6    3.60    2    0.63     1    .25
                                           ---  ------  ---  ------ ----- ------
    Total................................   27   15.90   13    9.57    81  41.14
                                           ===  ======  ===  ====== ===== ======
</TABLE>

   In addition, the Company was participating in 9 gross (5.88 net) wells,
which were in the process of being drilled, at December 31, 2000.

Reserves

   The table below sets forth the Company's estimated quantities of historical
proved reserves as of the dates indicated, all of which were located in the
United States, and the present values attributable to those reserves. These
estimates were prepared by the Company. Approximately 85% of the Company's
reserve information as of December 31, 2000, approximately 85% of the
Company's reserve information as of December 31, 1999 and all of the Company's
reserve information as of December 31, 1998 were reviewed by independent
reservoir engineers. Ryder Scott Company, L.P., an independent reservoir
engineer, reviewed the Company's Hugoton Embayment, Wind River Basin and
Piceance Basin year-end 1999 and 2000 reserve information and all but the
Company's coal bed methane reserves in Wyoming for year-end 1998. The Powder
River Basin coal bed methane reserves were reviewed by Netherland, Sewell &
Associates, Inc., an independent reservoir engineer, as of December 31, 1998,
1999 and 2000. The total proved net reserves estimated by the Company as of
December 31, 1998, 1999 and 2000 were within 10% of those reviewed and
estimated by the engineers; however, on a well by well basis, differences of
greater than 10% may exist.

                                       9
<PAGE>

<TABLE>
<CAPTION>
                                            Estimated Proved Reserves
                                  ----------------------------------------------
                                                   December 31,
                                  ----------------------------------------------
                                       1998           1999            2000
                                  ------------------------------ ---------------
                                  (dollars in millions, except sales price data)
<S>                               <C>            <C>             <C>
Estimated Proved Reserves
  Natural gas (Bcf).............           912.4         1,075.9         1,323.3
  Oil and condensate (MMBbls)...             9.7             9.7             8.1
    Total (Bcfe)................           970.3         1,133.8         1,372.0
Proved developed reserves
 (Bcfe).........................           580.4           698.1           789.3
Natural gas price as of December
 31 ($/Mcf).....................  $         2.01 $          2.06 $          8.23
Oil price as of December 31
 ($/Bbl)........................  $         9.35 $         22.01 $         22.18
Present value of estimated
 future net revenues before
 future income taxes discounted
 at 10%(1)......................  $        627.8 $         815.0 $         5,248
Standardized measure of
 discounted net cash flows(2)...  $        530.6 $         661.3 $         3,442
</TABLE>
--------
(1) The present value of estimated future net revenues on a non-escalated
    basis is based on the year-end market price.
(2) The standardized measure of discounted net cash flows prepared by the
    Company represents the present value of estimated future net revenues
    after income taxes discounted at 10%.

   In accordance with applicable requirements of the Securities and Exchange
Commission (the "SEC"), estimates of the Company's proved reserves and future
net revenues are made using sales prices estimated to be in effect as of the
date of such reserve estimates and are held constant throughout the life of
the properties (except to the extent a contract specifically provides for
escalation). Estimated quantities of proved reserves and future net revenues
therefrom are affected by natural gas and oil prices, which have fluctuated
widely in recent years. There are numerous uncertainties inherent in
estimating natural gas and oil reserves and their estimated values, including
many factors beyond the control of the producer. The reserve data set forth in
this document represents only estimates. Reservoir engineering is a subjective
process of estimating underground accumulations of natural gas and oil that
cannot be measured in an exact manner. 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 of different engineers,
including those used by the Company, may vary. In addition, estimates of
reserves are subject to revision based upon actual production, results of
future development and exploration activities, prevailing natural gas and oil
prices, operating costs and other factors, which revisions may be material.
Accordingly, reserve estimates are often different from the quantities of
natural gas and oil that are ultimately recovered and are highly dependent
upon the accuracy of the assumptions upon which they are based.

   In general, the volume of production from natural gas and oil properties
owned by the Company declines as reserves are depleted. Except to the extent
the Company acquires additional properties containing proved reserves or
conducts successful exploration and development activities, or both, the
proved reserves of the Company will decline as reserves are produced. Volumes
generated from future activities of the Company are therefore highly dependent
upon the level of success in acquiring or finding additional reserves and the
costs incurred in doing so.

   Reference should be made to "Supplemental Oil and Gas Information" on pages
F-23 through F-25 following the Consolidated Financial Statements included in
this document for additional information pertaining to the Company's proved
natural gas and oil reserves as of the end of each of the last three years.
During the past year, the only report concerning the Company's estimated
proved reserves that was filed with a U.S. federal agency other than the SEC
is the Annual Survey of Domestic Oil and Gas Reserves and was filed with the
Energy Information Administration ("EIA") as required by law. Only minor
differences of less than 5% in reserve estimates, which were due to small
variances in actual production versus year-end estimates, have occurred in
certain classifications reported in this document as compared to those in the
EIA report.

                                      10
<PAGE>

Developed and Undeveloped Acreage

   The gross and net acres of developed and undeveloped natural gas and oil
leases held by the Company as of December 31, 2000 are summarized in the
following table. "Undeveloped Acreage" includes leasehold interests that
already may have been classified as containing proved undeveloped reserves.

<TABLE>
<CAPTION>
                                                Developed    Undeveloped Acreage
                                                 Acreage             (1)
                                             --------------- -------------------
                                              Gross    Net     Gross      Net
                                             ------- ------- --------- ---------
<S>                                          <C>     <C>     <C>       <C>
Rocky Mountain Region
  Wind River................................  16,757  11,175    70,680    40,520
  Piceance..................................  58,591  57,081   128,936   103,400
  Raton.....................................  47,472  47,472     7,200     7,200
  Powder River.............................. 222,243 100,779   860,225   375,950
  Green River...............................  15,915   5,879    40,557    19,863
  Uinta.....................................   2,160   2,095    31,547    29,294
Mid-Continent Region
  Anadarko..................................  81,005  19,015    32,859    13,798
  Hugoton Embayment.........................  89,510  86,013       160       160
Gulf of Mexico Region....................... 142,145  54,406       246       154
International...............................     --      --  2,328,000 2,328,000
Other.......................................  32,197  22,588    82,271    59,465
                                             ------- ------- --------- ---------
    Total................................... 707,995 406,503 3,582,681 2,977,804
                                             ======= ======= ========= =========
</TABLE>
--------
(1) Undeveloped acreage is leased acreage on which wells have not been drilled
    or completed to a point that would permit the production of commercial
    quantities of natural gas and oil regardless of whether such acreage
    contains proved reserves. Of the aggregate 3,582,681 gross and 2,972,804
    net undeveloped acres, 303,802 gross and 122,309 net acres are held by
    production from other leasehold acreage.

   Substantially all the leases summarized in the preceding table will expire
at the end of their respective primary terms unless the existing leases are
renewed or production has been obtained from the acreage subject to the lease
prior to that date, in which event the lease will remain in effect until the
cessation of production. The following table sets forth the gross and net
acres subject to leases summarized in the preceding table that will expire
during the periods indicated:

<TABLE>
<CAPTION>
                                                               Acres Expiring
                                                             -------------------
                                                               Gross      Net
                                                             --------- ---------
<S>                                                          <C>       <C>
Twelve Months Ending:
  December 31, 2001.........................................    63,675    37,041
  December 31, 2002......................................... 1,782,098 1,717,598
  December 31, 2003.........................................   210,072   106,690
  December 31, 2004 and later .............................. 1,095,625   927,078
</TABLE>

Overriding Royalty Interests

   The Company owns overriding royalty interests covering in excess of 155,165
gross acres. The majority of these overriding royalty interests are within a
range of approximately 0.25 to 5.0 percent.

Natural Gas and Oil Marketing and Trading

   The Company markets all of its natural gas and oil production from wells
that it operates. Historically, the Company has actually purchased and sold
natural gas to third parties as a separate profit center. During the last half
of 2000, the Company significantly reduced its gas trading activities.
Following settlement of existing gas purchase and sales commitments in early
2001, the Company's gas trading volumes will be substantially reduced.

                                      11
<PAGE>

   Natural Gas. The Company has entered into a number of gas sales agreements
on behalf of itself and its industry partners for the sale of natural gas from
its properties in each of the Company's basins. These contracts vary with
respect to their specific provisions, including price, quantity, and length of
contract. As of December 31, 2001, less than 4% of the Company's production
was committed to natural gas sales contracts that had fixed prices or price
ceilings. The Company believes that it has sufficient production from its
properties to meet the Company's delivery obligations under its existing
natural gas sales contracts.

   In an effort to eliminate price volatility from its Piceance Basin
development program, the Company entered into a series of hedges throughout
1997 to hedge an aggregate of 123.5 Bcf of natural gas production from the
Rocky Mountain Region for the five-year period through March 2003. At year-end
2000, 57.4 Bcf of these hedges remained in place at an average gas sales price
of $1.77 per mmbtu.

   The Company has entered into a series of firm transportation and storage
agreements with various Rocky Mountain pipeline companies. At January 1, 2001,
these transportation arrangements had terms ranging from one month to ten
years. These transportation agreements provide the Company the opportunity to
transport a portion of its Rocky Mountain natural gas production into the Mid-
Continent. These agreements, in total, provide transportation of approximately
220 MMcfd. The primary purpose of this transportation is to move Company
production. The Company determines on a monthly basis the amount of gas that
it will transport from the Rocky Mountains to the Mid-Continent based on
current market conditions including consideration of price differentials
between the different areas. The Company's gas marketing group will utilize
unused transportation to purchase and transport third party gas to minimize
the cost of unused transportation to the Company. As Company production
increases, capacity previously used by the marketing department will be
utilized to move Company production.

   The Company has established a Risk Management Committee to oversee its
production hedging and marketing department activities. The Risk Management
Committee consists of the Chief Executive Officer, the President and Chief
Operating Officer, the Chief Financial Officer, the Senior Vice President and
Treasurer and the Vice President-Marketing. The Risk Management Committee must
review and approve all production hedges. During 2000, the Company did not
enter into and any additional price hedges specifically identified for Company
owned gas production.

   Oil and Condensate. Oil, including condensate production, is generally sold
from the leases at posted field prices, plus negotiated bonuses. Marketing
arrangements are made locally with various petroleum companies. The Company
sells its own oil production to numerous customers. Oil revenues totaled $23
million for the year ended December 31, 2000 and represented 6% of the
Company's total revenues for that period. The Company does not engage in oil
trading activities.

Government Regulation of the Oil and Gas Industry

   The Company's exploration, production and marketing operations are
regulated extensively at the federal, state and local levels. Natural gas and
oil exploration, development and production activities are subject to various
laws and regulations governing a wide variety of matters. For example,
hydrocarbon-producing states have statutes or regulations addressing
conservation practices and the protection of correlative rights, and such
regulations may affect the Company's operations and limit the quantity of
hydrocarbons the Company may produce and sell. Other regulated matters include
marketing, pricing, transportation, and valuation of royalty payments.

   Certain operations the Company conducts are on federal oil and gas leases,
which the Minerals Management Service ("MMS") administers. The MMS issues such
leases through competitive bidding. These leases contain relatively
standardized terms and require compliance with detailed MMS regulations and
orders pursuant to the Outer Continental Shelf Lands Act ("OCSLA"), which are
subject to change by the MMS. For offshore operations, lessees must obtain MMS
approval for exploration plans and development and production plans prior to
the commencement of such operations. In addition to permits required from
other agencies (such as the Coast Guard, the Army Corps of Engineers and the
Environmental Protection Agency), lessees must obtain a permit from the MMS
prior to the commencement of drilling. The MMS also has issued regulations
restricting the

                                      12
<PAGE>

flaring or venting of natural gas and liquid hydrocarbons without prior
authorization. Similarly, the MMS has promulgated regulations governing the
plugging and abandonment of wells located offshore and the removal of all
production facilities. To cover the various obligations of lessees on the OCS,
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 any 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 Federal Energy Regulatory Commission ("FERC") regulates interstate
transportation of natural gas under the Natural Gas Act. The Company's natural
gas sales are affected by regulation of intrastate and interstate natural gas
transportation. In an attempt to promote competition, the FERC has issued a
series of orders that have altered significantly the marketing and
transportation of natural gas. The effect of these orders has been to enable
the Company to market its natural gas production to purchasers other than the
interstate pipelines located in the vicinity of its producing properties. The
Company believes that these changes have generally improved the Company's
access to transportation and have enhanced the marketability of its natural
gas production. To date, the Company has not experienced any material adverse
effect on natural gas marketing as a result of these FERC orders; however, the
Company cannot predict what new regulations may be adopted by the FERC and
other regulatory authorities, or what effect subsequent regulations may have
on its future natural gas marketing.

   Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act
deregulated natural gas prices for all "first sales" of natural gas, which
includes sales by the Company of its own production. As a result, all sales of
the Company's natural gas produced in the U.S. may be sold at market prices,
unless otherwise committed by contract. Congress could reenact price controls
in the future. In addition, a complaint has been filed with the FERC,
captioned National Association of Gas Consumers v. All Sellers of Natural Gas
in the United States of America, RP01-223-000, wherein the complainant has
requested FERC to issue an order setting a benchmark price of $2.74 per Mmbtu
or, alternatively, initiate an investigation as to current prices and order
refunds of "excessive prices."

   The Company also is subject to laws and regulations concerning occupational
safety and health. It is not anticipated that the Company will be required in
the near future to expend amounts that are material in the aggregate to the
Company's overall operations by reason of occupational safety and health laws
and regulations, but inasmuch as such laws and regulations are frequently
changed, the Company is unable to predict the ultimate cost of compliance.

   Environmental Matters

   The Company, as an owner or lessee and operator of natural gas and oil
properties, is subject to various federal, state and local laws and
regulations relating to discharge of materials into, and protection of, the
environment. These laws and regulations may, among other things, impose
liability and substantial penalties on the lessee under a natural gas and oil
lease for the cost of pollution clean-up resulting from operations, subject
the lessee to liability for pollution damages, require suspension or cessation
of operations in affected areas, and impose restrictions on the injection of
liquid into subsurface aquifers that may contaminate groundwater. The Oil
Pollution Act of 1990, as amended, requires operators of offshore facilities
to provide financial assurance in the minimum amount of $35 million to cover
potential environmental cleanup and restoration costs. This amount is subject
to adjustment up to $150 million if the MMS determines such an amount is
justified by the risks from potential oil spills from covered offshore
facilities.

   The Company has made, and will continue to make, expenditures in its
efforts to comply with these requirements, which it believes are necessary
business costs in the oil and gas industry. The Company believes it is in
substantial compliance with applicable environmental laws and requirements and
to date such compliance has not had a material adverse effect on the earnings
or competitive position of the Company, although there can be no assurance
that significant costs for compliance will not be incurred in the future. The
Company maintains insurance coverages which it believes are customary in the
industry, although it is not fully insured against many environmental risks.

                                      13
<PAGE>

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, 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 (other than a preliminary review of local records). The
Company reviews information concerning federal and state offshore lease blocks
prior to acquisition. Drilling title opinions are always prepared before
commencement of drilling operations; however, as is customary in the industry,
the Company does not obtain drilling title opinions on offshore leases it has
received directly from the MMS.

Hedging May Prevent the Company from Fully Benefiting from Price Increases

   To the extent that the Company engages in hedging activities, it may be
prevented from realizing the benefits of price increases above the levels of
the hedges. In addition, the Company is subject to basis risk when it engages
in hedging transactions, particularly where transportation constraints
restrict the Company's ability to deliver oil and gas volumes at the delivery
point to which the hedging transaction is indexed. See "--Natural Gas and Oil
Marketing and Trading" and "Item 7A. Quantitative and Qualitative Disclosures
About Market Risk."

Commodity Pricing and Demand

   Crude oil prices continue to be affected by political developments
worldwide, pricing decisions and production quotas of OPEC and the volatile
trading patterns in the commodity futures markets. Natural gas prices also
continue to be highly volatile. In periods of sharply lower commodity prices,
the Company may curtail capital spending projects, as well as delay or defer
drilling wells in certain areas because of lower cash flows. Changes in crude
oil and natural gas prices can impact the Company's determination of proved
reserves and the Company's calculation of the standardized measure of
discounted future net cash flows relating to oil and gas reserves.

Exploration and Operating Risks

   The Company's business is subject to all of the operating risks normally
associated with the exploration for and production of oil and gas, including
blowouts, cratering and fire, any of which could result in damage to, or
destruction of, oil and gas wells or formations or production facilities and
other property and injury to persons. As protection against financial loss
resulting from these operating hazards, the Company maintains insurance
coverage, including certain physical damage, employer's liability,
comprehensive general liability and worker's compensation insurance. Although
the Company is not fully insured against all risks in its business, the
Company believes that the coverage it maintains is customary for companies
engaged in similar operations. The occurrence of a significant event against
which the Company is not fully insured could have a material adverse effect on
the Company's financial position.

Development Risks

   The Company is involved in several large development projects. Key factors
that may affect the timing and outcome of such projects include: project
approvals by joint venture partners; timely issuance of permits and licenses
by governmental agencies; manufacturing and delivery schedules of critical
equipment; and commercial arrangements for pipelines and related equipment to
transport and market hydrocarbons. In large development projects, these
uncertainties are usually resolved, but delays and differences between
estimated and actual timing of critical events are commonplace and may,
therefore, affect the forward-looking statements related to large development
projects.

Competition

   The oil and gas business is highly competitive in the search for and
acquisition of reserves and in the gathering and marketing of oil and gas
production. The Company's competitors include the major oil companies,

                                      14
<PAGE>

independent oil and gas concerns, individual producers, gas marketers and
major pipeline companies, as well as participants in other industries
supplying energy and fuel to industrial, commercial and individual consumers.

Disclosure Regarding Forward-Looking Statements

   This Annual Report on Form 10-K includes "forward-looking statements"
within the meaning of Section 27A of the Securities Act of 1933, as amended
(the "Securities Act"), 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 Annual Report on Form 10-K, including
without limitation statements under "Items 1 and 2. Business and Properties--
Core Areas of Activity", "--Reserves", "--Natural Gas and Oil Marketing and
Trading", "--Government Regulation of the Oil and Gas Industry", "--Hedging
May Prevent the Company from Fully Benefiting from Price Increases",
"Exploration and Operating Risks", "--Development Risks", "Competition" and
"Item 3. Legal Proceedings", and "Item 7. Management's Discussion and Analysis
of Financial Condition and Results of Operations", and "Item 7A. Quantitative
and Qualitative Disclosures About Market Risk" regarding the Company's
financial position, reserve quantities and net present values, business
strategy, plans and objectives of management of the Company for future
operations and capital expenditures, are forward-looking statements. Although
the Company believes that the expectations reflected in the forward-looking
statements and the assumptions upon which such forward-looking statements are
based are reasonable, it can give no assurance that such expectations and
assumptions will prove to have been correct. Reserve estimates are generally
different from the quantities of oil and natural gas that are ultimately
recovered. Additional statements concerning important factors that could cause
actual results to differ materially from the Company's expectations
("Cautionary Statements") are disclosed in this Annual Report on Form 10-K and
in the "Risk Factors" section of the Company's Preliminary Prospectus dated
May 6, 1998 included in the Company's Registration Statement on Form S-3 (File
Number 333-51985). All written and oral forward-looking statements
attributable to the Company or persons acting on its behalf subsequent to the
date of this Annual Report on Form 10-K are expressly qualified in their
entirety by the Cautionary Statements.

Item 3. Legal Proceedings

  Kansas Ad Valorem Tax Refund

   Pursuant to an August 1996 decision of the United States Court of Appeals
for the District of Columbia Circuit and subsequent orders of the FERC,
natural gas producers who received reimbursement for Kansas ad valorem taxes
paid in the mid-1980s in excess of the then maximum lawful price for natural
gas have been ordered to refund these tax reimbursements plus interest. In
1998, in compliance with these decisions, Plains Petroleum Operating Company
(a subsidiary of the Company) refunded a total of $4.25 million. This amount
reflects the entire refund obligation (principal and interest) that has been
billed to Plains' working interest. In addition, in 1998 Plains placed in
escrow $1.21 million. This escrowed amount represents the refund amount
attributable to Plains' royalty interest owners. On July 28, 1999, Plains
filed a class action in Kansas state district court to recover from its
royalty owners the amount placed in escrow. On January 23, 2001, the district
court ruled that the statute of limitations has expired and additionally,
"changed circumstances" precluded the claim. Plains has filed an appeal with
the Kansas Supreme Court. If that appeal is unsuccessful, Plains will file an
application with FERC seeking relief from any obligation with respect to the
royalty owner portion of the refund. The Company will only be financially
obligated for the royalty related refunds should the appeal be unsuccessful or
if unable to obtain FERC relief from any portion of the royalty refund.


  Litigation Concerning Shell Oil Company Offer

   The Company is involved in various lawsuits in connection with the
unsolicited tender offer commenced by Shell Oil Company on March 12, 2001 to
acquire the Company's outstanding common stock for $55.00 per share. The
following is a summary of these lawsuits.

                                      15
<PAGE>

   On March 7, 2001, Shell filed a complaint against Barrett in the Delaware
Court of Chancery. The Shell complaint sought an order declaring Article III,
Section 3 of the Barrett Bylaws to be in violation of Section 228 of the
Delaware corporate law. Article III, Section 3 provides that nominations by
stockholders for directors to be elected by written consent must be delivered
in writing to the Barrett Corporate Secretary not less than 60 days nor more
than 90 days prior to the first solicitation of any written consents for the
election of those nominees. In addition, Shell asked the Court to enjoin
Barrett, or anyone acting on Barrett's behalf or in concert with Barrett, from
enforcing Article III, Section 3. The Shell complaint also seeks an order
declaring Article IX, Section 4 of the Barrett Bylaws to be in violation of
Section 228 of the Delaware corporate law and again asks the Court to enjoin
Barrett, or anyone acting on Barrett's behalf or in concert with Barrett, from
enforcing that Bylaw. Article IX, Section 4 provides that the Barrett Bylaws
may be amended at a meeting of stockholders, but not by their written consent,
and includes certain requirements of advance notice of the proposed amendment
to Barrett and the Barrett Board. On March 12, 2001, Shell filed an amended
complaint adding Sub as a plaintiff and the individual directors of Barrett as
defendants. Shell alleges that the Barrett directors have breached their
fiduciary duties by failing to amend the Bylaws that allegedly violate state
law. On March 12, 2001, Shell also filed a motion with the Court seeking an
expedited proceeding for matters asserted in its complaint. On March 14, 2001,
Barrett amended the Bylaws to delete the two provisions that are the subject
of this litigation.

   On March 12, 2001, Shell and Sub filed a complaint against Barrett in the
United States District Court for the District of Delaware. The complaint seeks
an order declaring that the Shell Consent Solicitation, the Shell tender offer
documents and other documents filed with the SEC comply with all federal laws.
In addition, the complaint asks the Court to enjoin Barrett, or anyone acting
on Barrett's behalf or in concert with Barrett, from commencing in any other
forum litigation that relates to the Shell Consent Solicitation or the Shell
Offer or any matters concerning them.

   Several actions have been filed against Barrett and the Barrett Board in
the Delaware Court of Chancery on behalf of a purported class of Barrett
stockholders. Although containing slightly different allegations, all of the
complaints allege that the Board is violating its fiduciary duties to
stockholders. The various actions ask the Court to order the Board to evaluate
Barrett's net worth, to inform itself about the Shell Offer and other
potential acquirers, to enhance Barrett's value, to negotiate with Shell and
to conduct an auction for Barrett. Some of the complaints also challenge the
Company's Rights Agreement concerning preferred stock purchase rights
associated with the Common Stock and the two recently deleted Bylaws
challenged in Shell's suit in the Delaware Court of Chancery. In addition to
the injunctions, the actions request payment of their alleged damages and
plaintiffs' attorneys' fees.

   Two actions have been filed against Barrett and the Barrett Board in the
District Court for the City and County of Denver, Colorado on behalf of a
purported class of Barrett stockholders. These actions allege that the Board
will violate its fiduciary duties to stockholders if it allows Barrett to
consummate the Shell Offer. The actions ask the Court to enjoin the Board from
agreeing to the Shell Offer and to require the Board to implement a fair
process in order to sell the Company in a way that maximizes stockholder
value.

  Other Legal Proceedings

   At December 31, 2000, the Company was a party to certain other legal
proceedings, which have arisen out of the ordinary course of business. Based
on the facts currently available, in management's opinion, the liability,
individually or in the aggregate, if any, to the Company resulting from such
actions will not have a material adverse effect on the Company's consolidated
financial position or results of operations.

Item 4. Submission of Matters to Vote of Security Holders

   No matters were submitted to a vote of the Company's security holders
during the fourth quarter of the year ended December 31, 2000.

                                      16
<PAGE>

                                    PART II

Item 5. Market for the Company's Common Stock and Related Security Holders
Matters.

   (a) Market Information. The Company's common stock is listed on the New
York Stock Exchange under the symbol BRR. The range of high and low sales
prices for each quarterly period during the two most recent years, as reported
by the New York Stock Exchange, is as follows:

<TABLE>
<CAPTION>
   Quarter Ended                                                    High   Low
   -------------                                                   ------ ------
   <S>                                                             <C>    <C>
   March 31, 1999................................................. $28.00 $15.44
   June 30, 1999.................................................. $39.81 $24.31
   September 30, 1999............................................. $41.25 $32.25
   December 31, 1999.............................................. $37.31 $23.06
   March 31, 2000................................................. $34.31 $19.19
   June 30, 2000.................................................. $41.63 $27.31
   September 30, 2000............................................. $39.19 $26.69
   December 31, 2000.............................................. $59.81 $35.63
</TABLE>

   On March 15, 2001, the closing price for the Company's common stock was $
61.76 per share.

   (b) Holders. The number of record holders of the Company's common stock as
of March 15, 2001 was 2,499.

   (c) Dividends. The Company has not paid any cash dividends since its
inception. The Company's credit agreement restricts payment of dividends to
amounts that are less than 50 percent of net income. The Company anticipates
that all earnings will be retained for the development of its business and
that no cash dividends on its common stock will be declared in the foreseeable
future.

Item 6. Selected Financial Data

   The following table sets forth certain selected financial data of the
Company for each of the last five years ended December 31:

<TABLE>
<CAPTION>
                                          Year Ended December 31,
                               -----------------------------------------------
                                  2000      1999     1998      1997     1996
                               ---------- -------- --------  -------- --------
<S>                            <C>        <C>      <C>       <C>      <C>
                                   (in thousands, except per share data)
Operating Revenues............ $  376,432 $215,000 $211,768  $209,887 $154,950
Net income (loss)............. $   27,674 $ 20,828 $(93,743) $ 29,261 $ 29,526
Net income (loss) per share... $     0.83 $   0.64 $  (2.95) $   0.92 $   1.02
Total assets at the end of
 each period.................. $1,253,833 $884,301 $838,879  $872,701 $576,945
Long-term debt at the end of
 each period.................. $  406,269 $355,250 $334,067  $266,437 $ 70,000
</TABLE>

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

   The following discussion should be read in conjunction with the
Consolidated Financial Statements and Notes thereto referred to in "Item 8.
Financial Statements and Supplemental Data", and "Items 1 and 2. Business and
Properties--Disclosure Regarding Forward-Looking Statements" of this Form 10-
K.

Liquidity and Capital Resources

   At December 31, 2000, the Company's total assets were $1.25 billion,
reflecting an increase of $370 million (42 percent) over total assets of $884
million at December 31, 1999. This increase is principally attributable to 1)
the Company's drilling and development activities, 2) acquisition of
additional working interests in certain

                                      17
<PAGE>

properties in the Piceance Basin and an acquisition in the Raton Basin, 3) an
increase in receivables of $198 million, resulting primarily from higher
average sales prices for gas and oil and 4) increased receivables related to
trading activity.

   The Company's cash and cash equivalents at December 31, 2000 increased $4.8
million to $25.5 million and working capital increased by $3.6 million
compared to December 31, 1999. The Company's working capital was adversely
affected by certain non-cash unrealized mark to market adjustments of $47.7
million reflected in current liabilities at December 31, 2000. (See Results of
Operations below and Note 10 to the Consolidated Financial Statements for a
discussion of the effect of the mark to market adjustments during 2000.)
Excluding the effect of the $47.7 million unrealized mark to market
adjustment, the Company's working capital at the end of 2000 would have
increased by $51.3 million, compared to 1999.

   For the year ended December 31, 2000, the Company generated operating cash
flow of $211 million before working capital changes compared with $122.2
million in 1999. After working capital changes, cash flow provided by
operations was $178.5 million, an increase of $66.3 million over 1999. These
increases are attributable to an 18 percent increase in natural gas production
(total production increased 14 percent) over 1999 production together with
higher commodity prices received in 2000.

   At December 31, 2000, the Company had $9 million of outstanding margin
deposits held by derivative counter parties and had issued letters of credit
totaling $40.3 million to certain other counter parties. These margin deposits
and letters of credit will be refunded or released, respectively, to the
Company as the related derivatives settle, natural gas prices decline or
alternative arrangements are made.

   At December 31, 2000 and 1999, the outstanding balances under the Company's
bank credit facility were $248 million and $200 million, respectively. The
increase in the Company's year-end bank debt was primarily associated with the
acquisition in October of properties in the Raton Basin in southern Colorado.
On December 15, 2000, the Company entered into a new unsecured revolving
senior credit facility with a consortium of lending institutions. Under this
credit facility, up to $350 million is currently available to the Company for
loans and letters of credit. The Company has the option to increase the
maximum amount available under the facility to $450 million, subject to
certain terms and conditions. The maturity date of the credit facility is
December 15, 2005 and requires interest payments only until that time. The
Company has the option to borrow funds at an interest rate equal to the London
Interbank Eurodollar Rate ("LIBOR"), plus an applicable margin, or at a
defined Base Rate. For funds borrowed under the LIBOR rate, the Company may
select interest periods of one, two, three or six months with interest payable
at the end of the selected interest period, but not less frequently than
quarterly. Interest with respect to Base Rate loans is payable quarterly. (See
Note 6 to the Consolidated Financial Statements for a complete discussion of
the Company's long term debt and interest obligations.)

 Capital Expenditures

   The Company's 2000 capital expenditures, before divestitures totaling $44.8
million, were $291 million compared to $161 million for 1999. The Company
expended approximately $200 million in drilling and development activities
resulting in an addition of 1,227 gross (632 net) wells during 2000. Of these
expenditures, $80.4 million (40 percent) was invested in the Piceance Basin
(excluding the acquisition discussed below), $53.5 million (27 percent) in the
Powder River Basin-Coal Bed Methane project and $35.9 million (18 percent) in
the Wind River Basin.

   As part of the Company's 2000 capital expenditure program, the Company
acquired additional working interests in its Piceance Basin gas properties and
joint venture interest in a related gas gathering system, processing plant and
pipeline from an industry partner for approximately $34.4 million. Also, the
Company acquired interests in 54,675 gross and net acres of coal bed methane
properties in the Raton Basin in southern Colorado, with 58 producing wells
and a gas gathering and compression system, for a purchase price of
approximately $52.9 million.

                                      18
<PAGE>

   During 2000, the Company received proceeds of $44.8 million from the sale
of its interests in certain non-core oil and gas properties located
principally in the Permian and Arkoma Basins.

   The Company plans to continue actively acquiring, exploring and developing
oil and gas properties in the Rocky Mountain Region and expects its capital
expenditures for 2001 to be approximately $271 million. (See the Company's
discussion of its Core Areas of Activity included previously in this Form 10-
K). Management continues to be sensitive to fluctuations in natural gas and
oil prices, the Company's cash flow and its level of debt and will reassess
the future capital expenditure levels relative to such fluctuations.

 Reserves and Pricing

   Proved reserves at year-end 2000 were 1,372.0 billion cubic feet of natural
gas equivalents (Bcfe), approximately a 21 percent increase over the Company's
December 31, 1999 proved reserves. Approximately 26 percent of the reserve
additions were provided by property acquisitions, and 74 percent of the
reserve additions were generated through exploration and development projects.
Proved reserves were reduced by production of approximately 117.6 Bcfe and
sales of properties with reserves of 35.9 Bcfe and downward revisions of
previous estimates of 25.3 Bcfe. During 2000, as a result of its drilling and
acquisition activities net of sales and revisions, the Company's reserve
replacement was 302 percent of total production.

   As of December 31, 2000, the standardized measure of discounted future net
cash flows increased $2.8 billion, or 421 percent, from 1999 primarily due to
increases in oil and gas prices and reserve quantity additions. Reserve
extensions and discoveries and purchases of proved reserves, net of sales,
added $1.06 billion and $207.1 million, respectively, to the standardized
measure. The changes in year-end sales prices and production costs from 1999
to 2000 increased the standardized measure of discounted future net cash flows
by $3.468 billion. Reserves produced during the year reduced the standardized
measure by $343.4 million. The Company's standardized measure of discounted
future net cash flows is sensitive to gas prices and is subject to change as a
result of volatility in the commodities market.

   Oil and natural gas prices fluctuate throughout the year. As of December
31, 2000, the Company was receiving weighted average prices of $22.18 per
barrel of oil and $8.23 per Mcf of gas. A decline in prices would have a
material effect on the discounted future net cash flows which, in turn, could
impact the "ceiling test" for the Company's oil and gas properties accounted
for under the full cost method. Should the net capitalized costs of the
Company's oil and gas properties exceed the estimated present value of future
net cash flow from proved oil and gas reserves, such excess costs would be
recognized as an impairment and charged to expense.

   From time to time the Company uses swaps to hedge the sales price of its
natural gas and oil. The intent of hedging activities is to reduce the
volatility associated with the sales prices of the Company's natural gas and
oil production. Although hedging transactions associated with the Company's
production reduce the Company's exposure to declines in production revenue as
a result of unfavorable price changes, these transactions also limit the
Company's ability to benefit from favorable price changes. As of December 31,
2000, the Company held positions to hedge 57.4 Bcf of the Company's future
natural gas production at varying volumes per month through March 2003. The
Company currently has no derivatives in place for its oil production.

   As part of the Company's trading activities, it enters into a variety of
contracts to purchase and sell natural gas and oil at both fixed prices and at
index based prices. In addition, the Company enters into financial instruments
that seek to reduce sensitivity to price movements or to create guaranteed
margins on certain delivery and purchase commitments. As of December 31, 2000,
the absolute notional contract quantity of natural gas commodity derivatives
held for trading purposes was 578.3 Bcf including financial purchases, sales
and basis positions.

   The Company's drilling and acquisition activities have increased its
reserve base and its productive capacity and, therefore, its potential cash
flow. Lower gas prices may adversely affect cash flow. Due to current higher
than expected market prices for natural gas and the Company's derivative
positions for its natural gas production (See Item 7A Quantitative and
Qualitative Disclosures About Risk, Commodity Price Risk), the derivative

                                      19
<PAGE>

counter parties have required margin call deposits which may adversely affect
the Company's liquidity. If natural gas prices decline, such margin deposits
will be refunded to the Company. The Company's intentions are to continue to
acquire and develop oil and gas properties in its areas of activity as
dictated by market conditions and financial ability. The Company retains
flexibility to participate in oil and gas activities at a level that is
supported by its cash flow and financial ability.

   Management expects cash flow from its producing properties and its
borrowing capacity to be sufficient to fund its anticipated capital and
operating requirements, including any contingencies. Additional funding
alternatives, including sales of non-core area properties, will be considered
to secure other funds for capital development. The Company intends to continue
to use financial leverage to fund its operations as investment opportunities
become available on terms that management believes warrant investment of the
Company's capital resources.

Results of Operations

 2000 vs. 1999

   In 2000, the Company earned net income of $27.7 million ($.83 per share),
compared to net income of $20.8 million ($.64 per share) in 1999. During 2000,
the Company recognized $40.4 million after tax unrealized losses on the fair
value of certain derivatives ($65.2 million before tax). During 1999 the
Company included an after tax unrealized gain of $0.9 million on the fair
value of certain derivatives ($1.4 million before tax). Excluding the effects
of the unrealized fair value losses and gains and related income tax effect,
the Company's net income for 2000 and 1999 was $68.1 million ($2.04 per share)
and $19.9 million ($.61 per share), respectively.

   The Company's 2000 operating income from oil and gas operations increased
$123.4 million over 1999 results, primarily due to record production
strengthened by strong commodity prices. Oil and gas operating revenues
increased $161.4 million (75 percent) to $376.4 million in 2000. Oil and gas
operating expenses increased 21 percent to $217.8 million. Lease operating
expenses increased $15.8 million, transportation and gathering increased $10.0
million, and depreciation, depletion and amortization increased $10.1 million.

   Revenues from oil and gas production increased $157.8 million to $367.7
million, primarily due to an 80 percent increase in gas revenues. The increase
in gas revenue resulted from a 52 percent increase in average gas sales prices
received and an 18 percent increase in gas production. For 2000, the average
realized gas price, net of hedging, was $3.07 per Mcf compared to the average
realized price of $2.02 received in 1999. Gas production increased from 94.9
Bcf in 1999 to 112.4 Bcf in 2000. Gas production accounted for 96 percent of
total production on an energy equivalent basis. The Piceance, Powder River--
Coal Bed Methane, Wind River and Hugoton Embayment Basin properties accounted
for 33 percent, 22 percent, 18 percent, and 10 percent, respectively, of total
gas production.

   The Company enters into hedging arrangements to reduce its exposure to
price risks associated with commodities markets. Although hedging transactions
associated with its production reduce the Company's exposure to losses as a
result of unfavorable price changes, the transactions also limit the Company's
ability to benefit from favorable price changes. During 2000, the Company had
hedges 33.7 Bcf (30 percent) of its gas production for a net cost of $47.8
million. Net hedging gains and losses are included in oil and gas revenues.

   Oil production decreased from 1.4 million barrels in 1999 to 0.9 million
barrels in 2000. The decrease in oil production was due primarily to the sale
of the Company's Permian Basin properties and was offset by a 107 percent
increase in average oil prices from $12.71 per Bbl in 1999 to $26.28 per Bbl
in 2000, resulting in an increase in oil revenue of $4.7 million. The Powder
River and Uinta Basin properties accounted for 60 percent and 18 percent,
respectively, of total oil production.

   Lease operating expenses of $56.3 million averaged $.48 per Mcfe ($2.87 per
BOE) compared to $.39 per Mcfe ($2.35 per BOE) in 1999. The increase is
primarily attributable to increases in production and ad valorem taxes, which
resulted from higher average product prices received in 2000. Transportation
and gathering expenses averaged $.29 per Mcfe ($1.77 per BOE) compared to $.24
per Mcfe ($1.43 per BOE) in 1999. Depreciation,

                                      20
<PAGE>

depletion and amortization increased $10.1 million, primarily due to higher
production volumes. During 2000, depletion and amortization on oil and gas
production averaged $.80 per Mcfe ($4.81 per BOE) compared to $.83 per Mcfe
($4.99 per BOE) in 1999.

   General and administrative expenses of $26.1 million reflect a nine percent
increase compared to 1999. The 2000 amount is net of $7.4 million of operating
fee recoveries compared to a $5.1 million recovery in 1999. On a per unit of
production basis, general and administrative expense was $0.22 per Mcfe
compared to $0.23 per Mcfe for 1999.

   The Company reports its trading activities on a net basis (trading revenues
net of associated costs). All periods have been reported on a consistent
basis. Excluding unrealized mark to market transactions, the Company's net
trading activities decreased from a $17.5 million gain in 1999 to a $23.6
million loss in 2000. Gas trading volumes increased three percent to 396.6 Bcf
in 2000. High volatility and rising gas prices resulted in higher settlement
costs on fixed price sales and financial derivative positions.

   The Company's trading derivative positions and natural gas held in
inventory for trading activities are marked to market at the end of each
reporting period. As of December 31, 2000, the Company's trading derivative
positions had a fair value of a negative $79.2 million compared with a fair
value of a positive $1.4 million at December 31, 1999. The decrease in the
fair value from 1999 to 2000 and the resulting increase in the mark to market
adjustment is attributable to the significant rise in natural gas prices.
Higher prices on December 31, 2000 resulted in a mark to market increase in
the Company's trading natural gas inventory of $15.4 million. The net change
of a negative $65.2 million in the fair values of the Company's trading
derivative and inventory positions is included in net trading activities.

   Interest expense increased from $21.5 million in 1999 to $25.5 million in
2000 (net of capitalized interest expense of $4.7 million), primarily as a
result of higher average interest rates during 2000 and increased bank debt.

   Income tax expense increased in 2000 by $4.5 million to $17.0 million as a
result of the Company's increase in net income. The Company's effective
financial statement tax rate in 2000 was 38 percent compared to 37.5 percent
for 1999.

 1999 vs. 1998

   In 1999, the Company earned net income of $20.8 million ($.64 per share),
compared to a net loss of $93.7 million ($2.95 per share) in 1998. Excluding
the effects of the oil and gas impairment and related income tax effect
recognized in 1998, the Company's net income in 1998 after taxes would have
been $11.7 million ($.36 per share).

   Operating revenues increased $3.2 million (two percent) to $215.0 million
in 1999. Operating expenses decreased 49 percent to $179.8 million (excluding
the effects of the 1998 oil and gas impairment, operating expenses decreased
four percent). Lease operating expenses decreased $4.1 million, transportation
and gathering increased $10.6 million, and depreciation, depletion and
amortization decreased $11.5 million.

   Oil and gas revenues increased $4.5 million to $210.0 million primarily due
to a five percent increase in gas revenues. This increase in gas revenues is
the result of a five percent increase in average gas prices from $1.92 in 1998
to $2.02 in 1999. Gas production remained unchanged at 94.9 Bcf in 1999. Oil
production decreased 30 percent which was partially offset by an 11 percent
increase in average oil prices from $11.42 per Bbl in 1998 to $12.71 per Bbl
in 1999. Gas production accounted for 92 percent of total production on an
energy equivalent basis. The Piceance, Wind River, Powder River--Coal Bed
Methane and Hugoton Embayment Basin properties accounted for 22 percent, 20
percent, 14 percent, and 14 percent, respectively, of total gas production.
The Powder River and Uinta Basin properties accounted for 39 percent and 21
percent, respectively, of total oil production.

                                      21
<PAGE>

   Lease operating expenses of $40.5 million averaged $.39 per Mcfe ($2.35 per
BOE), compared to $.42 per Mcfe ($2.50 per BOE) in 1998. Transportation and
gathering expenses averaged $.24 per Mcfe ($1.43 per BOE) compared to $.13 per
Mcfe ($.78 per BOE) in 1998. Depreciation, depletion and amortization
decreased $11.5 million primarily due to a decrease in the depletion rate.
During 1999, depletion and amortization on oil and gas production was provided
for at an average rate of $.83 per Mcfe ($4.99 per BOE) compared to an average
rate of $.91 per Mcfe ($5.49 per BOE), in 1998.

   Net trading activities increased $3.9 million to $18.8 million in 1999. The
1999 amount includes a mark to market gain of $1.4 million. Gas trading
volumes increased 76 percent to 383.5 Bcf in 1999.

   During 1999, the Company hedged 37.2 Bcf (39 percent) of its gas production
for a net cost of $8.3 million and 825 MBbls (58 percent) of its oil
production for a net cost of $4.6 million compared to 31.3 Bcf (33 percent) of
its gas production for a net cost of $0.7 million in 1998. Oil production was
not hedged in 1998.

   General and administrative expenses of $23.8 million reflect a three
percent decrease compared to 1998. The 1999 amount is net of $5.1 million of
operating fee recoveries compared to a $6.3 million recovery in 1998.

   Interest expense increased from $20.9 million in 1998 to $21.5 million in
1999 primarily as a result of the increase in long-term debt.

   Income tax expense was $12.5 million in 1999 compared to an 1998 income tax
benefit of ($55.8) million resulting from a net loss in 1998. The Company's
effective financial statement tax rate in 1999 was 37.5 percent.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

   Commodity financial instruments are intended to reduce the Company's
exposure to declines in the market price of natural gas and oil. Such
instruments may also limit the Company's gain from increases in the market
price of natural gas and oil. Fluctuations or changes in the settlement values
of commodity financial instruments are generally offset by similar changes in
the realized price of natural gas and oil.

   The Company uses commodity derivative financial instruments, including
futures and swaps, to reduce the effect of natural gas price volatility on a
portion of its natural gas production. Commodity swap agreements are generally
used to fix a price at the natural gas market location or to fix a price
differential between the price of natural gas at Henry Hub and the price of
gas at its market location. Settlements are based on the difference between a
fixed and a variable price as specified in the agreement. The following table
summarizes the Company's derivative financial instrument position on its
natural gas production as of December 31, 2000. The Company does not have in
place as of December 31, 2000 any hedging position for its future oil
production. The fair value of these instruments reflected in the table below
is the estimated amount that the Company would receive or (pay) to settle the
contracts as of December 31, 2000. Actual settlement of these instruments when
they mature will differ from these estimates reflected in the table. Gains or
losses realized from these instruments hedging the Company's production are
expected to be offset by changes in the actual sales price received by the
Company for its natural gas production.

<TABLE>
     <S>                <C>            <C>                             <C>
     For the year       Bcf            Price Range Per MMBtu              Fair Value
     ------------       ----           ---------------------           ----------------
         2001           25.8              $1.6376--$2.84               $(101.5) million
         2002           27.2              $1.6376--$2.84               $ (53.5) million
         2003            4.4              $1.6396--$1.72               $  (8.4) million
</TABLE>

   The Company also uses commodity derivative financial instruments and
contracts for the purchase and sale of natural gas at both fixed and indexed
based prices in its trading activities. The financial instruments seek to
reduce sensitivity to price movements, to lock in margins on its trading
positions and to hedge the value of stored

                                      22
<PAGE>

gas. The following tables summarize the Company's derivative positions on its
natural gas trading activities as of December 31, 2000. The fair value of
these instruments reflects the estimated amounts that the Company would
receive or (pay) to settle the contracts as of December 31, 2000. Actual
settlement of these instruments as they mature will differ from these
estimates.

CONTRACTS TO PURCHASE NATURAL GAS

<TABLE>
     <S>              <C>          <C>                              <C>
     For the year      Bcf           Price Range Per MMBtu            Fair Value
     ------------     -----        --------------------------       ---------------
         2001           5.5             $1.8425--$2.4550            $  12.9 million
                       82.3              Indexed Based              $  15.1 million
         2002          21.6              Indexed Based              $ (0.9) million
         2003          14.7              Indexed Based              $ (0.4) million
         2004          11.9              Indexed Based              $ (0.3) million
         2005           2.2              Indexed Based                    --

CONTRACTS TO SELL NATURAL GAS

     For the year      Bcf           Price Range Per MMBtu            Fair Value
     ------------     -----        --------------------------       ---------------
         2001          12.4               $1.92--$4.65              $(39.7) million
                      178.7              Indexed Based              $   9.7 million
         2002           2.7             $2.3725--$2.465             $ (3.8) million
                       58.6              Indexed Based              $  3.7  million
         2003           2.7             $2.3725--$2.465             $ (2.5) million
                       40.0              Indexed Based              $   1.5 million
         2004           2.7             $2.3725--$2.465             $ (2.7) million
                       32.7              Indexed Based              $   1.1 million
         2005           1.4             $2.3725--$2.465             $ (1.3) million
                       12.4              Indexed Based              $    .5 million
      Thereafter        3.8             $2.3725--$2.465             $ (3.2) million
                        9.4              Indexed Based              $    .2 million

DERIVATIVE FINANCIAL INSTRUMENT POSITIONS*

     For the year      Bcf           Price Range Per MMBtu            Fair Value
     ------------     -----        --------------------------       ---------------
         2001          24.4        $1.905--$5.055/Index Based       $(46.2) million
         2002          21.7            $2.84/Index Based            $ (8.9) million
         2003          19.8              Indexed Based              $ (2.8) million
         2004          15.9              Indexed Based              $ (3.4) million
         2005          ( .2)             Indexed Based              $ (2.1) million
      Thereafter        1.0              Indexed Based              $ (5.7) million
</TABLE>

   * The volumes presented in this table represent the Company's net position.
A positive position indicates a net purchase position; a negative position
indicates a net sell position.

   The Company's natural gas inventory held in storage had a fair market value
of $27.4 million as of December 31, 2000.

                                      23
<PAGE>

Interest Rate Risk

   The Company's use of fixed and variable rate long-term debt to partially
finance capital expenditures exposes the Company to market risk related
changes in interest rates. The following table presents principal and related
average interest rates by year of maturity for the Company's debt obligations
and their indicated fair market value at December 31, 2000.

<TABLE>
<CAPTION>
                                Expected Maturity /Redemption
                            -----------------------------------------
                            2001  2002  2003  2004  2005   Thereafter Fair Value
                            ----  ----  ----  ---- ------  ---------- ----------
                                          Dollars in millions
<S>                         <C>   <C>   <C>   <C>  <C>     <C>        <C>
Long-term Debt:
  Fixed rate............... $7.0  $6.5  $1.8  --      --     $150.0     $164.6
  Average Interest rate.... 7.72% 7.72% 7.72% --      --       7.55%
  Variable rate............  --    --    --   --   $248.0       --      $248.0
  Average Interest rate....  --    --    --   --     8.14%      --
</TABLE>


Item 8. Financial Statements and Supplemental Data

   The Consolidated Financial Statements and schedules that constitute Item 8
are attached at the end of this Annual Report on Form 10-K. An index to these
Consolidated Financial Statements and Schedules is also included in Item 14(a)
of this Annual Report on Form 10-K.

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

   Not applicable.


                                      24
<PAGE>

                                   PART III

Item 10. Directors and Executive Officers of the Company

   The directors and executive officers of the Company, their respective ages
and positions, and the year in which each director was first elected, are set
forth in the following table. Additional information concerning each of these
individuals follows the table:

<TABLE>
<CAPTION>
                                                                                                       Initial
                                                                                                       Date as
                                           Age                Position With the Company                Director
                                           --- ------------------------------------------------------- --------
<S>                                        <C> <C>                                                     <C>
C. Robert Buford(1)(2)(3)(4)(5)..........  67  Director                                                  1983

Derrill Cody(1)(2)(3)(4)(5)..............  62  Director                                                  1995

Peter A. Dea (1).........................  47  Chairman of the Board, Chief Executive Officer            1999
                                                and a Director

James M. Fitzgibbons(3)(4)(5)(6).........  66  Director                                                  1987

Hennie L. J. M. Gieskes (3)(4)(7)........  62  Director                                                  1985

William W. Grant, III(3)(4)(5)...........  68  Director                                                  1995

Philippe S.E. Schreiber (1)(2)(3)(4)(5)..  60  Director                                                  1985

Joseph P. Barrett(8).....................  47  Senior Vice President--Land                                 --

Dean J. Gallacher........................  36  Vice President--Marketing                                   --

Robert W. Howard.........................  46  Senior Vice President--Investor Relations and               --
                                                Corporate Development and Treasurer

Joseph N. Jaggers........................  47  President and Chief Operating Officer                       --

J. Frank Keller(8).......................  57  Executive Vice President and Chief Financial Officer        --

Eugene A. Lang, Jr.......................  47  Executive Vice President--General Counsel and Secretary     --

Logan Magruder, III......................  44  Vice President--Operations                                  --

Steven G. Natali.........................  46  Vice President--Exploration                                 --
</TABLE>
--------
(1) Member of the Executive Committee of the Board of Directors.
(2)  Member of the Board Planning and Nominating Committee of the Board of
     Directors.
(3)  Member of the Audit Committee of the Board of Directors.
(4)  Member of the Compensation Committee of the Board of Directors.
(5)  Member of the Succession Planning Committee of the Board of Directors
     until this Committee was discontinued on May 4, 2000.
(6)  Mr. Fitzgibbons served as a director of the Company from July 1987 until
     October 1992. He was re-elected to the Board of Directors in January
     1994.
(7)  Mr. Gieskes served as a director of the Company from November 1985 until
     September 1997. He was re-elected to the Board on May 4, 2000.
(8)  J. Frank Keller is the uncle of Joseph P. Barrett.

   C. Robert Buford has been a director of the Company since December 1983 and
served as Chairman of the Board of Directors from December 1983 through March
1994. Mr. Buford has been President, Chairman of the Board and controlling
shareholder of Zenith Drilling Corporation ("Zenith"), Wichita, Kansas, since
February 1966. Zenith owns approximately 1.6 percent of the Company's common
stock. Since 1993, Mr. Buford has served as a director of Encore Energy, Inc.,
a wholly-owned subsidiary of Zenith engaged in the marketing of natural gas.
Mr. Buford is also a member of the Board of Directors of Intrust Financial
Corporation, a bank holding company.

                                      25
<PAGE>

   Derrill Cody has been a director of the Company since July 1995. From May
1990 until July 1995, Mr. Cody served as a director of Plains Petroleum
Company ("Plains"), which merged with a subsidiary of the Company on July 18,
1995. Since January 1990, Mr. Cody has been an attorney in private practice in
Oklahoma City, Oklahoma. From 1986 to 1990, he was Executive Vice President of
Texas Eastern Corporation, and from 1987 to 1990 he was the Chief Executive
Officer of Texas Eastern Pipeline Company. Since 1990, he has been a director
of the General Partner of TEPPCO Partners, L.P., an operator of transportation
systems for liquid hydrocarbons.

   Peter A. Dea has served as Chairman of the Board since April 1, 2000, and
has served as Chief Executive Officer and a director since November 1999. He
previously served as Vice Chairman from November 1999 until April 1, 2000 and
as Executive Vice President--Exploration from December 1998 until November
1999. He served as Senior Vice President--Exploration of the Company from June
1996 until December 1998. He held various exploration geologist positions with
the Company from February 1994 through June 1996. Mr. Dea served as President
of Nautilus Oil and Gas Company from 1992 through 1993.

   James M. Fitzgibbons has been a director of the Company since January 1994,
and previously served as a director of the Company from July 1987 until
October 1992. Since January 1998, Mr. Fitzgibbons has been the Chairman of the
Board of Davidson Cotton Company. From October 1990 through December 1997, Mr.
Fitzgibbons was Chairman of the Board and Chief Executive Officer of
Fieldcrest Cannon, Inc. Mr. Fitzgibbons also is a Director/Trustee of Dreyfus
Laurel Funds, a series of mutual funds.

   Hennie L.J.M. Gieskes was elected as a director in May 2000. He previously
served as a director of the Company from November 1985 until September 1997.
Mr. Gieskes has served as the Managing Director of Spaarne Compagnie N.V., a
Netherlands company engaged in the investment business, since January 1991.
From before 1976 until December 1990, Mr. Gieskes was a Managing Director of
Vitol Beheer B.V., a Netherlands trading company engaged primarily in energy
related commodities.

   William W. Grant, III has served as a director of the Company since July
1995. From May 1987 until July 1995, Mr. Grant served as a director of Plains
Petroleum Company. He was an advisory director of Colorado National Bank from
1993 through 1999. He was a director of Colorado National Bankshares, Inc.
from 1982 to 1993 and the Chairman of the Board of Colorado National Bank of
Denver from 1986 to 1993.

   Philippe S.E. Schreiber has been a director of the Company since November
1985. Mr. Schreiber is an independent lawyer and business consultant. From
August 1985 through December 1998, he was a partner of, or of counsel to, the
law firm of Walter, Conston, Alexander & Green, P.C. in New York, New York.
Mr. Schreiber has served as a director of the United States principal
affiliate of The Mayflower Corporation plc. since 1991. Mr. Schreiber also
serves as a director of other private companies.

   Joseph P. Barrett has served as the Company's Senior Vice President--Land
since March 1999. From March 1995 through February 1999, Mr. Barrett served as
Vice President--Land. Mr. Barrett has held various positions in the Company's
Land Department since 1982.

   Dean J. Gallacher joined the Company as its Vice President--Marketing in
November 2000. Before joining the Company, Mr. Gallacher was employed by
Avista Energy Inc. as a manager in its trading division from April 1997 to
November 2000. From January 1997 to March 1997, Mr. Gallacher served as a
principal for Potential Energy, Inc., which provided consulting services and
negotiation assistance concerning gas supply and transportation contracts and
related matters. In addition, Mr. Gallacher was employed as a marketing
manager by Inland Pacific Energy Services from April 1993 to December 1996
where he provided consulting services to large industrial customers on gas
supply and power contracts, energy trading activities and power requirements.

   Robert W. Howard has held his current position of Senior Vice President--
Investor Relations and Corporate Development since February 25, 1999. Mr.
Howard previously served as the Company's Senior Vice President since March
1992. He also has served as Treasurer since March 1986.

                                      26
<PAGE>

   Joseph N. Jaggers joined the Company in July 2000 as its President and
Chief Operating Officer. Prior to joining Barrett, Mr. Jaggers was employed by
BP Amoco as a Business Unit Leader from November 1998 to June 2000. From July
1995 to August 1998, Mr. Jaggers served as District Manager--Cairo for Amoco.
He also held the position of District Manager--Denver for Amoco from November
1991 to June 1995. In his capacities at BP Amoco and Amoco, Mr. Jaggers served
as a senior petroleum engineer and manager of production operations.

   J. Frank Keller has served as the Company's Executive Vice President since
1983 and Chief Financial Officer since 1995. Mr. Keller served as a director
from 1983 until 2000 and as Secretary from 1983 until 1997.

   Eugene A. Lang, Jr. has held the position of Executive Vice President --
General Counsel since May 1999. Mr. Lang served as the Company's Senior Vice
President -- General Counsel from September 1995 to May 1999. He also has
served as Secretary since June 1997.

   Logan Magruder III has held his current position as Vice President--
Operations since April 1998. From October 1997 to April 1998, Mr. Magruder
served as the Company's Vice President -- Investor Relations and Corporate
Development. In December 1996, Mr. Magruder joined the Company as its Manager
of Operations--Gulf of Mexico and held that position until October 1997. Mr.
Magruder was employed as Director of Engineering and Operations for Scana
Petroleum from November 1995 through December 1996.

   Steven G. Natali has served as the Company's Vice President--Exploration
since December 1999. From March 1999 until December 16, 1999, Mr. Natali
served as the Company's Exploration Manager. Mr. Natali held the position of
Chief Geophysicist for the Company from December 1995 to March 1999.

Section 16(a) Beneficial Ownership Reporting Compliance

   Section 16(a) of the Exchange Act requires the Company's executive officers
and directors, and persons who own more than 10 percent of the Company's
common stock to file reports of ownership and changes in ownership with the
SEC and the exchange on which the Company's common stock is listed for
trading. Executive officers, directors and more than ten percent stockholders
are required by regulations promulgated under the Exchange Act to furnish the
Company with copies of the Section 16(a) reports filed. Based solely on the
Company's review of copies of the Section 16(a) reports filed for the fiscal
year 2000, the Company believes that all reporting requirements applicable to
its executive officers, directors, and more than ten percent stockholders were
complied with for the fiscal year 2000.

                                      27
<PAGE>

Item 11. Executive Compensation

Summary Compensation Table

   The following table sets forth in summary form the compensation earned
during each of the Company's last three completed years by the Chief Executive
Officer of the Company and by the four other most highly compensated executive
officers whose salary and bonus exceeded $100,000 for the year ended December
31, 2000 (the "Named Executive Officers"):

                          Summary Compensation Table

<TABLE>
<CAPTION>
                                                                  Long Term Compensation
                                                              -------------------------------
                                                                      Awards          Payouts
                                                       Other  ----------------------- -------
                                                      Annual  Restricted  Securities
                                                      Compen-   Stock     Underlying   LTIP    All Other
                             Fiscal  Salary   Bonus   sation   Award(s)  Options/SARs Payouts Compensation
Name and Principal Position   Year    ($)     ($)(1)    ($)      ($)        (#)(2)      ($)      ($)(3)
---------------------------  ------ -------- -------- ------- ---------- ------------ ------- ------------
<S>                          <C>    <C>      <C>      <C>     <C>        <C>          <C>     <C>
Peter A. Dea...............   2000  $350,016 $200,000   -0-      -0-           -0-      -0-     $10,200
 Chief Executive Officer,     1999  $218,752 $175,000   -0-      -0-       100,000      -0-     $ 9,600
 Chairman, and a director     1998  $167,708      -0-   -0-      -0-       142,375      -0-     $ 9,600

Joseph N. Jaggers..........   2000  $119,391 $150,000   -0-      -0-        75,000      -0-     $75,886
 President, and Chief         1999       --       --    --       --            --       --          --
 Operating Officer (4)        1998       --       --    --       --            --       --          --

A. Ralph Reed (5)..........   2000  $285,000      -0-   -0-      -0-           -0-      -0-     $10,200
 Former President, former     1999  $285,000 $130,000   -0-      -0-        52,500      -0-     $ 9,600
 Chief Operating Officer,     1998  $272,250      -0-   -0-      -0-        60,000      -0-     $ 9,600
 and former director

J. Frank Keller (6)........   2000  $206,250 $ 55,000   -0-      -0-        25,000      -0-     $10,200
 Executive Vice President,    1999  $180,000 $ 85,000   -0-      -0-        34,350      -0-     $ 9,600
 Chief Financial Officer,     1998  $177,131      -0-   -0-      -0-        35,000      -0-     $ 9,600
 and former director

Eugene A. Lang, Jr.........   2000  $178,750 $111,000   -0-      -0-        12,000      -0-     $10,200
 Executive Vice President--   1999  $160,000 $ 60,000   -0-      -0-        11,200      -0-     $ 9,600
 General Counsel, and         1998  $157,500      -0-   -0-      -0-        25,000      -0-     $ 9,450
 Secretary
</TABLE>
--------
(1) The dollar value of cash bonuses earned during the year indicated. The
    cash bonuses earned for 2000 were determined by the Compensation Committee
    on March 7, 2001.
(2) The sum of the number of shares of common stock to be received upon the
    exercise of all stock options granted.
(3) Represents the Company's matching contribution under the Company's 401(k)
    Plan for each Named Executive Officer and a $75,000 relocation expense
    allowance paid to Mr. Jaggers upon his joining the Company as President
    and Chief Operating Officer on July 10, 2000.
(4) Mr. Jaggers joined the Company as President and Chief Operating Officer on
    July 10, 2000.
(5) On May 4, 2000, Mr. Reed stepped down as President and Chief Operating
    Officer. His membership on the Board also ended on May 4, 2000. Mr. Reed's
    employment ceased on January 4, 2001, when he retired. In recognition to
    Mr. Reed's contributions to the Company during his 11-year employment, he
    received a payment of $405,000 on January 4, 2001.
(6) Mr. Keller's membership on the Board ended on May 4, 2000.

                                      28
<PAGE>

Option Grants in Last Fiscal Year

   The following table provides certain summary information concerning
individual grants of stock options made to Named Executive Officers during the
fiscal year ended December 31, 2000 under the Company's incentive plans.
Except as set forth in the table below, during fiscal year 2000, the Company
did not grant any stock options under the Company's Incentive Plans to any of
the Named Executive Officers.

                       Option Grants In Last Fiscal Year

<TABLE>
<CAPTION>
                                                                        Potential Realizable Value
                          Number of    % of Total                         at Assumed Annual Rates
                         Securities     Options                         of Stock Price Appreciation
                         Underlying    Granted to  Exercise                   for Option Term
                           Options    Employees in   Price   Expiration ---------------------------
          Name           Granted (#)  Fiscal Year  ($/Share)    Date         5%           10%
          ----           -----------  ------------ --------- ---------- ---------------------------
<S>                      <C>          <C>          <C>       <C>        <C>          <C>
Peter A. Dea............      -0-(1)         0%         N/A        N/A           N/A            N/A
Joseph N. Jaggers.......   75,000(2)      25.8%    $  28.75  7-10-2007  $    877,500 $    2,045,250
A. Ralph Reed...........      -0-(3)         0%         N/A        N/A           N/A            N/A
J. Frank Keller.........   25,000(4)       8.6%    $25.8125  2-25-2007  $    262,750 $      612,250
Eugene A. Lang, Jr......   12,000(4)       4.1%    $25.8125  2-25-2007  $    126,120 $      293,880
</TABLE>
--------
(1) Mr. Dea was granted no stock options in 2000 in light of the options he
    received in November 1999 when he was elected Chief Executive Officer.
(2) Mr. Jaggers was granted options to purchase 75,000 shares upon his joining
    the Company as President and Chief Operating Officer on July 10, 2000.
    One-fourth of these options become exercisable on each of July 10, 2001,
    2002, 2003, and 2004 and all the options expire on July 10, 2007. These
    options become exercisable immediately upon a change in control of the
    Company.
(3) In light of his then anticipated retirement, Mr. Reed was granted no stock
    options in 2000.
(4) One-fourth of these options became exercisable on February 25, 2001, and
    one-fourth become exercisable on each of February 25, 2002, February 25,
    2003 and February 25, 2004. These options become exercisable immediately
    upon a change in control of the Company.

Aggregated Option Exercises And Fiscal Year-End Option Value Table

   The following table provides certain summary information concerning stock
option exercises during the fiscal year ended December 31, 2000 by the Named
Executive Officers and the value of unexercised stock options held by the
Named Executive Officers as of December 31, 2000.

                          Aggregated Option Exercises
                    For Fiscal Year Ended December 31, 2000
                        And Year-End Option Values(/1/)

<TABLE>
<CAPTION>
                                                        Number of
                                                  Securities Underlying     Value of Unexercised
                                                   Unexercised Options      In-the-Money Options
                           Shares      Value    at Fiscal Year-End(#)(4)  at Fiscal Year-End($)(5)
                         Acquired on  Realized  ------------------------- -------------------------
          Name           Exercise(2)  ($) (3)   Exercisable Unexercisable Exercisable Unexercisable
          ----           ----------- ---------- ----------- ------------- ----------- -------------
<S>                      <C>         <C>        <C>         <C>           <C>         <C>
Peter A. Dea............   56,858    $1,136,327   59,643       147,563    $1,537,569   $4,182,530
Joseph N. Jaggers.......      -0-    $      -0-      -0-        75,000    $      -0-   $2,104,500
A. Ralph Reed...........   75,000    $1,039,273   13,125        67,375    $  529,889   $2,169,292
J. Frank Keller.........   32,787    $  756,151   35,025        72,438    $  827,073   $2,322,595
Eugene A. Lang, Jr......    1,762    $   48,790   68,808        41,100    $2,080,134   $1,220,304
</TABLE>
--------
(1) No stock appreciation rights are held by any of the Named Executive
    Officers.
(2) The number of shares received upon exercise of options during the year
    ended December 31, 2000.
(3) With respect to options exercised during the year ended December 31, 2000,
    the dollar value of the difference between the option exercise price and
    the market value of the option shares purchased on the date of the
    exercise of the options.

                                      29
<PAGE>

(4) The total number of unexercised options held as of December 31, 2000,
    separated between those options that were exercisable and those options
    that were not exercisable on that date.
(5) For all unexercised options held as of December 31, 2000, the aggregate
    dollar value of the excess of the market value of the stock underlying
    those options over the exercise price of those unexercised options. These
    values are shown separately for those options that were exercisable, and
    those options that were not yet exercisable, on December 31, 2000. As
    required, the price used to calculate these figures was the closing sale
    price of the common stock at year's end, which was $56.81 per share on
    December 29, 2000.

Employee Retirement Plans, Long-Term Incentive Plans, and Pension Plans

   The Company has an employee retirement plan (the "401(k) Plan") that
qualifies under Section 401(k) of the Internal Revenue Code of 1986, as
amended (the "Code"). Employees of the Company are entitled to contribute to
the 401(k) Plan up to 15 percent of their respective salaries. In addition,
the Company currently contributes on behalf of each participating employee 100
percent of that employee's contribution, up to a maximum contribution by the
Company of six percent of that employee's gross salary for that pay period,
with one-half of the matching contribution paid in cash and one-half paid in
the Company's common stock. The Company's matching contribution is subject to
a vesting schedule. Benefits payable to employees upon retirement are based on
the contributions made by the employee under the 401(k) Plan, the Company's
matching contributions, and the performance of the 401(k) Plan's investments.
Therefore, the Company cannot estimate the annual benefits that will be
payable to participants in the 401(k) Plan upon retirement at normal
retirement age. Excluding the 401(k) Plan, the Company has no defined benefit
or actuarial or pension plans or other retirement plans.

   Excluding the Company's stock option plans, the Company has no long-term
incentive plan to serve as incentive for performance to occur over a period
longer than one fiscal year.

Compensation of Directors

   Standard Arrangements. Pursuant to the Company's standard arrangement for
compensating directors, no compensation for serving as a director is paid to
directors who also are employees of the Company, and those directors who are
not also employees of the Company ("Outside Directors") receive an annual
retainer of $20,000 paid in equal quarterly installments. In addition, during
the first quarter of 2000, for each Board of Directors or committee meeting
attended in person, each Outside Director received a $1,000 meeting attendance
fee. Each Outside Director also received $300 for each telephone meeting
lasting more than 15 minutes. The Chairmen of the Compensation and Audit
Committees received, however, a $1,500 meeting attendance fee for each
committee meeting. Beginning on April 1, 2000, the meeting attendance fee
increased to $1,100, the Chairman's fees for Committee meetings increased to
$1,600, and the fee for telephone meetings increased to $500. All directors
are reimbursed for out-of-pocket expenses incurred in connection with
attending Board and Committee meetings.

   For each Board of Directors or committee meeting attended, options to
purchase 1,000 shares of common stock will become exercisable for each Outside
Director. Although these options become exercisable only at the rate of 1,000
for each meeting attended, each director will be granted options to purchase
10,000 shares at the time the individual initially becomes a director. Any
options that have not become exercisable at the time of termination of a
director's service will expire at that time. At such time that the options to
purchase all 10,000 shares have become exercisable, options to purchase an
additional 10,000 shares will be granted to the director and will be subject
to the same restrictions on exercise as the previously received options. The
options are granted to the Outside Directors pursuant to the Company's Non-
Discretionary Stock Option Plan, and the exercise price for those options is
equal to the closing sales price for the Company's common stock on the date of
grant. The options expire upon the later to occur of five years after the date
of grant or two years after the date those options first became exercisable.

   Other Arrangements. During the year ended December 31, 2000, no
compensation was paid to directors of the Company other than pursuant to the
standard compensation arrangements described in the previous section.

                                      30
<PAGE>

Employment Contracts and Termination of Employment and Change-in-Control
Arrangements

   The Company has entered into severance agreements with each of the Named
Executive Officers as well as certain other officers and employees. Generally,
the agreements provide, among other things, that if, within three years after
a Change-in-Control (as defined in the severance agreement) the employee's
employment is terminated by the employee for "Good Reason" or by the Company
other than for "Cause" (as such terms are defined in the severance agreement),
the employee will be entitled to a lump sum cash payment equal to three times
for Messrs. Dea, Jaggers, Reed and Keller (two times in the case of other
officers and certain employees) the employee's annual compensation (based on
annual salary and past annual bonus) in addition to continuation of certain
benefits for three years for Messrs. Dea, Jaggers, Reed and Keller (two years
in the case of other officers and employees) from the date of termination. Mr.
Reed's agreement terminated upon his retirement on January 4, 2001.

   In addition, the Company's stock option plans and option agreements under
the plans provide for the acceleration of option exercisability in the event
of a Change-in-Control.

Compensation Committee Interlocks and Insider Participation

   During the year ended December 31, 2000, each of Messrs. Buford, Cody,
Fitzgibbons, Gieskes, Grant and Schreiber served as members of the
Compensation Committee of the Board of Directors. Mr. Schreiber served as the
President of Excel Energy Corporation ("Excel") prior to the 1985 merger of
Excel with and into the Company, and Mr. Gieskes served as Chairman of the
Board of Excel at the time of the merger. No other person who served as a
member of the Compensation Committee during the year ended December 31, 2000
was, during that year, an officer or employee of the Company or of any of its
subsidiaries, or was formerly an officer of the Company or of any of its
subsidiaries, except Mr. Buford who served as the Chairman of the Board from
December 1983 through March 1994. However, Mr. Buford was never a salaried
employee of the Company.

                                      31
<PAGE>

Item 12. Security Ownership of Certain Beneficial Owners and Management

   On March 15, 2001, there were 33,461,004 shares of the Company's common
stock outstanding. According to information furnished to the Company as of
March 15, 2001, the directors of the Company, the Named Executive Officers,
all directors and executive officers as a group, and each other person known
by the Company to be a beneficial owner of more than five percent of the
Company's common stock, beneficially owned shares of common stock as set forth
below. Beneficial ownership has been determined for purposes herein in
accordance with Rule 13d-3 of the Exchange Act under which a person has or
shares voting power or investment power in respect of such securities or has
the right to acquire beneficial ownership within 60 days of March 15, 2001.

<TABLE>
<CAPTION>
   Name of
  Beneficial                               Amount/Nature of     Percent of Class
    Owner                                Beneficial Ownership  Beneficially Owned
  ----------                             --------------------  ------------------
<S>                                      <C>                   <C>
C. Robert Buford ......................         644,866(1)            1.9%
Derrill Cody...........................          34,160(2)              *
Peter A. Dea...........................          80,799(2)              *
James M. Fitzgibbons...................          42,000(2)              *
Hennie L.J.M. Gieskes..................         909,214(2)            2.7%
William W. Grant, III..................          40,350(2)              *
Joseph N. Jaggers......................             255(2)              *
J. Frank Keller........................         117,060(2)              *
Eugene A. Lang, Jr.....................          96,791(2)              *
Philippe S.E. Schreiber................          37,106(2)              *
All Directors and Executive Officers as
 a Group (15 Persons)..................       2,124,312(3)            6.3%

State Farm Mutual Automobile Insurance
 Company and affiliates................       2,938,638(4)(5)         8.8%
 One State Farm Plaza
 Bloomington, IL 61710
Franklin Resources, Inc................       2,467,215(4)(6)         7.4%
 777 Mariners Island Boulevard
 San Mateo, CA 94403
Scudder Kemper Investments, Inc........       1,906,100(4)            5.7%
 345 Park Avenue
 New York, NY 10154
T. Rowe Price Associates, Inc..........       1,753,936(4)(7)         5.2%
 100 East Pratt Street
 Baltimore, MD 21202
</TABLE>
--------
*  Less than 1% of the common stock outstanding.
(1) C. Robert Buford is considered a beneficial owner of the 523,210 shares of
    which Zenith is the record owner. Mr. Buford owns approximately 89 percent
    of the outstanding common stock of Zenith. The number of shares of the
    Company's stock indicated for Mr. Buford also includes 10,000 shares that
    are owned by Aguilla Corporation, which is owned by Mr. Buford's wife and
    adult children. Mr. Buford disclaims beneficial ownership of the shares
    held by Aguilla Corporation pursuant to Rule 16a-1(a)(4) under the
    Exchange Act. The number of shares indicated also includes 30,000 shares
    underlying stock options that currently are exercisable or that may become
    exercisable within 60 days following March 15, 2001.
(2) The number of shares indicated consists of or includes the following
    number of shares underlying options that currently are exercisable or that
    may become exercisable within 60 days following March 15, 2001: Derrill
    Cody, 20,000; Peter A. Dea, 66,518; James M. Fitzgibbons, 30,000; Hennie
    L.J.M. Gieskes, 10,000; William W. Grant, III, 20,000; J. Frank Keller,
    64,038; Eugene A. Lang, Jr., 84,767; and Philippe S.E. Schreiber, 30,000.
(3) The number of shares indicated consists of or includes 355,323 shares
    underlying options held by the directors and executive officers shown in
    the table, and an additional 92,006 shares underlying options held by
    other officers that currently are exercisable or that may become
    exercisable within 60 days following March 15, 2001.

                                      32
<PAGE>

(4) Based solely on information included in a Schedule 13G filed with the SEC
    by each of the named stockholders.
(5) The number of shares indicated includes the shares owned by entities
    related to State Farm Mutual Automobile Insurance Company ("SFMAI"). Those
    entities and SFMAI may be deemed to constitute a "group" with regard to
    the ownership of shares reported on a Schedule 13G. In their reports on
    Schedule 13G, the entities indicated that they disclaim membership in a
    group for the purposes of reporting on Schedule 13G or did not affirm the
    existence of a group.
(6) The number of shares indicated includes the shares owned by Franklin
    Resources, Inc. ("Franklin") and an individual and entity related to
    Franklin. Franklin, the individual and the additional entity may be deemed
    to constitute a "group" with regard to the ownership of shares reported on
    a Schedule 13G. In their reports on Schedule 13G, Franklin, the individual
    and the other entity indicated that they disclaim membership in a group
    for the purposes of reporting on Schedule 13G or did not affirm the
    existence of a group.
(7) The shares indicated are owned by various individuals and institutional
    investors which T. Rowe Price Associates, Inc. ("Price Associates") serves
    as investment adviser with power to direct investments and/or sole power
    to vote the securities. For purposes of the reporting requirements of the
    Exchange Act, Price Associates is deemed to be a beneficial owner of such
    securities; however, Price Associates expressly disclaims that it is, in
    fact, the beneficial owner of such securities.

Item 13. Certain Relationships and Related Transactions

   During 2000, there were no transactions between the Company and its
directors, executive officers or known holders of greater than five percent of
the Company's common stock in which the amount involved exceeded $60,000 and
in which any of the foregoing persons had or will have a material interest.

                                      33
<PAGE>

                                    PART IV

Item 14. Exhibits, Financial Schedules, and Reports on Form 8-K

   (a)(1) and (a)(2) Financial Statements And Financial Statement Schedules

        INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

<TABLE>
   <S>                                                                    <C>
   Report of Independent Public Accountants..............................  F-1
   Consolidated Balance Sheets at December 31, 2000 and 1999.............  F-2
   Consolidated Statements of Income for each of the three years in the
    period ended December 31, 2000.......................................  F-3
   Consolidated Statements of Stockholders' Equity for each of the three
    years in the period ended December 31, 2000..........................  F-4
   Consolidated Statements of Cash Flows for each of the three years in
    the period ended December 31, 2000...................................  F-5
   Notes to the Consolidated Financial Statements........................  F-6
   Supplemental Oil And Gas Information.................................. F-23
</TABLE>

   All other schedules are omitted because the required information is not
present in amounts sufficient to require submission of the schedule or because
the information required is included in the Consolidated Financial Statements
and Notes thereto.

   (a)(3) Exhibits

   See "EXHIBIT INDEX" on page   .

   (b) Reports on Form 8-K. A report on Form 8-K was filed November 15, 2000.

                                      34
<PAGE>

                         BARRETT RESOURCES CORPORATION

                           ANNUAL REPORT ON FORM 10-K

                      For The Year Ended December 31, 2000

                                 EXHIBIT INDEX

<TABLE>
<CAPTION>
 Exhibit                               Description
 -------                               -----------
 <C>     <S>
  2.1    Agreement And Plan of Merger, dated as of May 2, 1995, among Barrett
         Resources Corporation
         ("Barrett" or "Registrant"), Barrett Energy Inc. (formerly known as
         Vanilla Corporation), and
         Plains Petroleum Company ("Plains") is incorporated by reference from
         Annex I to the Joint Proxy
         Statement/Prospectus of Barrett and Plains dated June 13, 1995.

  3.1    Restated Certificate Of Incorporation of Barrett Resources
         Corporation, a Delaware corporation, is incorporated herein by
         reference from Exhibit 3.2 of Registrant's Registration Statement on
         Form S-4 dated June 9, 1995.

  3.2    Certificate of Amendment to Certificate of Incorporation of Barrett
         dated June 17, 1997 is incorporated by reference from Exhibit 3.2 of
         Registrant's Annual Report on Form 10-K for the year ended December
         31, 1997.

  3.3A   Bylaws of Barrett, as amended through February 25, 199 are
         incorporated by reference from Exhibit 3.3 of Registrant's Annual
         Report on Form 10-K for the year ended December 31, 1998.

  3.3B   Bylaw Amendments dated March 14, 2001 are incorporated by reference
         from Exhibit (a)(2)(xi) of Registrant's Schedule 14D-9 filed with the
         SEC on March 23, 2001.

  3.3C   Bylaw Amendment dated March 22, 2001.

  4.1A   Form of Rights Agreement dated as of August 5, 1997 between Barrett
         and BankBoston, N.A., which includes, as Exhibit A thereto, the form
         of Certificate of Designations specifying the terms of the Series A
         Junior Participating Preferred Stock, and as Exhibit B thereto, the
         form of Rights Certificate, is incorporated by reference from Exhibit
         1 to the Company's Registration Statement on Form 8-A filed August 11,
         1997.

  4.1B   Amendment to Rights Agreement dated August 5, 1997 between Barrett and
         BankBoston, N.A.

  4.2    Revised Form of Indenture between the Company and Bankers Trust
         Company, as trustee, with respect to Senior Notes including specimen
         of 7.55% Senior Notes is incorporated by reference from Exhibit 4.1 to
         the Company's Amendment No. 1 to Registration Statement on Form S-3
         filed February 10, 1997, File No. 333-19363.

  4.3    Form of Indenture between the Registrant and Bankers Trust Company, as
         trustee, with respect to Debt Securities is incorporated by reference
         from Exhibit 4.2 of Registrant's Registration Statement on Form S-3
         filed May 6, 1998 (File No. 333-51985).

 10.1    Non-Qualified Stock Option Plan Of Barrett Resources Corporation is
         incorporated by reference from Registrant's Registration Statement on
         Form S-8 dated November 15, 1989.

 10.2    Registrant's 1990 Stock Option Plan, as amended, is incorporated by
         reference from the Registrant's Registration Statement on Form S-8
         dated March 15, 1995.

 10.3    Registrant's Non-Discretionary Stock Option, as amended, is
         incorporated by reference from Exhibit 99.2 of the Registrant's Proxy
         Statement dated April 24, 1997.

 10.4    Registrant's 1994 Stock Option Plan, as amended, is incorporated by
         reference from the Registrant's Registration Statement on Form S-8
         dated March 15, 1995.

 10.5    Registrant's 1997 Stock Option Plan is incorporated by reference from
         Exhibit 99.1 of the Registrant's Proxy Statement dated April 24, 1997.
</TABLE>

                                       35
<PAGE>

<TABLE>

<CAPTION>
 Exhibit                               Description
 -------                               -----------
 <C>     <S>
 10.6A   Revolving Credit Agreement dated as of July 19, 1995 among Barrett and
         Texas Commerce Bank National Association, as Agent, and Texas Commerce
         Bank National Association, Nations Bank of Texas, N.A., Bank of
         Montreal, Houston Agency, Colorado National Bank, and The First
         National Bank of Boston, as the "Banks", is incorporated by reference
         from Exhibit 10.6 to Barrett's Annual Report on Form 10-K for the year
         ended December 31, 1995.

 10.6B   First Amendment to Revolving Credit Agreement dated October 31, 1996
         between and among Barrett, Agent and the Banks is incorporated by
         reference from Exhibit 10.1 to Amendment No. 2 to Barrett's
         Registration Statement on Form S-3 (File No. 333-19363) dated February
         10, 1997.

 10.6C   Second Amendment to Revolving Credit Agreement dated February 10, 1997
         between and among Barrett, the Agent, and the Banks is incorporated by
         reference from Exhibit 10.2 to Amendment No. 2 to Barrett's
         Registration Statement on Form S-3 (File No. 333-19363) dated February
         10, 1997.

 10.6D   Amended and Restated Credit Agreement dated November 12, 1997 between
         and among Barrett, the Agent, the Banks, and The Chase Manhattan Bank
         as the "Competitive Bid Auction Agent" is incorporated by reference
         from Exhibit 10.7D to Registrant's Annual Report on Form 10-K for the
         Year ended December 31, 1997.

 10.6E   First Amendment to Amended and Restated Credit Agreement dated
         December 19, 1997 between and among Barrett, the Agent, the Banks, and
         the Competitive Bid Auction Agent is incorporated by reference from
         Exhibit 10.7E to Registrant's Annual Report on Form 10-K for the year
         ended December 31, 1997.

 10.7    Revolving Credit Agreement among Barrett, as Borrower, Bank of
         America, N.A., as Administrative Agent and Issuing Lender, Banc of
         America Securities L.L.C., as Sole Lead Arranger and Book Manager,
         Bank One, NA, as Syndication Agent, Fleet National Bank, as
         Documentation Agent, and the Lenders Party to that agreement.

 10.8A   Severance Protection Agreement dated February 6, 1998 between
         Registrant and William J. Barrett is incorporated by reference from
         Exhibit 10.8 to Registrant's Annual Report on Form 10-K for the year
         ended December 31, 1997.

 10.8B   Amendment No. 1 to Severance Protection Agreement dated November 19,
         1998 between Registrant and William J. Barrett is incorporated by
         reference from Exhibit 10.8B of Registrant's Annual Report on Form 10-
         K for the year ended December 31, 1998.

 10.10A  Form of Severance Protection Agreement is incorporated by reference
         from Exhibit 10.9A to Registrant's Annual Report on Form 10-K for the
         year ended December 31, 1997.

 10.10B  Schedule Identifying Material Differences Among Severance Protection
         Agreements between Barrett and each of Peter A. Dea, Joseph N.
         Jaggers, A. Ralph Reed, J. Frank Keller, Eugene A. Lang, Jr. and Bryan
         G. Hassler.

 10.10C  Amendment No. 1 to Severance Protection Agreement dated February 9,
         1998 between Registrant and Peter A. Dea is incorporated by reference
         from Exhibit 10.8C to Registrant's Annual Report on Form 10-K for the
         year ended December 31, 1999.

 21      List of Subsidiaries.

 23.1    Consent of Arthur Andersen LLP.

 23.2    Consent of Ryder Scott Company L.P.

 23.3    Consent of Netherland, Sewell & Associates, Inc.
</TABLE>

                                       36
<PAGE>

                                   SIGNATURES

   Pursuant to the requirements of Section 13 or 15(d) of the Securities Act of
1934, the Registrant has duly caused this report to be signed on its behalf by
the undersigned, thereunto duly authorized.

                                          Barrett Resources Corporation

Date: March 30, 2001                                 /s/ Peter A. Dea
                                          By___________________________________
                                                       Peter A. Dea
                                             Chairman of the Board, and Chief
                                                     Executive Officer

Date: March 30, 2001                                /s/ John F. Keller
                                          By___________________________________
                                                      John F. Keller
                                               Chief Financial Officer, and
                                                    Principal Financial
                                                  and Accounting Officer

<TABLE>
<CAPTION>
              Signature                           Title                  Date
              ---------                           -----                  ----

 <C>                                  <S>                           <C>
 _______/s/ C. Robert Buford ________            Director           March 30, 2001
           C. Robert Buford

 _________/s/ Derrill Cody __________            Director           March 30, 2001
             Derrill Cody

 _________/s/ Peter A. Dea __________            Director           March 30, 2001
             Peter A. Dea

 _____/s/ James M. Fitzgibbons ______            Director           March 30, 2001
         James M. Fitzgibbons

 ____/s/ Hennie L.J.M. Gieskes ______            Director           March 30, 2001
         Hennie L.J.M. Gieskes

 ____/s/ William W. Grant, III ______            Director           March 30, 2001
         William W. Grant, III

 ___/s/ Philippe S.E. Schreiber _____            Director           March 30, 2001
        Philippe S.E. Schreiber
</TABLE>

                                       37
<PAGE>

                   REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Board of Directors and Stockholders of Barrett Resources Corporation:

   We have audited the accompanying consolidated balance sheets of Barrett
Resources Corporation (a Delaware corporation) and subsidiaries as of December
31, 2000 and 1999, and the related consolidated statements of operations,
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 2000. 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 financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Barrett
Resources Corporation and subsidiaries as of December 31, 2000 and 1999, and
the results of their operations and their cash flows for each of the three
years in the period ended December 31, 2000, in conformity with accounting
principles generally accepted in the United States.

                                          Arthur Andersen LLP

Denver, Colorado,
February 27, 2001.

                                      F-1
<PAGE>

                         BARRETT RESOURCES CORPORATION

                          CONSOLIDATED BALANCE SHEETS

                           December 31, 2000 and 1999
                (in thousands, except share and per share data)

<TABLE>
<CAPTION>
                                                               2000      1999
                                                            ---------- --------
<S>                                                         <C>        <C>
                          ASSETS
Current assets:
  Cash and cash equivalents................................ $   25,454 $ 20,634
  Receivables, net.........................................    297,766   99,906
  Gas inventory held for sale, at market...................     27,418   19,907
  Other current assets.....................................     29,042   14,075
                                                            ---------- --------
    Total current assets...................................    379,680  154,522
Net property and equipment (full cost method)..............    869,606  726,489
Other assets, net..........................................      4,547    3,290
                                                            ---------- --------
                                                            $1,253,833 $884,301
                                                            ========== ========

           LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
  Accounts payable......................................... $  234,739 $ 94,293
  Amounts payable to oil and gas property owners...........     18,672    5,879
  Production taxes payable.................................     39,229   22,981
  Accrued and other liabilities............................     20,917   16,610
  Unrealized mark to market transactions...................     47,745      --
                                                            ---------- --------
    Total current liabilities..............................    361,302  139,763
Long term debt.............................................    406,269  355,250
Deferred income taxes......................................     39,003   25,640
Unrealized mark to market transactions.....................     31,446      --

Commitments and contingencies

Stockholders' equity:
  Preferred stock, $.001 par value: 1,000,000 shares
   authorized, none outstanding............................        --       --
  Common stock, $.01 par value: 45,000,000 shares
   authorized, 33,394,063 and 32,589,774 shares issued and
   outstanding, respectively...............................        334      326
  Additional paid-in capital...............................    296,043  271,560
  Retained earnings........................................    119,436   91,762
                                                            ---------- --------
    Total stockholders' equity.............................    415,813  363,648
                                                            ---------- --------
                                                            $1,253,833 $884,301
                                                            ========== ========
</TABLE>


        The accompanying notes are an integral part of these statements.

                                      F-2
<PAGE>

                         BARRETT RESOURCES CORPORATION

                     CONSOLIDATED STATEMENTS OF OPERATIONS

                  Years ended December 31, 2000, 1999 and 1998
                     (in thousands, except per share data)

<TABLE>
<CAPTION>
                                                 2000       1999      1998
                                               ---------  --------  ---------
<S>                                            <C>        <C>       <C>
Operating revenues:
  Oil and gas production...................... $ 367,732  $209,977  $ 205,501
  Other income................................     8,700     5,023      6,267
                                               ---------  --------  ---------
                                                 376,432   215,000    211,768
Operating expenses:
  Lease operating expenses....................    56,272    40,486     44,588
  Transportation and gathering................    34,664    24,651     14,038
  Depreciation, depletion and amortization....   100,795    90,668    102,123
  General and administrative..................    26,065    23,849     24,546
  Impairment..................................       --        --     168,304
  Other.......................................       --        158      2,412
                                               ---------  --------  ---------
                                                 217,796   179,812    356,011
                                               ---------  --------  ---------
Operating income (loss) from oil and gas
 operations...................................   158,636    35,188   (144,243)
Other income and (expenses):
  Interest income.............................     1,561       826        649
  Interest expense............................   (25,455)  (21,521)   (20,858)
  Trading activities, net.....................   (88,800)   18,845     14,941
  Other.......................................    (1,305)      --         --
                                               ---------  --------  ---------
                                                (113,999)   (1,850)    (5,268)
                                               ---------  --------  ---------
Income (loss) before income taxes.............    44,637    33,338   (149,511)
Provision (benefit) for income taxes..........    16,963    12,510    (55,768)
                                               ---------  --------  ---------
Net income (loss)............................. $  27,674  $ 20,828  $ (93,743)
                                               =========  ========  =========
Earnings (loss) per common share
  Basic....................................... $    0.84  $   0.64  $   (2.95)
                                               =========  ========  =========
  Assuming dilution........................... $    0.83  $   0.64  $   (2.95)
                                               =========  ========  =========
Weighted average shares of common stock
 outstanding:
  Basic.......................................    32,873    32,307     31,756
                                               =========  ========  =========
  Assuming dilution...........................    33,324    32,790     31,756
                                               =========  ========  =========
</TABLE>

        The accompanying notes are an integral part of these statements.

                                      F-3
<PAGE>

                         BARRETT RESOURCES CORPORATION

                CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

                  Years ended December 31, 2000, 1999 and 1998
                        (in thousands except share data)

<TABLE>
<CAPTION>
                                    Additional                        Total
                             Common  Paid-In   Treasury Retained  Stockholders'
                             Stock   Capital    Stock   Earnings     Equity
                             ------ ---------- -------- --------  -------------
<S>                          <C>    <C>        <C>      <C>       <C>
Balances, January 1, 1998...  $314   $247,390   $  --   $164,677    $412,381
  Exercise of stock
   options..................     3      5,728     (233)      --        5,498
  Retirement of 8,280 shares
   of treasury stock........   --        (233)     233       --          --
  Stock issued in connection
   with property
   acquisitions.............     3      9,113      --        --        9,116
  Net loss..................   --         --       --    (93,743)    (93,743)
                              ----   --------   ------  --------    --------
Balances, December 31,
 1998.......................   320    261,998      --     70,934     333,252
  Exercise of stock
   options..................     4     10,353     (789)      --        9,568
  Exercise of put options...     2         (2)     --        --          --
  Retirement of 28,217
   shares of treasury
   stock....................   --        (789)     789       --          --
  Net income ...............   --         --       --     20,828      20,828
                              ----   --------   ------  --------    --------
Balances, December 31,
 1999.......................   326    271,560       --    91,762     363,648
  Exercise of stock
   options..................    10     25,865   (5,709)      --       20,166
  Tax benefit related to
   stock option exercises...   --       3,021      --        --        3,021
  Purchase of treasury
   stock....................   --         --        (1)      --           (1)
  Retirement of 167,853
   shares of treasury
   stock....................    (2)    (5,708)   5,710       --          --
  Compensation associated
   with acceleration of
   vesting stock options....   --       1,305      --        --        1,305
  Net income................   --         --       --     27,674      27,674
                              ----   --------   ------  --------    --------
Balances, December 31,
 2000.......................  $334   $296,043   $  --   $119,436    $415,813
                              ====   ========   ======  ========    ========
</TABLE>



        The accompanying notes are an integral part of these statements.

                                      F-4
<PAGE>

                         BARRETT RESOURCES CORPORATION

                     CONSOLIDATED STATEMENTS OF CASH FLOWS

                  Years ended December 31, 2000, 1999 and 1998
                                 (in thousands)

<TABLE>
<CAPTION>
                                                 2000       1999       1998
                                               ---------  ---------  ---------
<S>                                            <C>        <C>        <C>
Cash flows from operations:
  Net income (loss)........................... $  27,674  $  20,828  $ (93,743)
  Adjustments needed to reconcile to net cash
   flow provided by operations:
    Depreciation, depletion, amortization and
     impairment...............................   101,236     91,193    270,858
    Unrealized loss (gain) on mark to market
     transactions.............................    65,193     (1,379)       --
    Deferred income taxes.....................    15,936     12,347    (55,683)
    Other.....................................       946       (770)    (2,168)
                                               ---------  ---------  ---------
                                                 210,985    122,219    119,264
Change in current assets and liabilities:
  Receivables.................................  (197,860)    27,892    (24,864)
  Other current assets........................    (5,946)   (20,591)    (6,383)
  Accounts payable............................   140,446    (10,506)    42,929
  Amounts payable to oil and gas property
   owners.....................................    12,793    (10,141)   (11,154)
  Production taxes payable....................    16,248      2,581      2,455
  Accrued and other liabilities...............     1,844        776     (5,277)
                                               ---------  ---------  ---------
Net cash flow provided by operations..........   178,510    112,230    116,970
                                               ---------  ---------  ---------
Cash flows from investing activities:
  Proceeds from sales of oil and gas
   properties.................................    44,819     24,685      6,393
  Acquisitions of property and equipment......  (291,001)  (160,928)  (203,056)
                                               ---------  ---------  ---------
Net cash flow used in investing activities....  (246,182)  (136,243)  (196,663)
                                               ---------  ---------  ---------
Cash flows from financing activities:
  Proceeds from issuance of common stock......    20,166      9,568      5,498
  Proceeds from long term borrowing...........   575,060    100,000    119,000
  Payments on long term debt..................  (520,771)   (79,260)   (44,794)
  Treasury stock purchased....................        (1)       --         --
  Other.......................................    (1,962)       --        (151)
                                               ---------  ---------  ---------
Net cash flow provided by financing
 activities...................................    72,492     30,308     79,553
                                               ---------  ---------  ---------
Increase (decrease) in cash and cash
 equivalents..................................     4,820      6,295       (140)
Cash and cash equivalents at beginning of
 year.........................................    20,634     14,339     14,479
                                               ---------  ---------  ---------
Cash and cash equivalents at end of year...... $  25,454  $  20,634  $  14,339
                                               =========  =========  =========
</TABLE>


        The accompanying notes are an integral part of these statements.

                                      F-5
<PAGE>

                         BARRETT RESOURCES CORPORATION

                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

                       December 31, 2000, 1999 and 1998

1. BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 Business

   Barrett Resources Corporation (the "Company") is an independent natural gas
and oil exploration and production company with producing properties located
principally in the Rocky Mountain and Mid-Continent regions. The Company also
operates gas gathering systems and related facilities in certain areas in
which the Company owns production. In addition, the Company engages in natural
gas trading activities, which involves purchasing natural gas from and selling
natural gas to third parties. The Company also has exploration activities in
the Republic of Peru.

 Principles of consolidation

   The consolidated financial statements include the accounts of the Company
and its subsidiaries, all of which are wholly owned. All inter-company
transactions and amounts have been eliminated in consolidation.

 Reclassifications

   Certain reclassifications have been made to 1999 and 1998 amounts to
conform to the 2000 presentation. Also, in September 2000, the Emerging Issues
Task Force reached a consensus on issue No. 00-10, "Accounting for Shipping
and Handling Fees and Costs" ("EITF No. 00-10"), which requires shipping and
handling costs to be reflected as an operating expense rather than as a
reduction of revenue. The Company was required to adopt the provisions of EITF
No. 00-10 in the fourth quarter of 2000. Accordingly, the Company restated oil
and natural gas revenues for all periods presented to exclude the effects of
transportation costs and recorded such transportation costs as a separate line
in the statements of operations. Adoption of the provisions of EITF No. 00-10
had no impact on net income (loss).

 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 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. There are many factors, including global events that may influence
the production, processing, marketing, and valuation of crude oil and natural
gas. A reduction in the valuation of oil and gas properties resulting from
declining prices or production could adversely impact depletion rates and
ceiling test limitations.

 Partnerships

   The consolidated financial statements include the Company's proportionate
share of the assets, liabilities, revenues and expenses of its oil and gas
partnership interests. These partnership interests relate to oil and gas
producing properties.

 Cash and cash equivalents

   Cash in excess of daily requirements is invested overnight in Eurodollar
accounts or commercial paper with short-term maturities. Such investments are
deemed to be cash equivalents for purposes of the consolidated statements of
cash flows. The carrying amount of cash equivalents approximates fair value
because of the short maturity of those instruments.

                                      F-6
<PAGE>

                         BARRETT RESOURCES CORPORATION

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


 Credit Risk

   Financial instruments, which potentially subject the Company to
concentrations of credit risk, consist principally of temporary cash
investments, receivables, payables and derivative instruments. The Company
places its temporary cash investments with high credit quality financial
institutions. The Company's receivables and payables result from operation and
trading activities and are primarily due from many customers including amounts
due from oil and gas entities in the Rocky Mountain region and from industrial
end-users and local distribution companies. The Company routinely assesses the
financial strength of its customers. Due to the large number of customers,
concentrations of credit risk are limited. The Company analyzes the financial
condition of each counter party prior to entering into a transaction,
establishes credit limits and monitors the appropriateness of these limits on
an ongoing basis. Based on these assessments, the Company may require a
standby letter of credit or a financial guarantee. Traded futures and option
contracts entered into with the New York Mercantile Exchange ("Exchange") are
guaranteed by the Exchange and have nominal credit risk.

 Gas Inventory

   The Company engages in natural gas trading activities and holds natural gas
inventory for such purposes. Accordingly, natural gas inventory held in
storage is marked to market based upon future market prices in effect at the
end of the year. At December 31, 2000 and 1999 the average market value per
Mcf for inventory held in storage was $8.88 and $2.14, respectively.

 Oil and gas properties

   The Company utilizes the full cost method of accounting for oil and gas
properties whereby all productive and nonproductive costs paid to third
parties that are incurred in connection with the acquisition, exploration and
development of oil and gas reserves are capitalized. No gains or losses are
recognized upon the sale, conveyance or other disposition of oil and gas
properties except in transactions involving the conveyance of significant
amounts of oil and gas reserves.

   Capitalized costs are accumulated on a country-by-country basis subject to
a cost center ceiling and amortized using the units-of-production method. The
Company currently has two cost centers: the United States and the Republic of
Peru. Amortizable costs include estimated future development costs of proved
reserves and estimated dismantlement costs, but exclude the costs of
unevaluated oil and gas properties. Accumulated depreciation is written off as
assets are retired. Depletion and amortization equaled approximately $.80,
$.83 and $.92 per Mcfe ($4.81, $4.99 and $5.49 per BOE) during the years ended
December 31, 2000, 1999 and 1998, respectively. Included in accumulated
depletion, depreciation and amortization is the Company's accrual for future
abandonment costs. Total future abandonment costs of approximately $7.2
million are included in the depletable base. In 1998, the ceiling test
limitation resulted in the Company recognizing a pre-tax impairment expense of
$129 million and $39 million on its oil and gas properties located in the
United States and Peru, respectively.

   The Company leases non-producing acreage for its exploration and
development activities. The cost of these leases is included in unevaluated
oil and gas property costs recorded at the lower of cost or fair market value.

   The Company operates many of the wells in which it owns an economic
interest. The operating agreements for these activities provide for a fee
structure to allow the Company to recover a portion of its direct and overhead
charges related to its operating activities. The fees collected under the
operating agreements are recorded as a reduction of general and administrative
expenses. Any amounts collected from a sale of oil and gas interests or earned
as a result of assembling oil and gas drilling activities are applied to
reduce the book value of oil and gas properties.

                                      F-7
<PAGE>

                         BARRETT RESOURCES CORPORATION

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


 Other property and equipment

   Other property and equipment is recorded at cost. Renewals and betterments
which substantially extend the useful life of the assets are capitalized.
Maintenance and repairs are expensed when incurred. Depreciation is provided
using accelerated and straight-line methods over the estimated useful lives,
ranging from five to fifteen years, of the assets.

 Unamortized debt discount and expense

   Discounts and expenses incurred in connection with the issuance of
outstanding long term debt are amortized on a straight-line basis over the
terms of the respective issue.

 Amounts payable to oil and gas property owners

   Amounts payable to oil and gas property owners consist of cash calls from
working interest owners to pay for development costs of properties being
currently developed and production revenue that the Company, as operator, is
collecting and distributing to revenue interest owners.

 Trading activities

   The Company's business activities include the buying and selling of natural
gas. The Company currently recognizes revenue and costs on gas trading
transactions at the point in time when gas is purchased from the seller or
delivered to the purchaser. All trading revenues and expenses are presented on
a net basis in the accompanying financial statements. Contracts to purchase
and sell natural gas and derivative positions are marked to market at the end
of each reporting period in accordance with EITF Issue No. 98-10, "Accounting
for Contracts Involved in Energy Trading and Risk Management Activities". As
of December 31, 2000 and 1999, the Company, utilizing appropriate mark to
market criteria, recorded an unrealized gain (loss) on these contracts and
derivative positions of approximately ($80.6) million and $1.4 million,
respectively.

 Hedging activities

   The Company uses both commodity futures contracts and price swaps to hedge
the impact of price fluctuations on a portion of its production. The Company
enters into a hedging position for specific transactions that, in management's
opinion, may expose the Company to an unacceptable market price risk.

   Gains or losses on hedging transactions are deferred until the physical
transaction occurs for financial reporting purposes. Deferred gains and losses
and unrealized gains and losses are evaluated in connection with the physical
transaction underlying the hedge position. Gains or losses on hedging
activities are recorded in the consolidated statements of operations as
adjustments to oil and gas production. Hedging transactions are reported as
operating activities in the consolidated statements of cash flows.

 Earnings (loss) per share

   Earnings (loss) per share ("EPS") is based on the weighted-average number
of common shares outstanding (referred to as basic earnings (loss) per share)
and earnings per share giving effect to all dilutive potential common shares
that were outstanding during the reporting period (referred to as diluted
earnings (loss) per share or earnings (loss) per share-assuming dilution).

                                      F-8
<PAGE>

                         BARRETT RESOURCES CORPORATION

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   The following table reflects the amounts used in computing earnings (loss)
per share and the effect on income (loss) and the weighted average number of
shares of dilutive potential common stock.

<TABLE>
<CAPTION>
                                                       For the years ended
                                                           December 31
                                                     ------------------------
                                                      2000    1999     1998
                                                     ------- ------- --------
                                                          (in thousands)
   <S>                                               <C>     <C>     <C>
   Income (loss) available to common stockholders... $27,674 $20,828 $(93,743)
                                                     ======= ======= ========
   Weighted average number of common shares used in
    basic EPS.......................................  32,873  32,307   31,756
   Effect of dilutive securities (see Note 8):
     Stock options..................................     451     395      --
     Written put option.............................     --       88      --
                                                     ------- ------- --------
   Weighted average number of common shares and
    shares of dilutive potential common stock used
    in EPS--assuming dilution.......................  33,324  32,790   31,756
                                                     ======= ======= ========
</TABLE>

   On August 3, 1999, the holder of the written put option elected to exercise
such option and, accordingly, the Company issued 150,000 shares of its common
stock. In conjunction with the exercise of this option, the Company received
the holder's one percent interest in a subsidiary of the Company.

   Dilutive securities were not included in computing diluted EPS for 1998
because their effects were antidilutive.

 Recently Issued Accounting Standards

   In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133 ("SFAS 133"), "Accounting for
Derivative Instruments and Hedging Activities." SFAS 133 establishes
accounting and reporting standards requiring that every derivative instrument
(including certain derivative instruments embedded in other contracts) be
recorded in the balance sheet as either an asset or liability measured at its
fair value. It also requires that changes in the derivative's fair value be
recognized currently in earnings unless specific hedge accounting criteria are
met. Special accounting for qualifying hedges allows a derivative's gains and
losses to offset related results on the hedged item in the income statement,
and requires that a company must formally document, designate, and assess the
effectiveness of transactions that receive hedge accounting. The Company
adopted SFAS 133 on January 1, 2001.

   As of January 1, 2001, the Company held derivative positions on 57.4 Bcf of
its natural gas production. The fair value of these non-trading derivatives,
based on January 1, 2001 natural gas prices, was a negative $163.4 million.

   With the adoption of SFAS 133 on January 1, 2001, the Company will reflect
on its balance sheet an additional unrealized mark to market transaction
liability of $163.4 million, of which $101.6 million is current, and an income
tax benefit of $62.1 million. The Company's stockholders' equity will reflect
an accumulated other comprehensive loss, net of tax benefits, of $101.3
million.

2. ACQUISITIONS

   In January 2000, the Company acquired additional working interests in its
Piceance Basin gas properties located in northwestern Colorado and the
remaining joint venture interest in a related gas gathering system, processing
plant and pipeline from an industry partner for approximately $34.4 million.
In October 2000, the Company acquired interests in 54,675 gross and net acres
of coal bed methane properties with 58 producing wells

                                      F-9
<PAGE>

                         BARRETT RESOURCES CORPORATION

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

and a gas gathering and compression system in the Raton Basin in southern
Colorado, for a purchase price of approximately $52.9 million. The
acquisitions (accounted for under the purchase method) were financed with
borrowings from the Company's bank credit facilities.

3. RECEIVABLES AND PAYABLES

   The Company's Receivables as of December 31 are as follows:

<TABLE>
<CAPTION>
                                                                 2000    1999
                                                               -------- -------
                                                                (in thousands)
   <S>                                                         <C>      <C>
   Oil and gas revenue receivables............................ $ 97,639 $43,315
   Trading receivables........................................  180,907  41,002
   Joint interest billings....................................   11,555  10,625
   Other accounts receivable..................................    7,665   4,964
                                                               -------- -------
                                                               $297,766 $99,906
                                                               ======== =======

   As of December 31, 2000 and 1999, receivables are recorded net of allowance
for doubtful accounts of $1,017,000 and $1,912,000, respectively.

   The Company's Payables as of December 31 are as follows:

<CAPTION>
                                                                 2000    1999
                                                               -------- -------
                                                                (in thousands)
   <S>                                                         <C>      <C>
   Oil and gas trade payables................................. $ 32,862 $29,009
   Trading payables...........................................  201,877  65,284
                                                               -------- -------
                                                               $234,739 $94,293
                                                               ======== =======
</TABLE>

4. PROPERTY AND EQUIPMENT

<TABLE>
<CAPTION>
                                                            December 31
                                                       ----------------------
                                                          2000        1999
                                                       ----------  ----------
                                                          (in thousands)
   <S>                                                 <C>         <C>
   Oil and gas properties, full cost method:
     Unevaluated costs, not being amortized........... $   73,875  $   67,676
     Evaluated costs..................................  1,430,412   1,231,417
     Gas gathering systems............................     77,037      40,627
   Furniture, vehicles and equipment..................     14,146      12,375
                                                       ----------  ----------
                                                        1,595,470   1,352,095
   Less accumulated depreciation, depletion,
    amortization and impairment.......................   (725,864)   (625,606)
                                                       ----------  ----------
                                                       $  869,606  $  726,489
                                                       ==========  ==========
</TABLE>

                                     F-10
<PAGE>

                         BARRETT RESOURCES CORPORATION

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


5. UNEVALUATED OIL AND GAS PROPERTY COSTS

   Costs associated with unevaluated properties and major development projects
consist of the following:

<TABLE>
<CAPTION>
                                                 Costs incurred during
                                        ---------------------------------------
                                         2000    1999    1998    Prior   Total
                                        ------- ------- ------- ------- -------
                                                    (in thousands)
<S>                                     <C>     <C>     <C>     <C>     <C>
United States
  Acquisition costs.................... $12,127 $12,210 $19,192 $17,585 $61,114
  Exploration costs....................  10,957     167     741     211  12,076
Peru--Acquisition costs ...............     --      685             --      685
                                        ------- ------- ------- ------- -------
                                        $23,084 $13,062 $19,933 $17,796 $73,875
                                        ======= ======= ======= ======= =======
</TABLE>

   The unevaluated costs were incurred for projects which are being explored.
The Company anticipates that substantially all unevaluated costs will be
classified as evaluated costs within the next five years.

6. LONG-TERM DEBT

<TABLE>
<CAPTION>
                                                                For the years
                                                              ended December 31
                                                              -----------------
                                                                2000     1999
                                                              -------- --------
                                                               (in thousands)
   <S>                                                        <C>      <C>
   Line of Credit............................................ $248,000 $200,000
   7.55% Senior Notes........................................  150,000  150,000
   Production Payments.......................................   15,298    9,369
                                                              -------- --------
   Total.....................................................  413,298  359,369
   Less: current portion, included in other liabilities......    7,029    4,119
                                                              -------- --------
   Long-term debt............................................ $406,269 $355,250
                                                              ======== ========
</TABLE>

   The aggregate amounts of maturities on long-term debt for the next five
years are as follows: 2001, $7.0 million; 2002, $6.5 million; 2003, $1.8
million; 2004, zero; and 2005, $248.0 million.

 Line of Credit

   On December 15, 2000, the Company entered into a credit agreement with
lending banks that established a revolving senior credit facility (the "Line
of Credit") under which up to $350 million is available for loans and letters
of credit on a revolving basis. The Company has the option to increase the
maximum amount available under the Line of Credit to $450 million, subject to
certain terms and conditions. In addition, the Company may elect, or subject
to certain terms relating to the Company's senior unsecured debt rating, may
be required to permanently convert the Line of Credit to a reserve based
credit facility. The maturity date of the Line of Credit is December 15, 2005.

   The Company is required to pay interest only on its borrowings. At the
Company's option, funds may be borrowed at an interest rate equal to the
London Interbank Eurodollar Rate ("LIBOR") plus an applicable margin ranging
from 0.75 percent to 1.625 percent (depending on the Company's senior
unsecured debt rating); or alternatively, funds may be borrowed at a "Base
Rate" defined as the higher of (i) the Bank of America's prime rate and (ii)
the Federal Funds rate plus 0.50 percent plus an applicable margin ranging
from zero to 0.375 percent. For funds borrowed under the LIBOR rate, the
Company may select interest periods of one, two, three or six months with
interest payable at the end of the selected interest period, but not less
frequently than

                                     F-11
<PAGE>

                         BARRETT RESOURCES CORPORATION

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

quarterly. Interest with respect to Base Rate loans is payable quarterly. At
December 31, 2000, the Company's outstanding balance under the Line of Credit
was $248 million of which $210 million was accruing interest at an average
LIBOR rate of 7.89 percent and $38 million accruing interest at a Base Rate of
9.50 percent.

   Under the Line of Credit the Company is required to pay quarterly
commitment fees ranging between 0.175 percent and 0.50 percent (based on the
Company's senior unsecured debt rating) on the unused portion of the maximum
amount available for borrowing. At December 31, 2000, the Company had $63
million of unused commitment amount under the Line of Credit. The Company is
also required to pay quarterly fees associated with outstanding letters of
credit ranging between 0.75 percent and 1.625 percent (based on the Company's
senior unsecured debt rating) plus a fronting fee of 0.125 percent.

   The credit agreement associated with the Line of Credit places restrictions
on the payment of dividends, borrowings, sales of assets, loans to others and
investment and merger activity over certain limits and requires the Company to
maintain defined net worth and debt to equity levels. The Company is in
compliance with all debt covenants.

 7.55% Senior Notes

   In February 1997, the Company completed a public offering of $150 million
(principal amount) of its 7.55% Senior Notes due 2007 ("Notes"). A portion of
the net proceeds from the offering was used to repay the Company's then
existing line of credit. The Notes are senior unsecured obligations of the
Company ranking equally in right of payment to all existing and future senior
indebtedness of the Company. At the option of the Company, the Notes may be
redeemed at any time, in whole or in part, by paying an amount specified for a
make-whole premium. The indenture of the Notes limits the Company's ability to
incur indebtedness secured by certain liens, engage in certain sale/leaseback
transactions, and engage in certain merger, consolidation or reorganization
transactions. Interest is paid semi-annually on February 1 and August 1 of
each year.

 Production Payments

   In November 1997, the Company sold its interest in certain Colorado
properties to an investment group. For accounting purposes, the Company has
treated the sale as a non-recourse monetary production payment reflected in
long-term liabilities on the balance sheet. Net of transaction costs, the
proceeds from the original sale were approximately $15.5 million in cash. In
May of 2000, the Company sold an additional interest in the properties to the
same investment group for net proceeds of approximately $9.6 million. Payments
of the production payment liability are funded from the operating cash flow of
the properties, less funds required for working capital purposes. The
liability is expected to be fully repaid by 2003.

 Fair value of financial instruments

   The estimated fair values of the Company's financial instruments are:

<TABLE>
<CAPTION>
                                                              Carrying   Fair
                                                               Amount   Value
                                                              -------- --------
                                                               (in thousands)
   <S>                                                        <C>      <C>
   2000
   Cash and cash equivalents................................. $ 25,454 $ 25,454
   Long-term debt (including current portion)................  413,298  412,639

   1999
   Cash and cash equivalents................................. $ 20,634 $ 20,634
   Long-term debt (including current portion)................  359,369  349,807
</TABLE>

                                     F-12
<PAGE>

                         BARRETT RESOURCES CORPORATION

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   The carrying amounts of accounts receivable, accounts payable and accrued
liabilities approximate fair value because of the short-term nature of these
instruments.

   The fair value of the Company's long-term debt is estimated based on
current rates and re-pricing terms available to the Company for its Line of
Credit and on quoted market prices for the 7.55% Senior Notes.

   Outstanding letters of credit totaled approximately $40.3 million of which
$39 million is secured by the Company's Line of Credit, at December 31, 2000.
The letters of credit guarantee performance to third parties. The Company does
not expect any losses due to non-performance and, therefore, believes that the
fair value of these instruments is zero.

7. RATIO OF EARNINGS TO FIXED CHARGES

   The Company's ratio of earnings to fixed charges was as follows for each of
the years then ended:

<TABLE>
   <S>                                                                 <C>
   2000...............................................................  2.3 to 1
   1999...............................................................  2.5 to 1
   1998...............................................................     n/a
   1997...............................................................  4.4 to 1
   1996............................................................... 11.7 to 1
</TABLE>

   For purposes of computing the ratio of earnings to fixed charges, earnings,
including the impact of mark to market adjustments, are computed as net income
(loss) before income taxes, plus fixed charges. Fixed charges consist of
interest expense, whether expensed or capitalized, on all indebtedness plus
amortization of debt issuance costs. For the year ended December 31, 1998,
earnings were not sufficient to cover historical fixed charges due to a $168
million non-cash charge for impairment relating to the Company's oil and gas
properties. Excluding the effect of the impairment, the ratio of earnings to
fixed charges for 1998 was 1.8.

8. COMMON STOCK AND STOCK OPTIONS

 Common Stock

   In August 1999, the holder of a written put option, issued by the Company
in April 1997 in conjunction with a property acquisition, elected to exercise
such option. Pursuant to the terms of this option, the Company issued 150,000
shares of its common stock and, in return, received the holder's one percent
interest in a subsidiary of the Company.

   In March 1998, the Company issued 260,917 shares of its common stock in an
acquisition of a company whose sole asset is a 15 percent interest in an oil
and gas license covering an area denominated as Block 67 located in the
Republic of Peru.

   During 2000, 1999 and 1998, the Company acquired treasury stock only as a
result of stock option exercises or the buy back of shares, which were
unsolicited from stockholders. Treasury stock acquired during any year was
retired at the end of that year.

   The Company has a stockholders rights plan designed to insure that
stockholders receive full value for their shares in the event of certain
takeover attempts.

                                     F-13
<PAGE>

                         BARRETT RESOURCES CORPORATION

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


 Stock Options

   The Company has four employee stock option plans, a 1994 Plan, a 1997 Plan,
a 1999 Plan and a 2000 Plan, under which the Company's common stock may be
granted to officers and other employees of the Company and subsidiaries. The
1994 Plan as amended, the 1997 Plan, the 1999 Plan and the 2000 Plan provide
for the granting of options to purchase 1,000,000, 1,500,000, 600,000 and
600,000 shares of the Company's common stock, respectively. In addition, the
Company has a non-discretionary stock option plan, as amended, under which
options for an aggregate of 300,000 shares of the Company's common stock may
be granted to non-employee directors. Effective with the 1995 merger of the
Company and Plains Petroleum Company ("Plains"), the Company assumed
preexisting stock option plans of Plains and converted all options then
outstanding into options to acquire shares of the Company's common stock. No
further options will be granted under the Plains' plans.

   Pursuant to the plans, the exercise price of each option cannot be less
than the market price of the Company's stock on the date of grant. Options
under the Company's plans generally become exercisable in equal installments
on each of the first four anniversaries of the date of grant. All options
granted under the Plains option plans are currently exercisable. The options
expire, to the extent not exercised, between five and ten years after the date
of the grant, or within 90 days (30 days under the Plains' plan) after the
recipient's termination of employment with the Company. Options can be
incentive stock options or non-statutory stock options.

   Changes in outstanding stock options under these plans are summarized as
follows:

<TABLE>
<CAPTION>
                                  2000                  1999                  1998
                          --------------------- --------------------- ---------------------
                                      Weighted-             Weighted-             Weighted-
                          Number of    Average  Number of    Average  Number of    Average
                            Option    Exercise    Option    Exercise    Option    Exercise
                            Shares      Price     Shares      Price     Shares      Price
                          ----------  --------- ----------  --------- ----------  ---------
<S>                       <C>         <C>       <C>         <C>       <C>         <C>
Outstanding at beginning
 of year................   2,710,824   $27.68    2,609,876   $28.63    2,088,208   $26.29
Granted.................     329,750    31.66      763,945    21.85    1,253,307    30.10
Exercised...............    (972,142)   26.61     (465,687)   22.24     (344,139)   16.96
Forfeited...............    (329,427)   29.86     (197,310)   30.46     (387,500)   31.15
                          ----------            ----------            ----------
Outstanding at end of
 year...................   1,739,005   $28.63    2,710,824    27.68    2,609,876    28.63
                          ==========            ==========            ==========
Options exercisable at
 year-end...............     608,133               990,559               959,326
Weighted-average fair
 value of options
 granted during the
 year...................  $    16.31            $    11.39            $    17.27
</TABLE>

   The calculated value of stock options granted under these plans, following
calculation methods prescribed by SFAS 123, uses the Black-Scholes stock
option pricing model with the following weighted-average assumptions used:

<TABLE>
<CAPTION>
                                                            2000   1999   1998
                                                            -----  -----  -----
   <S>                                                      <C>    <C>    <C>
   Expected option life--years.............................  4.49   4.82   5.54
   Risk-free interest rate.................................  6.14%  5.47%  5.19%
   Dividend yield..........................................     0      0      0
   Volatility.............................................. 54.80% 55.33% 56.87%
</TABLE>

                                     F-14
<PAGE>

                         BARRETT RESOURCES CORPORATION

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   The following table summarizes information about stock options outstanding
at December 31, 2000:

<TABLE>
<CAPTION>
                               Stock Options Outstanding              Stock Options Exercisable
                     ---------------------------------------------- -----------------------------
                         Number     Weighted-Average   Weighted-        Number       Weighted-
      Range of       Outstanding at    Remaining        Average     Exercisable at    Average
   Exercise Prices      12/31/00    Contractual Life Exercise Price    12/31/00    Exercise Price
   ---------------   -------------- ---------------- -------------- -------------- --------------
   <S>               <C>            <C>              <C>            <C>            <C>
   $15--20               305,497          4.7            $16.55         66,939         $16.96
    20--25               247,187          4.3             23.33        101,687          23.06
    25--30               247,970          5.6             27.29         37,220          27.36
    30--35               728,676          4.0             32.95        330,612          32.89
    35--40               100,750          3.9             36.43         53,250          36.65
    40--43               108,925          5.7             41.41         18,425          42.58
                       ---------          ---            ------        -------         ------
                       1,739,005          4.5            $28.63        608,133         $29.78
                       =========                                       =======
</TABLE>

   The Company applies APB Opinion No. 25 and related interpretations in
accounting for stock options. Accordingly, no compensation cost has been
recognized for its grant of stock options. Had compensation cost for the grant
of stock options been determined based on fair value at grant dates since
1996, as presented by SFAS No. 123, the Company's net income (loss) and
earnings (loss) per share would have been the pro forma amounts indicated
below.

<TABLE>
<CAPTION>
                                                         For the Year Ended
                                                             December 31
                                                      -------------------------
                                                       2000    1999     1998
                                                      ------- ------- ---------
                                                           (in thousands)
   <S>                                                <C>     <C>     <C>
   Net income (loss)
     As reported..................................... $27,674 $20,828 $ (93,743)
     Pro forma....................................... $23,608 $12,832 $(101,008)
   Net income (loss) per share
     As reported
       Basic......................................... $   .84 $   .64 $   (2.95)
       Diluted....................................... $   .83 $   .64 $   (2.95)
     Pro forma
       Basic......................................... $   .72 $   .40 $   (3.18)
       Diluted....................................... $   .71 $   .39 $   (3.18)
</TABLE>

   In 2000, the Company accelerated the vesting of stock option grants to two
employees to occur upon the date of their retirement. This event resulted in
the Company measuring the amount of compensation expense to these employees at
the date of modification. Compensation expense is being recognized over the
estimated remaining service period for these individuals.

9. RETIREMENT BENEFITS

   The Company has a voluntary 401(k) employee savings plan. Under this plan,
as amended, the Company matches 100 percent of each participating employee's
contribution, up to a maximum of 6 percent of base salary, with one-half of
the match paid in cash invested as directed by the employee and one-half of
the match paid in the Company's common stock. The employee's rights to the
Company's matching contributions are subject to a vesting schedule. Company
contributions were $624,000, $607,000 and $675,000 in 2000, 1999 and 1998,
respectively.

                                     F-15
<PAGE>

                         BARRETT RESOURCES CORPORATION

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   Pursuant to a 1995 merger agreement between Plains and the Company, Plains'
employee benefit plans were terminated and plan assets were distributed to the
participants. A final distribution for Plains' executive deferred compensation
plan and directors' deferred plan was made to the participants by the trustee
of the assets in January 1998.

10. DERIVATIVES

 Production Activities

   The Company uses swap agreements to reduce the effect of price and
transportation cost volatility on a portion of its natural gas production. In
a typical swap agreement, on a monthly basis for the term of the swap
agreement, the Company receives or pays the difference between a fixed price
per unit of production and a price based on an agreed-upon third party index.
The Company reviews and monitors the credit standing of the counter party to
each of its swap agreements and believes that the counter party will fully
comply with its contractual obligations.

   As of December 31, 2000, the Company had in effect outstanding natural gas
swaps associated with its Rocky Mountain natural gas production of 57.4 Bcf at
varying volumes per month through March 2003. Fixed prices associated with
these swaps range from $ 1.6376 to $ 2.84 per MMBtu. As of December 31, 2000,
these contracts had a negative fair value of $163.4 million. The Company does
not have any derivatives on its oil production as of December 31, 2000.

   For the years ended December 31, 2000, 1999 and 1998, the Company's losses
under its natural gas production swap agreements were $47.8 million, $8.3
million and $0.7 million, respectively. For 1999, the Company recognized
hedging losses of approximately $4.6 million under its oil production swap
agreements. The Company did not enter into hedging positions for its oil
production in 2000 or 1998.

 Trading Activities

   As of December 31, 2000, the Company had entered into a variety of
contracts to purchase and sell natural gas and oil at both fixed prices and at
index based prices. The Company also enters into financial instruments
(derivatives) that seek to reduce sensitivity to price movements or to create
guaranteed margins on certain delivery and purchase commitments. The fair
value of these contracts and financial instruments as of December 31, 2000 was
an estimated net negative of $79.2 million. Net trading activities include net
unrealized mark to market losses of $65.2 million, including a natural gas
inventory unrealized gain of $15.4 million, and gains of $1.4 million, in 2000
and 1999, respectively. Gross trading activities are summarized in the table
below.

<TABLE>
<CAPTION>
                                               2000        1999       1998
                                            -----------  ---------  ---------
                                                    (in thousands)
   <S>                                      <C>          <C>        <C>
   Revenues, gross......................... $ 1,350,800  $ 792,016  $ 412,982
   Operating expenses, gross...............  (1,374,407)  (774,550)  (398,041)
                                            -----------  ---------  ---------
                                                (23,607)    17,466     14,941
   Unrealized (losses) gains on mark to
    market transactions....................     (65,193)     1,379        --
                                            -----------  ---------  ---------
   Net trading (loss) income............... $   (88,800) $  18,845  $  14,941
                                            ===========  =========  =========
</TABLE>

                                     F-16
<PAGE>

                         BARRETT RESOURCES CORPORATION

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


11. COMMITMENTS AND CONTINGENCIES

 Lease Commitments

   The minimum future payments under the terms of operating leases,
principally for office space, are as follows:

<TABLE>
<CAPTION>
                                                         Years ended December 31
                                                         -----------------------
                                                             (in thousands)
   <S>                                                   <C>
   2001.................................................         $ 1,159
   2002.................................................           1,171
   2003.................................................           1,302
   2004.................................................           1,305
   2005.................................................           1,283
   Thereafter...........................................           7,238
                                                                 -------
                                                                 $13,458
                                                                 =======
</TABLE>

   Rent expense was $1,241,000, $1,305,000 and $1,282,000 for the years ended
December 31, 2000, 1999 and 1998, respectively.

 Firm Transportation Commitments

   The Company has executed firm transportation commitments to ensure the
transportation and sale of its gas production in the Rocky Mountain region.
The Company's obligation for such firm transportation contracts for the next
five years and thereafter is as follows:

<TABLE>
<CAPTION>
                                                         Years Ended December 31
                                                         -----------------------
                                                             (in thousands)
   <S>                                                   <C>
   2001.................................................        $ 34,723
   2002.................................................          38,279
   2003.................................................          45,451
   2004.................................................          42,513
   2005.................................................          44,064
   Thereafter...........................................         231,692
                                                                --------
                                                                $436,722
                                                                ========
</TABLE>

   In October 2000, the Company entered into a ten year firm transportation
commitment to move its gas on a pipeline to be placed in service in May 2002.
In January 2001, for consideration of $20.0 million, the Company assigned its
rights and obligations for a 34 month period of the ten year commitment
commencing July 1, 2002. The Company is obligated to refund all or some of the
consideration if, in the unlikely event, the pipeline is not constructed or
its in-service date is delayed. The commitment and assignment are reflected in
the Company's transportation commitments in the above table.

 Guarantee of Indebtedness

   The Company, as a ten percent owner of a limited liability company
operating a gas gathering system in the Powder River Basin of Wyoming, has
guaranteed its pro rata share of that company's notes payable. At December 31,
2000, the balance of the notes was $37 million, of which the Company's pro
rata share of the liability under its guarantee is $3.7 million. The Company
has not been required to pay any amounts related to the notes, nor does it
expect to be required to pay any amounts in the future.

                                     F-17
<PAGE>

                         BARRETT RESOURCES CORPORATION

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


 Litigation

  Kansas Ad Valorem Tax Refund

   Pursuant to an August 1996 decision of the United States Court of Appeals
for the District of Columbia Circuit and subsequent orders of the FERC,
natural gas producers who received reimbursement for Kansas ad valorem taxes
paid in the mid-1980's on top of the then maximum lawful price for natural gas
have been ordered to refund these tax reimbursements plus interest. In
connection with this decision, the Company has refunded $5.46 million
(principal and interest), including an escrowed refund of $1.21 million
attributable to royalty interest owners. In July 1999, the Company filed suit
in Kansas state district court to recover the amount attributed to the royalty
owners. In January 2001, the court ruled the statute of limitation had expired
and additionally, "changed circumstances" precluded the claim. The Company has
filed an appeal with the Kansas Supreme Court. If that appeal is unsuccessful,
the Company will file an application with FERC seeking relief from any
obligation with respect to the royalty owner portion of the refund. The
Company will only be financially obligated for the royalty related refunds
should the appeal be unsuccessful or if unable to obtain FERC relief from any
portion of the royalty related refund.

  Litigation Concerning Shell Oil Company Offer

   The Company is involved in various lawsuits in connection with the
unsolicited tender offer (the "Shell Offer") commenced by Shell Oil Company,
acting through its indirect wholly-owned subsidiary SRM Acquisition Company
("Sub"), on March 12, 2001 to acquire the Company's outstanding common stock
for $55.00 per share. The following is a summary of these lawsuits.

   On March 7, 2001, Shell filed a complaint against Barrett in the Delaware
Court of Chancery. The Shell complaint sought an order declaring Article III,
Section 3 of the Barrett Bylaws to be in violation of Section 228 of the
Delaware corporate law. Article III, Section 3 provides that nominations by
stockholders for directors to be elected by written consent must be delivered
in writing to the Barrett Corporate Secretary not less than 60 days nor more
than 90 days prior to the first solicitation of any written consents for the
election of those nominees. In addition, Shell asked the Court to enjoin
Barrett, or anyone acting on Barrett's behalf or in concert with Barrett, from
enforcing Article III, Section 3. The Shell complaint also seeks an order
declaring Article IX, Section 4 of the Barrett Bylaws to be in violation of
Section 228 of the Delaware corporate law and again asks the Court to enjoin
Barrett, or anyone acting on Barrett's behalf or in concert with Barrett, from
enforcing that Bylaw. Article IX, Section 4 provides that the Barrett Bylaws
may be amended at a meeting of stockholders, but not by their written consent,
and includes certain requirements of advance notice of the proposed amendment
to Barrett and the Barrett Board. On March 12, 2001, Shell filed an amended
complaint adding Sub as a plaintiff and the individual directors of Barrett as
defendants. Shell alleges that the Barrett directors have breached their
fiduciary duties by failing to amend the Bylaws that allegedly violate state
law. On March 12, 2001, Shell also filed a motion with the Court seeking an
expedited proceeding for matters asserted in its complaint. On March 14, 2001,
Barrett amended the Bylaws to delete the two provisions that are the subject
of this litigation.

   On March 12, 2001, Shell and Sub filed a complaint against Barrett in the
United States District Court for the District of Delaware. The complaint seeks
an order declaring that Shell's proposed solicitation of written consents of
Barrett's stockholders to remove Barrett's directors and replace them with
Shell's nominees (the "Shell Consent Solicitation"), the Shell tender offer
documents and other documents filed with the SEC comply with all federal laws.
In addition, the complaint asks the Court to enjoin Barrett, or anyone acting
on Barrett's behalf or in concert with Barrett, from commencing in any other
forum litigation that relates to the Shell Consent Solicitation or the Shell
Offer or any matters concerning them.

   Several actions have been filed against Barrett and the Barrett Board in
the Delaware Court of Chancery on behalf of a purported class of Barrett
stockholders. Although containing slightly different allegations, all of the
complaints allege that the Board is violating its fiduciary duties to
stockholders. The various actions ask the Court

                                     F-18
<PAGE>

to order the Board to evaluate Barrett's net worth, to inform itself about the
Shell Offer and other potential acquirers, to enhance Barrett's value, to
negotiate with Shell and to conduct an auction for Barrett. Some of the
complaints also challenge the Company's Rights Agreement concerning preferred
stock purchase rights associated with the Common Stock and the two recently
deleted Bylaws challenged in Shell's suit in the Delaware Court of Chancery.
In addition to the injunctions, the actions request payment of their alleged
damages and plaintiffs' attorneys' fees.

   Two actions have been filed against Barrett and the Barrett Board in the
District Court for the City and County of Denver, Colorado on behalf of a
purported class of Barrett stockholders. These actions allege that the Board
will violate its fiduciary duties to stockholders if it allows Barrett to
consummate the Shell Offer. The actions ask the Court to enjoin the Board from
agreeing to the Shell Offer and to require the Board to implement a fair
process in order to sell the Company in a way that maximizes stockholder
value.

  Other Legal Proceedings

   At December 31, 2000, the Company was a party to certain other legal
proceedings, which have arisen out of the ordinary course of business. Based
on the facts currently available, in management's opinion the liability,
individually or in the aggregate, if any, to the Company resulting from such
actions, including those specifically mentioned above, will not have a
material adverse effect on the Company's consolidated financial position or
results of operations.

 Environmental

   At year-end 2000, there were no known environmental or other regulatory
matters related to the Company's operations which are reasonably expected to
result in a material liability to the Company. Compliance with environmental
laws and regulations has not had, and in management's opinion is not expected
to have, a material adverse effect on the Company's capital expenditures,
results of operations or competitive position.

12. INCOME TAXES

   The provision for income taxes consists of the following:

<TABLE>
<CAPTION>
                                                        2000    1999     1998
                                                       ------- ------- --------
                                                            (in thousands)
   <S>                                                 <C>     <C>     <C>
   Current
     Federal.........................................  $   512 $   --  $   (175)
     State...........................................       66     163       90
                                                       ------- ------- --------
                                                           578     163      (85)
   Deferred
     Federal.........................................   15,091  11,680  (51,287)
     State...........................................    1,294     667   (4,396)
                                                       ------- ------- --------
                                                        16,385  12,347  (55,683)
                                                       ------- ------- --------
                                                       $16,963 $12,510 $(55,768)
                                                       ======= ======= ========
</TABLE>

   The difference between the provision for income taxes and the amounts,
which would be determined by applying the statutory federal income tax rate,
to income (loss) before provision for income taxes is analyzed below:

<TABLE>
<CAPTION>
                                                    2000     1999     1998
                                                   -------  ------- --------
                                                        (in thousands)
   <S>                                             <C>      <C>     <C>
   Tax by applying the statutory federal income
    tax rate to pretax accounting income (loss)... $15,623  $11,668 $(52,323)
   Increase (decrease) in tax from:
     State income taxes...........................   1,360      830   (4,306)
     Other, net...................................     (20)      12      861
                                                   -------  ------- --------
                                                   $16,963  $12,510 $(55,768)
                                                   =======  ======= ========
</TABLE>


                                     F-19
<PAGE>

                         BARRETT RESOURCES CORPORATION

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

   Long-term deferred tax assets (liabilities) are comprised of the following
at December 31, 2000 and 1999:

<TABLE>
<CAPTION>
                                                            2000       1999
                                                          ---------  ---------
                                                            (in thousands)
   <S>                                                    <C>        <C>
   Deferred tax assets:
     Allowance for losses................................ $      40  $   3,216
     Mark to market......................................    26,293        --
     Loss carryforwards and other........................    79,288     85,353
                                                          ---------  ---------
       Gross deferred tax assets.........................   105,621     88,569
   Deferred tax liabilities:
     Depreciation, depletion and amortization............  (142,624)  (106,972)
     Partnership activity................................       --      (4,091)
     Capitalized interest and other assets...............       --        (546)
                                                          ---------  ---------
       Gross deferred tax liabilities....................  (142,624)  (111,609)
                                                          ---------  ---------
   Net deferred tax liability............................   (37,003)   (23,040)
   Valuation allowance...................................    (2,000)    (2,600)
                                                          ---------  ---------
                                                          $ (39,003) $ (25,640)
                                                          =========  =========
</TABLE>

   Valuation allowances of $2.0 million and $2.6 million were provided at
December 31, 2000 and 1999, respectively, based on carryforward amounts, which
may not be utilized before expiration.

   The Company has net operating loss carryforwards available totaling $211.5
million, which expire in the years 2001 through 2020. The Company also has AMT
tax credits of $2.9 million.

   The tax benefits of compensation expense for tax purposes in excess of
amounts recognized for financial accounting purposes has been credited
directly to stockholders' equity.

   The 1995 merger with Plains also resulted in a change in the Company's and
Plains' ownership as defined by Section 382 of the Internal Revenue Code. The
change effectively limits the annual utilization of the Company's and Plains'
remaining net operating losses arising prior to the merger to approximately
$15.8 million per year for the Company. Portions of the above limitations
which are not used each year may be carried forward to future years.

13. SUPPLEMENTAL CASH FLOW SCHEDULES AND INFORMATION

<TABLE>
<CAPTION>
                                                         2000    1999    1998
                                                        ------- ------- -------
                                                            (in thousands)
   <S>                                                  <C>     <C>     <C>
   Cash paid during years
     Income tax........................................ $   368 $ 3,927 $   130
     Interest..........................................  29,514  21,207  20,384
   Supplemental information of noncash investing and
    financing activities:
     Issuance of common stock exchanged for treasury
      shares in cashless option transactions with
      mature shares.................................... $ 5,709 $   789 $   233
     Compensation associated with acceleration of
      vesting stock option............................. $ 1,305     --      --
</TABLE>


                                     F-20
<PAGE>

                         BARRETT RESOURCES CORPORATION

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

   In March 1998, the Company issued 260,917 shares of common stock with a
market value of $9.1 million in an acquisition of a company. The acquired
company's sole asset was a 15 percent interest in an oil and gas license in
the area denominated as Block 67 located in the Republic of Peru.

   During each of the three years ended December 31, 2000, the Company's
production payment obligations were reduced by certain tax credit benefits of
$.4 million, $.8 million and $2.2 million, respectively, directly attributed
to the properties burdened by the production payment and received by the
holder of the production payment liability. The non monetary benefit to the
Company was recognized as income.

   During 1997, in separate transactions, the Company assumed a production
payment with a value of $2.8 million and issued a written put option on
150,000 shares of the Company's common stock with a market value of $4.2
million (at the date of issue) in connection with acquisitions of interests in
oil and gas properties located in the Uinta and Piceance Basins, respectively.
In August 1999, the owner of the written put option elected to exercise such
option, and accordingly the Company issued 150,000 shares of its common stock.

14. BUSINESS SEGMENT INFORMATION

   The Company operates principally in two business segments: oil and gas
exploration and production and natural gas trading. In addition to marketing
its own gas, the Company engages in natural gas trading activities, which
involves purchasing natural gas from and selling natural gas to third parties
at prices and volumes that management anticipates will result in profits to
the Company. The Company evaluates segment performance based on the profit or
loss from operations before income taxes. Corporate general and administrative
expenses are unallocated except for certain direct costs associated with the
Company's trading activity. Consolidated and segment financial information is
as follows:

<TABLE>
<CAPTION>
                                        Natural
                             Oil & Gas    Gas      Segment   Corporation &
                                E&P     Trading    Totals     Unallocated  Consolidated
                             ---------  --------  ---------  ------------- ------------
                                                 (in thousands)
   <S>                       <C>        <C>       <C>        <C>           <C>
   2000
   Revenues................  $ 368,122  $    --   $ 368,122    $  8,310     $  376,432
   DD&A....................     94,236       --      94,236       6,559        100,795
   Unrealized losses on
    mark to market
    transactions...........        --    (65,193)   (65,193)        --         (65,193)
   Profit (loss)...........    182,950   (90,174)    92,776     (48,139)        44,637
   Assets..................    863,252       --     863,252     390,581      1,253,833
   Expenditures for assets,
    net....................    243,873       --     243,873       2,309        246,182


   1999
   Revenues................  $ 210,226  $    --   $ 210,226    $  4,774     $  215,000
   DD&A....................     86,163       --      86,163       4,505         90,668
   Unrealized gains on mark
    to market
    transactions...........        --      1,379      1,379         --           1,379
   Profit (loss)...........     58,926    17,514     76,440     (43,102)        33,338
   Assets..................    720,453       --     720,453     163,848        884,301
   Expenditures for assets,
    net....................    134,439       --     134,439       1,804        136,243


   1998
   Revenues................  $ 206,338  $    --   $ 206,338    $  5,430     $  211,768
   DD&A....................     97,957       --      97,957       4,166        102,123
   Impairment..............    168,304       --     168,304         --         168,304
   Profit (loss)...........   (118,549)   13,782   (104,767)    (44,744)      (149,511)
   Assets..................    676,228       --     676,228     162,651        838,879
   Expenditures for assets,
    net....................    202,912       --     202,912       2,867        205,779
</TABLE>


                                     F-21
<PAGE>

                         BARRETT RESOURCES CORPORATION

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

   The Company's revenues are derived in the United States and Canada. The
Company's long-lived assets are principally located in the United States.

15. QUARTERLY INFORMATION (UNAUDITED)

<TABLE>
<CAPTION>
                                                   Three Months Ended
                                            -----------------------------------
                                            3/31/00 6/30/00   9/30/00  12/31/00
                                            ------- --------  -------  --------
                                             (in thousands, except per share
                                                          data)
   <S>                                      <C>     <C>       <C>      <C>
   2000
   Revenues................................ $69,109 $ 83,865  $98,297  $125,161
   Income from operations..................  18,215   33,335   42,966    64,120
   Trading activities, net.................     298  (34,086)  (3,425)  (51,587)
   Net income (loss).......................   7,826   (4,023)  21,257     2,614
   Net income (loss) per share*:
     Basic.................................     .24     (.12)     .64       .08
     Assuming dilution.....................     .24     (.12)     .64       .08

<CAPTION>
                                                   Three Months Ended
                                            -----------------------------------
                                            3/31/99 6/30/99   9/30/99  12/31/99
                                            ------- --------  -------  --------
   <S>                                      <C>     <C>       <C>      <C>
   1999
   Revenues................................ $44,629 $ 53,906  $58,906  $ 57,559
   Income from operations..................   2,503    8,638   12,466    11,581
   Trading activities, net.................  15,085    2,985     (222)      997
   Net income..............................   7,699    4,127    4,322     4,680
   Net income per share*:
     Basic.................................     .24      .13      .13       .14
     Assuming dilution.....................     .24      .13      .13       .14
</TABLE>

* Individual quarterly income (loss) per share may not aggregate to the income
  (loss) per share for the year.

                                     F-22
<PAGE>

                     SUPPLEMENTAL OIL AND GAS INFORMATION

   The following information, pertaining to the Company's oil and gas
producing activities for the years ended December 31, 2000, 1999 and 1998, is
presented in accordance with Statement of Financial Accounting Standards No.
69, "Disclosure About Oil and Gas Producing Activities" (SFAS No. 69).

Major Purchaser

   During 2000, one natural gas purchaser accounted for 9 percent of the
Company's operating revenues. Sales of gas to this same purchaser represented
10 percent and 12 percent of operating revenues in 1999 and 1998,
respectively.

Costs Incurred In Oil And Gas Exploration And Development Activities

   The following costs were incurred by the Company in oil and gas property
acquisition, exploration, and development activities during the years ended
December 31:

<TABLE>
<CAPTION>
                                                   2000      1999      1998
                                                 --------  --------  --------
                                                       (in thousands)
   <S>                                           <C>       <C>       <C>
   Acquisition of evaluated properties.......... $ 25,551  $ 53,001  $  3,529
   Acquisition of unevaluated properties:
     United States..............................   42,439    21,504    32,127
     Peru.......................................      274       --     12,089
   Exploration costs:
     United States..............................   41,644    27,467    59,331
     Peru.......................................       55       --     15,196
   Development costs:
     United States..............................  142,132    55,615    84,577
     Peru.......................................      160       685       --
                                                 --------  --------  --------
                                                  252,255   158,272   206,849
   Other, principally proceeds from mineral
    conveyances.................................  (44,819)  (26,915)   (7,185)
                                                 --------  --------  --------
   Total additions to oil and gas properties.... $207,436  $131,357  $199,664
                                                 ========  ========  ========
</TABLE>

   Property acquisition costs include costs incurred to purchase, lease, or
otherwise acquire a property. Exploration costs include the costs of
geological and geophysical activity, dry holes, and drilling and equipping
exploratory wells. Development costs include costs incurred to gain access to
and prepare development well locations for drilling and to drill and equip
development wells.

   In addition, the Company incurred costs of $34.2 million in 2000 for
various supporting production facilities consisting principally of natural gas
gathering systems and processing plants. Production facility expenditures for
1999 and 1998 were $1.8 million and $3.2 million.

Oil And Gas Reserves (Unaudited)

   The following reserve related information for 2000 is based on estimates
prepared by the Company. All of the Company's reserves are located in the
United States. Approximately 85 percent of the Company's reserve information
as of December 31, 2000 and December 31, 1999 was reviewed by independent
reservoir engineers. Ryder Scott Company, L.P., an independent reservoir
engineer, reviewed the Company's Hugoton Embayment, Wind River Basin and
Piceance Basin reserve information. The reserve information for the Company's
Coal Bed Methane properties located in the Powder River Basin was audited by
Netherland, Sewell & Associates, Inc., an independent reservoir engineer.
Reserve estimates are inherently imprecise and are continually subject to

                                     F-23
<PAGE>

revisions based on production history, results of additional exploration and
development, prices of oil and gas and other factors.

<TABLE>
<CAPTION>
                                 2000                 1999                  1998
                         --------------------  --------------------  --------------------
                         Oil (MBbl) Gas (Mmcf) Oil (MBbl) Gas (Mmcf) Oil (MBbl) Gas (Mmcf)
                         ---------- ---------  ---------  ---------  ---------  ---------
                                                (in thousands)
<S>                      <C>        <C>        <C>        <C>        <C>        <C>
Proved developed and
 undeveloped reserves:
Beginning of year.......    9,658   1,075,892    9,650      912,430   18,651     851,244
Revisions of previous
 estimates..............     (116)    (24,626)   3,220       (6,790)  (7,437)    (55,343)
Purchase of minerals in
 place..................      --      110,365      --       160,424      --        3,520
Extensions and
 discoveries............      521     303,595    1,047      127,604      746     217,870
Production..............     (873)   (112,403)  (1,432)     (94,953)  (2,033)    (94,893)
Sale of minerals in
 place..................   (1,081)    (29,456)  (2,827)     (22,823)    (277)     (9,968)
                           ------   ---------   ------    ---------   ------     -------
End of year.............    8,109   1,323,367    9,658    1,075,892    9,650     912,430
                           ======   =========   ======    =========   ======     =======
Proved developed
 reserves:
 Beginning of year......    5,664     664,096    6,212      543,068   10,751     553,787
                           ======   =========   ======    =========   ======     =======
 End of year............    4,020     765,174    5,664      664,096    6,212     543,068
                           ======   =========   ======    =========   ======     =======
</TABLE>

Standardized Measure of Discounted Future Net Cash Flows (Unaudited)

   The standardized measure of discounted future net cash flows is based on
estimated quantities of proved reserves and the future periods in which they
are expected to be produced and on year-end economic conditions. Estimated
future gross revenues are priced on the basis of year-end prices, except in
the case of contracts where the applicable contract price, including fixed and
determinable escalations, were used for the duration of the contract.
Estimated future gross revenues are reduced by estimated future development
and production costs, as well as certain abandonment costs and by estimated
future income tax expense. Future income tax expenses have been computed
considering the tax basis of the oil and gas properties plus available
carryforwards and credits.

   The standardized measure of discounted future net cash flows should not be
construed to be an estimate of the fair market value of the Company's proved
reserves. Estimates of fair value would also take into account anticipated
changes in future prices and costs, the reserve recovery variances from
estimated proved reserves and a discount factor more representative of the
time value of money and the inherent risks in producing oil and gas.
Significant changes in estimated reserve volumes or product prices could have
a material effect on the Company's consolidated financial statements.

<TABLE>
<CAPTION>
                                              2000         1999        1998
                                           -----------  ----------  ----------
                                                    (in thousands)
<S>                                        <C>          <C>         <C>
Future cash inflows......................  $11,069,169  $2,431,441  $1,927,074
Future production costs..................   (1,762,819)   (705,476)   (570,923)
Future development costs.................     (371,673)   (281,727)   (238,169)
Future income tax expenses...............   (3,073,719)   (300,354)   (187,113)
                                           -----------  ----------  ----------
  Future net cash flows..................    5,860,958   1,143,884     930,869
10% annual discount for estimated timing
 of cash flows...........................   (2,418,805)   (482,577)   (400,221)
                                           -----------  ----------  ----------
Standardized measure of discounted future
 net cash flows..........................  $ 3,442,153  $  661,307  $  530,648
                                           ===========  ==========  ==========
</TABLE>

   The estimate of future income taxes is based on the future net cash flows
from proved reserves adjusted for the tax basis of the oil and gas properties
but without consideration of general and administrative and interest expenses.
For standardized measure purposes the Company estimates future income taxes
using the "year-by-year" method. For ceiling test purposes, the Company
estimates future income taxes using the "short-cut" method.

                                     F-24
<PAGE>

   The following are the principal sources of changes in the standardized
measure of discounted future net cash flows:

<TABLE>
<CAPTION>
                                              2000         1999        1998
                                           -----------  ----------  ----------
                                                    (in thousands)
<S>                                        <C>          <C>         <C>
Net change in sales price and production
 costs...................................  $ 3,468,077  $   45,470  $ (103,105)
Changes in estimated future development
 costs...................................       55,115      18,055      43,383
Sales and transfers of oil and gas
 produced, net of production costs.......     (343,367)  (157,768)   (146,875)
Net change due to extensions and
 discoveries.............................    1,059,145      76,523     115,145
Net change due to purchases and sales of
 minerals in place.......................      207,135     117,670     (6,980)
Net change due to revisions in
 quantities..............................     (161,818)     35,208     (76,985)
Net change in income taxes...............   (1,603,349)    (64,554)     68,083
Accretion of discount....................       70,304      56,702      63,163
Other, principally revisions in estimates
 of timing of production.................       29,604       3,353      10,688
                                           -----------  ----------  ----------
Net changes..............................    2,780,846     130,659     (33,483)
Balance, beginning of year...............      661,307     530,648     564,131
                                           -----------  ----------  ----------
Balance, end of year.....................  $ 3,442,153  $  661,307  $  530,648
                                           ===========  ==========  ==========
</TABLE>

   The weighted average prices utilized for purposes of estimating the
Company's proved reserves and future net revenues were $22.18 per barrel of
oil and $8.23 per Mcf of natural gas based on market prices in effect on
December 31, 2000.

                                     F-25