<PAGE>
 
-------------------------------------------------------------------------------
-------------------------------------------------------------------------------
 
                      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, 1995
                                      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)
 
               DELAWARE                              84-0832476
    (STATE OR OTHER JURISDICTION OF     (I.R.S. EMPLOYER IDENTIFICATION NO.)
    INCORPORATION OR ORGANIZATION)
 
 1515 ARAPAHOE STREET, TOWER 3, SUITE                   80202
        1000, DENVER, COLORADO                       (ZIP CODE)
    (ADDRESS OF PRINCIPAL EXECUTIVE
               OFFICES)
 
                                (303) 572-3900
             (REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
 
          SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
                                    (NONE)
 
          SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
                    COMMON STOCK (PAR VALUE $.01 PER SHARE)
                                TITLE OF CLASS
 
  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. [_]
 
  As of March 12, 1996, the Registrant had 25,103,666 common shares
outstanding, and the aggregate market value of the common shares held by non-
affiliates was approximately $523,651,915. This calculation is based upon the
closing sale price of $22.625 per share for the stock on March 12, 1996.
 
-------------------------------------------------------------------------------
-------------------------------------------------------------------------------
<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 REGISTRANT'S COMMON STOCK AND RELATED SECURITY
           HOLDERS MATTERS..............................................   16
 6.       SELECTED FINANCIAL DATA.......................................   17
 7.       MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
           AND RESULTS OF OPERATIONS....................................   17
 8.       FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA....................   21
 9.       CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
           AND FINANCIAL DISCLOSURES....................................   21
                                    PART III
 10.      DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY...............   22
 11.      EXECUTIVE COMPENSATION........................................   26
 12.      SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
           MANAGEMENT...................................................   29
 13.      CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS................   31
                                    PART IV
 14.      EXHIBITS, FINANCIAL SCHEDULES, AND REPORTS ON FORM 8-K........   31
</TABLE>
<PAGE>
 
                                    PART I
 
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
 
  Barrett Resources Corporation (the "Company" or "Barrett", which reference
shall include the Company's wholly owned subsidiaries) was incorporated in
December 1980 as an oil and gas company under the name AIMEXCO Inc. and became
publicly owned with a $5.8 million common stock offering in May 1981. In
December 1983, AIMEXCO acquired all of the common stock of Barrett Energy
Company, which owned a number of oil and gas properties, in exchange for 71.5
percent of the common stock of AIMEXCO that was outstanding after the
transaction. In January 1984, the Company changed its name to Barrett
Resources Corporation.
 
  In November 1985, the Company acquired Excel Energy Corporation ("Excel"), a
Utah corporation that owned oil and gas interests, in exchange for
approximately 1,425,000 shares of the Company's common stock. In June 1987,
the Company acquired all the outstanding stock of Finance For Energy, Ltd.
("FFE"), whose assets consisted primarily of cash and mortgages, in exchange
for 1,174,100 shares of the Company's common stock.
 
  In September 1987, the Company effected a one-for-twenty reverse stock split
of the Company's common shares and changed the par value of its common stock
to $.01 per share. All references in this Item to numbers of shares of the
Company's common stock have been adjusted for the effect of this one-for-
twenty reverse stock split.
 
  In May 1990, the Company completed the public offering of 3,565,000 shares
of its common stock for aggregate proceeds of $21,260,250, net of the
underwriting discount. In March 1993, the Company completed the public
offering of an additional 2,000,000 shares of its Common Stock for aggregate
proceeds of $19,160,000, net of the underwriting discount.
 
  In August 1993, the Company completed the sale, effective July 1, 1993, of
substantially all the interests of the Company in oil and gas properties, a
gas processing plant and the related gas gathering system located in the
Wattenberg Field of Colorado. The adjusted sales price, net of selling
expenses, was approximately $14.4 million.
 
  On July 18, 1995, the Company completed the merger of the Company and Plains
Petroleum Company ("Plains") pursuant to which Plains became a wholly owned
subsidiary of the Company. The Company issued a total of 12.8 million shares
of Common Stock in exchange for all the outstanding shares of Plains.
 
 Oil and Gas Exploration and Development
 
  Barrett is primarily an independent oil and gas exploration and production
company with major emphasis in the Rocky Mountain region of Colorado and
Wyoming and the Mid-Continent region of Kansas, Oklahoma and the Texas
Panhandle. Barrett utilizes its own exploration staff to develop a geologic
concept into an exploration prospect, which is drilled either solely by
Barrett or with partners. Oil and gas leases are acquired by Barrett's land
department primarily in the Company's strategic core areas of interest.
Barrett typically will retain an interest and serve as operator of a joint
venture exploration program on the prospect acreage. Barrett also acquires
interests in exploration and development programs operated by other companies
through acquisition or farm-ins.
 
  Barrett will act as the operator, when possible, of the exploration or
development drilling program. Barrett's operations division is currently
operating major projects, including properties in the Piceance Basin in
Colorado, Hugoton and Panoma-Council Grove Fields in Kansas, Anadarko and
Arkoma Basins in Oklahoma, and Wind River Basin in Wyoming. When serving as
operator, Barrett is responsible for the drilling, evaluation and production
activities associated with the prospect and for negotiating the sales of oil
and gas production. As of December 31, 1995, Barrett was serving as operator
for approximately 1,061 producing wells, 186 shut-in wells, four wells that
were drilling, four wells that were being completed and five wells that were
waiting on completion.
 
                                       1
<PAGE>
 
  During 1995, more than 82 percent of the Company's total production was
natural gas, and the Company's primary natural gas production came from the
Hugoton and Panoma-Council Grove Fields, and the Piceance and Wind River,
Basins.
 
  The Company has constructed and operates, on behalf of itself and others, an
approximate 150-mile pipeline gathering system and related facilities in the
Company's Piceance Basin Project, as well as a 16-inch, 27-mile pipeline and a
gas processing plant in the Piceance Basin. This pipeline enables the Company
to move gas to three interstate pipelines, which allows the transport of the
Company's gas to eastern markets for the first time. The Company also owns and
operates a 30-mile gas gathering system in the Washakie-Red Desert Basin of
Wyoming. See "Gas Gathering".
 
  Barrett Fuels Corporation ("Barrett Fuels"), a wholly owned subsidiary, is
engaged in natural gas trading activities as well as natural gas marketing
activities on behalf of itself and others. See "Gas Marketing And Trading".
 
  The Company is headquartered in Denver, Colorado with additional offices in
Gillette, Wyoming; Lakin, Kansas; Midland, Texas; Parachute, Colorado; and
Tulsa, Oklahoma. In 1996, Barrett opened an office in Houston, Texas. Barrett
currently has 131 full time employees, including eight officers (two of whom
are geologists and one of whom is a petroleum engineer), seven geologists, two
geophysicists, nine engineers, one environmental manager, four landmen, four
district managers, one operations superintendent, and administrative,
clerical, accounting and field operations personnel.
 
 Colorado
 
  PICEANCE BASIN PROJECT
 
  The Piceance Basin of northwestern Colorado is a core operating area for the
Company and will continue to be very prominent in the Company's capital
spending plans. Barrett drilled its first well in the Piceance Basin in 1984.
At present, the Company owns and operates 289 gross, 100 net, wells in the
Piceance Basin. The Company's activities in the Piceance Basin are conducted
primarily in three fields: Parachute, Rulison, and Grand Valley. In addition,
the Company has small projects in the Trailridge area and the Story Gulch
Federal Unit.
 
  The Company's drilling activities in the Piceance Basin primarily target the
lenticular sandstones of the Williams Fork Formation of the Mesaverde Group.
These sandstone reservoirs overlie the blanket sandstones of the Iles
Formation in the basal Mesaverde. The Company operates and owns an interest in
an approximate 150 mile pipeline gathering system with related production and
compression facilities, a 27 mile pipeline and a gas processing plant in the
Piceance Basin. During March 1996, the Company was operating one rig
continuously in the Basin.
 
  In February 1995, the Company received approval for 40-acre density by the
Colorado Oil and Gas Conservation Commission on 81 640-acre sections across
the three main fields. In November 1995, the Company completed the drilling of
a three well, 40-acre test program and plans to drill a similar three well,
40-acre test program in Grand Valley Field during the first half of 1996.
 
  Grand Valley Field. The Grand Valley Field, located in Mesa and Garfield
Counties of Colorado, produces gas primarily from the Mesaverde Formation with
wells drilled to depths ranging from 6,000 to 7,500 feet. The Formation
consists of numerous tight gas sandstone reservoirs. As of December 31, 1995,
the Company had, from the inception of the project, drilled 86 wells in the
Grand Valley Field with 80 wells producing gas, three wells shut-in and three
wells plugged and abandoned. During 1995, the Company's activities in this
area included the drilling and completion of two wells, both of which are
producing and operated by the Company.
 
  Rulison Field. The Rulison Field, located in Garfield County, Colorado,
produces from the Wasatch and Mesaverde Formations with wells drilled to
depths varying from 1,200 to 2,500 feet in the Wasatch and 7,500 to 8,500 feet
in the deeper Mesaverde Formation. As of December 31, 1995, the Company had,
from the inception
 
                                       2
<PAGE>
 
of the project, drilled 101 wells in the Rulison Field with 92 wells producing
and eight wells shut-in and one well waiting on completion. The Company has a
working interest in an additional 21 non-operated producing wells.
 
  During 1995, the Company's activities in this area included the drilling and
completion of 18 wells, 17 of which are producing and one is waiting on
completion. All of these wells are Company operated. During 1996, the Company
plans to initiate a program to test the lower Mesaverde Cozzette and Corcoran
Sandstones, which underlie the Williams Fork Formation in the north Rulison
Field.
 
  Testing of the #1 Rulison Deep well, drilled in 1994, demonstrated the
Entrada, Morrison, and Dakota Formations to be non-commercial. Tests of the
Mancos section, at a depth of approximately 9,250 feet, indicated the presence
of natural gas. However, the lack of properly cemented casing over this zone
prevented adequate testing of the Mancos. The Company is currently evaluating
the need to drill a nearby offset to the Mancos for testing. Completion of the
Williams Fork section in the #1 Rulison Deep began in January 1996.
 
  Parachute Field. The Parachute Field, located in Garfield County, Colorado,
produces from the Wasatch and Mesaverde Formations with wells drilled to
depths varying from 1,200 to 1,800 feet in the Wasatch and 6,000 to 7,500 feet
in the deeper Mesaverde Formation. As of December 31, 1995, the Company had,
from the inception of the project, drilled 76 wells in the Parachute Field
with 73 wells producing, two wells shut-in, and one well plugged and
abandoned.
 
  In the Axial Fold belt area, Moffat County, Colorado, the Company drilled
the Waddle Creek #1 well as a 2,633 foot high angle test of the fractured
Niobrara Formation. The well was plugged and abandoned after three days of
drilling indicated no hydrocarbons in the objective. The Company had a 55
percent working interest in the well. The Company has no further plans in the
Axial Fold belt area.
 
 Kansas
 
  HUGOTON EMBAYMENT PROJECT
 
  The largest single producing area for the Company is the Hugoton Embayment
located in southwest Kansas and the Oklahoma panhandle. The Company produces
gas from three fields in the Hugoton Embayment including the Hugoton and
Panoma Fields in Kansas, and the Guymon-Hugoton Field in Oklahoma.
 
  Hugoton and Guymon-Hugoton Fields. The Hugoton Field, located in southwest
Kansas, is the northern portion of the Panhandle-Hugoton Field that
encompasses portions of Kansas, Oklahoma and Texas and is one of the largest
gas fields in the United States. The portion of the Field within Kansas is
designated as the Hugoton Field, while the portion in Oklahoma is referred to
as the Guymon-Hugoton Field. In this case, the difference in field name does
not imply different reservoirs, but only the naming convention used in each
particular state.
 
  Gas production is from the Chase Group, a section of marine carbonates and,
to a lesser extent, sand and silt beds, deposited in six distinct sedimentary
cycles. Production is from a 200 to 350 foot thick Chase Sequence at depths of
2,300 to 2,800 feet.
 
  At present, the Company has a working interest in 324 gross Hugoton wells
and operates 275 of those wells. During 1995, the Company participated in the
drilling of one successful development infill well in Hugoton. The Company is
evaluating additional Hugoton infill wells.
 
  Early in 1995, the Company attempted to increase production from an old
Hugoton well by drilling two horizontal legs into selected portions of the
Chase Group. Results of that work were disappointing, and the Company has no
plans to expand that project in the near future.
 
  Panoma Field. Panoma is the field designation for gas produced from the
Council Grove Group, a formation immediately beneath the Chase Group. The
Council Grove Group has similar reservoir rocks as the
 
                                       3
<PAGE>
 
Chase section, however, the productive limits are not as extensive. Presently,
the Company has a working interest in 53 gross Panoma wells and operates 49 of
those wells.
 
  In 1995, the Company drilled one development well, which is currently shut-
in, waiting on a pipeline connection. At least one additional Council Grove
well is expected to be drilled by the Company during 1996.
 
 Louisiana
 
  GULF COAST PROJECT
 
  The Company had a limited exposure to drill wells and 3-D seismic programs
in onshore and offshore Louisiana in 1995. The Company plans to expand its
activity in the Louisiana and Texas Gulf Coast and shallow Gulf of Mexico
waters through a focused exploration effort with extensive application of 3-D
seismic technology. The Company established a division office in Houston in
1996, staffed with persons with Gulf Coast expertise.
 
  Ship Shoal Block 65. In November 1995, the Company participated in drilling
the Estate of William G. Helis State Lease 14571 #1 well, a 14,199 foot
wildcat in Ship Shoal Block 65. The prospect was developed utilizing the 3-D
seismic data acquired in 1994. The well was completed and tested for rates as
high as 720 barrels of oil per day from a zone at 12,280 feet. One offset well
is being completed and another well will be drilled in 1996 to fully develop
the reservoir and to determine the design of production facilities, which will
be installed shortly thereafter. The Company owns a 33.3 percent working
interest in this new discovery and in the Ship Shoal Block 45 gas field
located immediately to the north of Ship Shoal Block 65. Both fields are
located in Louisiana state waters, immediately offshore of the Terrebonne
Parish, Louisiana.
 
  Ship Shoal Block 275/292. During the second quarter of 1995, the Company
participated in the drilling of the Meridian OCS-G-14507 #1 well, a 9,000 foot
wildcat. The well reached total depth in July 1995 and was plugged and
abandoned due to a lack of reservoir quality rock. The Company has a 33.3
percent working interest in all of Ship Shoal Block 275 and the east half of
Ship Shoal Block 292. Ship Shoal Blocks 275 and 292 are located in Federal
Waters approximately 65 miles offshore of Louisiana. The Company has no
further plans for this property.
 
  South Perry Point. The South Perry Point Prospect is located 14 miles
southwest of Lafayette, Louisiana in Acadia Parish. During the first quarter
of 1995, the Company participated in the drilling of the Total #1 Lambert
well. The well reached a total depth of 17,457 feet before the contractor
plugged and abandoned the well prior to reaching the planned total depth of
18,000. Under the terms of the turnkey contract, the participants were not
obligated for the cost of the well. A 3-D seismic survey is in the process of
being acquired over the prospect with the intent of selecting a 1996 wildcat
location. The Company has a 19 percent working interest in the project.
 
  Patterson Deep. In February 1995, the Helmerich & Payne Shadyside "A" #1
well reached a total depth of 19,030 feet. The Company has a 12.5 percent
working interest in the well and in the prospect leases. The well did not
reach the objective section and was plugged and abandoned. The Company, along
with the other participants, are planning the acquisition of a 3-D seismic
survey over the prospect area. The prospect is located in St. Mary Parish,
Louisiana.
 
 Oklahoma
 
  ARKOMA BASIN PROJECT
 
  During 1995, the Company drilled or participated in the drilling of 15 wells
in the five main focus areas of the Arkoma Basin: Red Oak Field, Limestone
Ridge area, White Ranch Field, Wilburton Field, and the Choctaw Thrust 3-D
area. Additionally, the Company entered two new areas in 1995 with large
leasehold purchases and acquisitions in the Choctaw Thrust 3-D area extension
and the South Panola 3-D area.
 
 
                                       4
<PAGE>
 
  Red Oak Field. In the Red Oak Field, located in Latimer and LeFlore
Counties, Oklahoma, since 1992, the Company has drilled, or participated in
the drilling of, 41 wells, of which 40 wells are producing and one well was
plugged and abandoned. The Company drilled or participated in the drilling of
five wells during 1995, of which all five are producing. These wells were
primarily infill development wells targeting Red Oak, Fanshawe, and/or Spiro
Sandstones at depths ranging from 6,500 to 11,500 feet. The Company obtained
the majority of its interests through farmout agreements with industry
partners or through production purchases that had associated rights for
further infill wells. Some of these agreements involved a number of wells,
while others involved only a single well. The Company's working interests
after payout in the wells drilled in 1995 ranges from 1.9 to 21.5 percent, and
its working interests in wells drilled in previous years range from 1.3 to 44
percent after payout. Typical terms of the farmout agreements vary, but all
provide for the Company to receive all the respective industry partner's
working interest and for the industry partner to retain an overriding royalty
interest in the wells until payout, at which time the industry partner has a
right to convert the overriding royalty interest to a working interest. The
Company continues to drill wells in the Red Oak Field, both with interests
obtained by farmouts and also with interests it has purchased from other
companies.
 
  Limestone Ridge. In the Limestone Ridge area, located in Pittsburg County,
Oklahoma, the Company has drilled or participated in the drilling of, from the
inception of the project in January 1993, nine wells with seven wells
producing and two wells plugged and abandoned. The Company drilled four wells
during 1995, of which three wells were successfully completed.
 
  Wilburton Field. During 1995, the Company drilled three wells in the
Wilburton Field area, which is located in Latimer and Pittsburg Counties,
Oklahoma. The Bowman #5-29 had an initial potential of 1,838 Mcf per day from
the Spiro Sandstone. The Company owns a 14.6 percent working interest in the
well. During 1996, the Company will be participating with industry partners in
shooting a 3-D seismic program over some of the Company's properties in the
Wilburton Field. The 3-D program will be acquired over 12.5 square miles
during early 1996. The Company has plans to drill as many as three wells in
1996 based on the results of the 3-D seismic.
 
  Choctaw 3-D Seismic Area. In fiscal 1994, the Company entered into an
agreement with an industry partner to explore and develop gas reserves in the
Frontal Choctaw Thrust area of the Ouachita Mountains in the Arkoma Basin of
Oklahoma. This agreement allows the Company to prospect on the partner's large
acreage holdings in the area using a 3-D seismic survey developed by that
partner and another party. The 3-D seismic data is extremely useful in
identifying prospective targets in structurally complex areas, such as this
Choctaw Thrust area. The main gas producing zones in this area are the Middle
Atoka Sandstone, the Spiro Sandstone, and the Wapanucka Limestone.
 
  The Company participated in two wells in this area during 1995. One well was
plugged and abandoned as a dry hole and the other is still drilling. Current
plans call for the drilling of three wells in this area during 1996.
 
  Choctaw 3-D Seismic Extension. During 1995, the Company embarked on a
strategy to enlarge and extend the 3-D seismic coverage that the Company has
access to in the Choctaw area. Barrett and a 15 percent working interest
partner have taken leases on an approximately 50 square mile block with the
intent of shooting a 3-D seismic survey. Currently, the Company and its
partner own 7,500 acres of leasehold over the block, the majority of it with a
three to five year term. The Company intends to acquire more leasehold as well
as producing interests in the block before acquiring the 3-D data later in the
year. Four wells have been planned to drill in the new 3-D area in 1996.
 
  South Panola 3-D Area. In 1995, the Company increased its activity in the
South Panola Field in Latimer County, Oklahoma. The South Panola Field
produces from thrust faulted Spiro Sandstone sheets that range in depth from
13,500 to 17,000 feet. Various wells in the Field have produced as much as 24
Bcf at rates in excess of 12,000 Mcf per day. In 1995, a geophysical
contractor proposed a 3-D group shoot over a portion of the South Panola
Field. The Company proposed extending the 3-D to cover a larger part of the
Field and the contractor
 
                                       5
<PAGE>
 
agreed, ultimately resulting in a 71 square mile seismic program. The Company
is a participant in the 3-D program with an agreement to buy 41 square miles of
data.
 
  Previously owning a working interest in just one well, the Company sought to
expand its presence in the South Panola area, making two producing property
acquisitions and taking two farmouts that cover multiple sections. The Company
paid a total of $2.87 million for the two acquisitions, which gave the Company
an interest in 32 different sections, both in the South Panola Field and other
areas within the Arkoma Basin. Two farmout agreements were reached with two
different companies covering 20 different sections in the South Panola Field.
 
  The 3-D seismic was acquired during 1995 and is currently being processed by
the geophysical contractor. The data is expected to be released to participants
in the first quarter of 1996. The Company has budgeted four wells in the South
Panola Field for 1996.
 
 ANADARKO BASIN PROJECT
 
  The Anadarko Basin is one of the Company's most active drilling areas. Since
1993, the Company drilled or participated in a total of 65 wells. In 1995, the
Company drilled or participated in 32 wells with working interests ranging from
1.5 to 100 percent after payout. While staying active in the Strong City Red
Fork Play, the Company become increasingly active in the Mountain Front Granite
Wash plays and the Sentinel Field area.
 
  Watonga-Chickasha Trend. The Watonga-Chickasha Trend is a north-south
trending field. It produces dominantly from Morrowan and Springeran-age
Sandstones at depths ranging from 8,000 feet on the north end to 13,000 feet on
the south end. Drilling in the Watonga-Chickasha Trend accounted for five of
the wells that the Company participated in during 1995 in the Anadarko Basin.
The Company's working interest after payout ranges from one to 100 percent. Of
these five wells, two wells are currently producing, one well had production
casing set and is waiting on completion, one well is still drilling, and one
well was a dry hole.
 
  Strong City Red Fork Play. The Strong City Red Fork Play refers to an active
drilling area that covers approximately 750 square miles in Roger Mills and
Custer Counties in western Oklahoma. The primary targets are the Pennsylvanian-
aged Red Fork, Pure and Skinner Sandstones at depths ranging from 11,000 to
13,500 feet across the region. The Red Fork, Pure and Skinner Sandstones are
relatively tight and impermeable. This lack of permeability has required more
than one well per section be drilled to fully develop the gas reserves that are
in place and has accounted for a great deal of drilling activity in this area
by other companies. The Company has targeted this area as one of high potential
due to the widespread nature of sand deposition, improving drilling economics
with decreasing costs, and the opportunity for multiple locations within each
section. The Company has acquired working interests through several avenues,
including farm-in arrangements with industry partners, producing property
acquisitions and leasing minerals.
 
  The Company drilled or participated in 12 wells in this area during 1995. Of
these 12 wells, 10 wells are producing, one well is being completed, and one
well was a dry hole. The Strong City Red Fork Play will be an important part of
the Company's activity in the Anadarko Basin during 1996 with current plans for
drilling or participating in 21 wells.
 
  During 1995, the Company drilled a successful Red Fork well near the town of
Clinton in western Oklahoma. The Barrett Stratton Farms #2 tested in excess of
10,000 Mcf per day from the Red Fork Sandstone. The well is currently selling
into the pipeline at a rate of 4,600 Mcf per day after producing 500 Mmcf since
September 1995. The Company owns a 56 percent working interest in the well
after payout. The Company is currently drilling an offset to the Stratton Farms
called the Cabaniss #1. The Company owns a 70.25 percent working interest in
the Cabaniss #1. The Company also drilled the Barrett Glen Miller #1 and
completed the well in the Skinner Sandstone at a rate of 2,400 Mcf per day. The
well is currently waiting on pipeline connection. The Company owns a 43 percent
working interest in the well after payout.
 
  Mountain Front Granite Wash Play. The Company became active during 1995 in a
play along the structurally complex Wichita Mountain front that borders the
Anadarko Basin to the south. Thick sequences of
 
                                       6
<PAGE>
 
sandstone composed of granite and other rock fragments were deposited into the
Anadarko Basin as erosion wore down the exposed granite of the Wichita
Mountains to the south. These Granite Wash Sandstones have been drilled
through for many years, yet overlooked, as operators targeted the deeper
Morrow, Springer and Hunton horizons.
 
  Recent workovers and recompletions have shown that, while some of these
rocks may exhibit low receptivity on electrical logs, it does not necessarily
mean they are non-productive. Newer techniques have also resulted in better
completions as the water sensitiveness of the formations have become better
understood. In fact, some excellent producers have been made within hundreds
of feet of wells that have been historically poor producers.
 
  During 1995, the Company participated in three wells in the Mountain Front
Granite Wash Play. Of these, one well is producing into a pipeline and two
wells have had production casing set and are waiting on completion. The first
well the Company participated in this area was the Kamphaus #1, which is
currently selling into the pipeline at a rate of 4,600 Mcf per day and 266
barrels of oil per day. The Company has a seven percent working interest in
the well after payout. The Company has been very active acquiring leasehold in
several different areas along the Mountain Front to drill Granite Wash wells.
The Company has budgeted 11 wells in this area during 1996.
 
  Sentinel Field. Sentinel Field, located in Washita County, Oklahoma,
produces gas both from steeply dipping and overturned Morrow and Springer
Formations, and overlying and nearly flat lying Granite Wash reservoirs.
Granite Wash reservoirs are encountered at approximately 9,700 feet and the
Morrow/Springer produces from approximately 12,000 feet. The Company drilled
and completed four wells in the Sentinel Field in 1995. The Baker #1 is
currently flowing 10,000 Mcf per day and the Banks #2 is currently testing gas
from the same Springer Sandstone. The Company's working interest is 25 and 65
percent, respectively. The Sears #2, in which the Company owns an 86 percent
working interest, missed the Morrow Sandstone, but was completed uphole in the
Granite Wash as a new field discovery flowing 2,200 Mcf per day. Subsequently,
the Huckaby #3, in which the Company has an 88 percent working interest, was
drilled and completed, flowing 4,500 Mcf per day from the Granite Wash. The
Latham #3, a well in which the Company owns a 100 percent working interest, is
flowing 600 Mcf per day from the Granite Wash. The Company plans to drill at
least three Granite Wash wells and three Morrow/Springer wells in 1996.
 
 Wyoming
 
  WIND RIVER BASIN PROJECT
 
  In fiscal 1994, the Company began a focused exploration program in the Wind
River Basin, particularly along the Owl Creek Thrust fault. The primary
reservoir target in this program is a thick section of lenticular sandstones
in the Fort Union and Lance Formations of Tertiary and Upper Cretaceous age.
 
  Cave Gulch Field Discovery. In August 1994, the Company drilled the Cave
Gulch Federal Unit #1 and discovered a significant natural gas field in the
Fort Union and Lance Sandstones below the Owl Creek Thrust. In September 1994,
the Company acquired additional interests, thereby increasing its working
interest in the well and the 440-acre Cave Gulch Unit from 72 to 94 percent.
The well began flowing on-line December 2, 1994 at a rate of 9.7 Mmcf of gas
per day and 116 barrels of oil per day. The Company owns working interests
from 40 to 100 percent in the surrounding area and owns leasehold in 15,687
gross and 7,839 net acres in the Cave Gulch area.
 
  Cave Gulch Development. During 1995, the Company drilled and set production
casing on eight wells, the Cave Gulch Nos. 2, 3, 4, 7, 8, 9, 11 and 13. Of
those eight wells, four have been completed in various intervals from the Ft.
Union, Lance and Meeteetse Formations, two are undergoing completion testing,
and two are waiting on completion. Current combined daily production for the
Cave Gulch Field at year end 1995 was 52 Mmcf of natural gas per day and 232
barrels of oil per day. As of November 30, 1995, the field had a total
 
                                       7
<PAGE>
 
cumulative production of 7.37 Bcf of natural gas and 42,668 barrels of oil.
The Company owns a 94.1 percent working interest in each of the wells drilled
in 1995.
 
  In December 1995, the Company drilled a 12,661 foot twin to the Cave Gulch
Unit #1 well to probe for deeper Mesaverde and Cody Sandstones of the Upper
Cretaceous. Production pipe was run to total depth in the well. However, due
to requirements of the Cave Gulch environmental assessment, testing will be
completed in the summer of 1996. The Company owns a 90.62 percent working
interest below the shallower Lance Formation. Subsequent to completion, its
working interest is reduced to 58.13 percent.
 
  During 1996, the Company had planned to drill up to 10 wells. However, the
Bureau of Land Management has determined that an environmental impact
statement in the greater Cave Gulch area may be required to assess future
development proposals from the Company and other operators in the area. The
Company believes that certain locations could be drilled in the Cave Gulch
area during the environmental impact statement process, and the Company will
proceed accordingly.
 
  Owl Creek Thrust. The Company continues to evaluate additional exploration
prospects in the Owl Creek Thrust and central Wind River Basin. The Company
has 80,100 gross and 62,222 net acres under lease outside of the Cave Gulch
area. The Company plans to drill two exploratory tests in 1996.
 
  POWDER RIVER BASIN PROJECT
 
  The Powder River Basin in Wyoming is a new core area for the Company and is
primarily an oil province, with production from Cretaceous and Permian-age
Formations. One of the reservoir targets in this area is the Permian Minnelusa
Formation. This Basin contributes nearly half of the Company's daily oil
production and further activity will concentrate on development drilling and
enhanced recovery projects utilizing 3-D seismic technology where appropriate.
 
  North Adon Road Field Waterflood. The Company initiated waterflood
operations in November, 1995. It is anticipated that the Field's gross
production should increase from 40 barrels of oil per day to 750 barrels of
oil per day by the end of 1996. The application of alkaline surfactant polymer
("ASP") technology to chemically enhance the Field's waterflood performance is
currently being evaluated. The Company's working interest in this property is
80.28 percent. In May 1995, the Company drilled an unsuccessful development
well in the downdip area of North Adon Road Field.
 
  West Rozet Unit. The Minnelusa A and Upper B Sandstone reservoirs at the
West Rozet Unit have produced over nine million barrels of oil and have been
under waterflood for many years. In an effort to further develop this
property, a 3-D seismic survey was acquired in March 1995. The West Rozet #24-
23 well was drilled based on the interpretation of this 3-D survey. The well
was completed on December 21, 1995 producing 181 barrels of oil per day with
no water from the Minnelusa Upper B Sandstone. Production from the West Rozet
Unit prior to completing the West Rozet #24-23 well totaled 134 barrels of oil
per day from four producing wells. The seismic data indicate the potential for
an additional Upper B Sandstone location, which may be drilled later in 1996.
The application of ASP in a tertiary waterflood is also being considered in
this unit, in which the Company has a 99.8 percent working interest.
 
  South Rozet Field. A 3-D seismic survey was acquired over the Minnelusa
Lower B Sandstone portion of South Rozet Field in March 1995 in an attempt to
define an additional drilling location. The Billy Nelson #23-19 was drilled in
December 1995, and is presently being completed. Based on initial production
tests, the well is expected to produce approximately 100 barrels of oil per
day. The Company's working interest in this well is 98.4 percent. The South
Rozet Field also includes the Northern Minnelusa A Sandstone Unit, which is
operated by the Company with a 96.7 percent working interest. The Minnelusa A
Sandstone reservoir performance suggests the possibility of additional
development opportunities within this unit. Further evaluation of this
property will be carried out in 1996.
 
 
                                       8
<PAGE>
 
  Rozet Minnelusa Unit. The Company acquired a 3-D seismic survey over the
Rozet Minnelusa Unit in August 1995, in an attempt to define additional
drilling locations in this Minnelusa Upper B Sandstone Field. The data is
currently being processed, and it is anticipated that a development well will
be drilled during the first quarter of 1996. Depending on the drilling
results, the Company will evaluate the applicability of ASP technology at
Rozet Minnelusa Unit. The Company's working interest is 87.9 percent.
 
  Cambridge Unit. The Cambridge Minnelusa ASP project was initiated in January
1993 and continues its strong performance of enhanced oil recovery. In
December 1995, oil production averaged 950 barrels of oil per day. The Company
is currently completing an additional development well. The location for this
well was based on an updated interpretation of the 3-D seismic survey, which
covers the entire field. The Company's working interest in the Cambridge Unit
is 73.2 percent.
 
  West Moran Unit. During the third quarter of 1995, the Company participated
in the drilling of an unsuccessful Minnelusa A Sand development well in the
West Moran Unit. The West Moran Unit #5-5, operated by Northstar Operating
Co., was plugged and abandoned after recovering water on a drill stem test.
The Company's working interest in the West Moran Unit is 12.4 percent.
 
  East Moran Unit. The East Moran Unit is immediately adjacent to the West
Moran Unit, and produces from the Minnelusa Upper B Sand. The Company has a
100 percent working interest in this unit, and believes the reservoir's
recovery efficiency may be improved by the drilling of an additional Minnelusa
Upper B injection well. This opportunity will be further evaluated during
1996.
 
  Powell Field. The Company has a significant working interest and acreage
position in the Powell Field area in Converse County, Wyoming, in the southern
portion of the Powder River Basin. Production in the Powell Field is primarily
from stratigraphically-trapped sandstones in the Cretaceous Frontier and
Dakota Formation, as well as secondary potential in the shallower Sussex
Sandstone. The Company currently has 7,603 gross acres, and 4,221 net acres
under lease in the Powell area and plans to drill one to two infill and
stepout locations in 1996, primarily targeting reserves in the Dakota
Sandstone. The Company will have an approximate 62 to 68 percent working
interest in these locations.
 
  GREEN RIVER BASIN/WYOMING OVERTHRUST PROJECT
 
 
  The Company owns leasehold within the greater Green River Basin, primarily
in the Moxa Arch, Rock Springs Uplift and Wamsutter Arch areas, and in the
Wyoming Overthrust Trend. The Company participated in one well in the Green
River Basin and one well in the Wyoming Overthrust in 1995. The Company has
plans for additional wells in the Green River Basin in 1996.
 
  Whiskey Springs Field. The Company holds 6,524 gross acres and 4,610 net
acres in the Whiskey Springs Field of the southern Moxa Arch. Currently, the
Company is evaluating the area in anticipation of drilling one well during the
summer of 1996.
 
  Nighthawk Prospect. The Redtail Unit #1 well was drilled to a depth of
11,918 feet to the Jurassic Twin Creek Formation. Structural data indicated
the Jurassic Nugget Formation was no longer prospective and the well was
plugged and abandoned prior to reaching the proposed total depth of 13,000
feet. The Company had a 100 percent working interest in the well.
 
 Texas
 
  PERMIAN BASIN PROJECT
 
  The Company's activities in 1995 in the Permian Basin included the final
phases of exploratory drilling and a continuing effort in development
drilling. As of December 31, 1995, the Company had an interest in 300 gross
wells (225 net wells) located in the Permian Basin, which produce
approximately 1,100 net barrels of oil per
 
                                       9
<PAGE>
 
day. The primary areas of production for the Company are in the South Cowden
Field, Spraberry Trend area, Novice Field and North Knox City Field in Ector,
Midland, Martin, Coleman and Knox Counties, Texas, respectively.
 
  Dawson County. During 1995, the Company's exploration activities included
the participation in five successful wells located in Dawson County, Texas.
These prospects were identified through the use of 3-D seismic technology. The
Company has a 10 percent working interest in this project. In 1996, the
operator of this 3-D project plans to drill three additional west Texas
exploration prospects and the Company has the option of participating in each
of these prospects.
 
  Foster Grayburg San Andres Unit. In Ector County, Texas, the Company
acquired an 80 percent working interest before payout (50 percent after
payout) in a waterflood project in the Foster Grayburg San Andres Unit that
produces from the Grayburg Formation. In 1995, four producing wells and one
water injection well were drilled and four producing wells and six water
injection wells were reactivated. Production increased from 112 barrels of oil
per day to 235 barrels of oil per day from the pilot areas in the Foster
Grayburg San Andres Unit. The Company has the option to expand the development
of the Foster Grayburg Unit in 1996 if successful waterflood response results
are realized from the pilot test.
 
  Teague Field. Two Simpson-McKee Formation wells were drilled and placed on
production in the Teague Field in Lea County, Texas in 1995. Two Simpson-McKee
wells were converted to water injection wells, initiating a pressure
maintenance project in December 1995. In 1996, in the immediate Teague Field
area, three water injection wells will be reactivated and one producing well
will be converted to a water injection well at the G. H. Mattix Lease in Lea
County, New Mexico to increase oil recovery from the Queen Formation. This
will be similar to an active waterflood that the Company operates in this same
area, the Blinebry-Cade Waterflood, that also produces from the Queen
Formation.
 
  Boys Ranch Project. During 1993, the Company joined in three exploration
projects in and around the Permian Basin of West Texas. Each project centered
on acquiring lease options over large tracts of land and then utilizing 3-D
seismic to define prospects. In 1995, Barrett participated in two wells within
the Boys Ranch project in Borden and Scurry Counties of the Northern Midland
Basin. The Ruwco #1 Von Roeder drilled a reef that came in as expected
structurally, yet the well had excessive water production. The Ruwco #1-A
Griffen found non-commercial amounts of oil. The Company has a 10 percent
working interest in both wells, which were plugged and abandoned.
 
 Utah
 
  UINTA BASIN PROJECT
 
  Brundage Canyon Field. Brundage Canyon Field, located in the Uinta Basin in
Duchesne County, Utah, was purchased by the Company in December 1995. The
Company currently owns a working interest ranging from 49 to 100 percent in 20
producing wells, a pipeline gathering and transmission system, and 24,660
gross acres, approximately 21,700 net acres, all of which are on the Ute
Indian Reservation. The Field has produced 1,270,000 barrels of oil to date
and is currently producing 300 barrels of oil and 750 Mcf per day, primarily
from multiple sandstone reservoirs of the lower Green River Formation at
depths averaging 5,500 feet. Individual wells can have a primary recovery of
over 200,000 barrels of oil of black wax crude, which can command a premium
price over spot market prices.
 
  The Company plans extensive work in this Field during 1996 including: a 10
well program to develop infill and field extension locations; a 40-acre pilot
project that will lay the groundwork for a future waterflood project; and
recompletions and workovers of existing wells to test the viability of
shallower horizons for potential future development. Deeper gas bearing
Wasatch and Mesaverde reservoirs are also prospective and will be tested in
the future.
 
 
                                      10
<PAGE>
 
 Production
 
  The Company's total gas production averaged 130,700 Mcf of gas per day in
1995 compared with 91,200 Mcf per day in 1994. The Company's total crude oil
production averaged 4,700 barrels per day in 1995 compared with 3,540 barrels
per day during the prior year. On a barrel of oil equivalent basis (BOE),
using a ratio of six Mcf of gas to one barrel of oil, the Company's total
production averaged 26,400 BOE per day for 1995 compared with 18,740 BOE per
day for 1994.
 
  The table below sets forth information with respect to the Company's
producing oil and gas properties for each of its last three years:
 
<TABLE>
<CAPTION>
                                                  YEAR ENDED DECEMBER 31,
                                            -----------------------------------
                                               1995        1994        1993
                                            ----------- ----------- -----------
<S>                                         <C>         <C>         <C>
Quantities Produced And Sold
  Oil and Condensate (Bbls)................   1,702,000   1,293,000   1,293,000
  Gas (Mcf)................................  47,692,000  33,282,000  31,712,000
Average Sales Price
  Oil and Condensate ($/Bbls).............. $     15.76 $     13.95 $     14.93
  Gas ($/Mcf).............................. $      1.47 $      1.83 $      1.94
Average Production Costs
  Oil and Condensate ($/Bbls).............. $      3.58 $      4.13 $      4.62
  Gas ($/Mcf).............................. $      0.60 $      0.69 $      0.77
</TABLE>
 
 Productive Wells And Acreage
 
  The productive wells and developed acreage in which the Company owned a
working interest as of December 31, 1995 are described in the following table:
 
<TABLE>
<CAPTION>
                                     PRODUCTIVE WELLS(A)(B)
                                    -------------------------
                                     OIL WELLS     GAS WELLS  DEVELOPED ACREAGE
                                    ------------ ------------ -----------------
                                    GROSS  NET   GROSS  NET    GROSS     NET
                                    ----- ------ ----- ------ -----------------
<S>                                 <C>   <C>    <C>   <C>    <C>      <C>
Piceance Basin, CO.................    0    0.00   289  99.93   35,200   10,600
Greater Green River Basin, WY......    3    1.80    45  21.43   19,998    9,396
Powder River Basin, WY.............  288   67.60    16   2.30   42,654   25,521
Wind River Basin, WY...............    0    0.00     9   8.46      440      414
Arkoma Basin, OK...................    0    0.00   135  24.81   41,181   11,755
Anadarko Basin, OK/TX..............   13   12.60   180  66.34   40,725   14,571
Hugoton Embayment, KS/OK...........    0    0.00   411 346.80  118,238  114,100
Permian Basin, TX/NM...............  287  215.73    13   9.60   25,922   20,407
Gulf Coast, TX/LA..................   10    0.60    12   2.90    2,934      420
Uinta Basin, UT....................   20   15.42     0   0.00      --       --
Miscellaneous Properties...........  233   18.52    93  58.30   45,403   30,741
                                     ---  ------ ----- ------ -------- --------
  Total............................  854  332.27 1,203 640.87  372,695  237,925
                                     ===  ====== ===== ====== ======== ========
</TABLE>
--------
(a) Each well completed to more than one producing zone is counted as a single
    well.
(b) The Company has royalty interests in certain wells that are not included
    in this table.
 
                                      11
<PAGE>
 
 Drilling Activity
 
  The following table summarizes the Company's oil and gas drilling
activities, all of which were located in the continental United States, during
the last three years:
 
<TABLE>
<CAPTION>
                                                   YEAR ENDED DECEMBER 31,
                                             -----------------------------------
                                                1995        1994        1993
                                             ----------- ----------- -----------
WELLS DRILLED                                GROSS  NET  GROSS  NET  GROSS  NET
-------------                                ----- ----- ----- ----- ----- -----
<S>                                          <C>   <C>   <C>   <C>   <C>   <C>
Exploratory
  Oil.......................................    1   0.33    5   0.58    1   0.10
  Gas.......................................    0   0.00    1   0.50    0   0.00
  Non-productive............................    8   2.65    8   1.84   12   4.55
                                              ---  -----  ---  -----  ---  -----
    Total...................................    9   2.98   14   2.92   13   4.65
                                              ===  =====  ===  =====  ===  =====
Development
  Oil.......................................   22  11.68   19  12.62   13  10.40
  Gas.......................................   88  39.03  100  36.51   70  24.29
  Non-productive............................   10   3.51   18   7.65    9   1.35
                                              ---  -----  ---  -----  ---  -----
    Total...................................  120  54.22  137  56.78   92  36.04
                                              ===  =====  ===  =====  ===  =====
</TABLE>
 
  In addition, the Company was participating in 10 gross (2.97 net) wells
which were in the process of being drilled at December 31, 1995.
 
 Reserves
 
  The table below sets forth the Company's estimated quantities of proved
reserves, all of which were located in the continental U.S., and the present
value of estimated future net revenues from these reserves on a non-escalated
basis, discounted by 10 percent per year, as of the end of each of the last
three years:
 
<TABLE>
<CAPTION>
                                                     DECEMBER 31,
                                        --------------------------------------
                                            1995         1994         1993
                                        ------------ ------------ ------------
<S>                                     <C>          <C>          <C>
Estimated Proved Oil Reserve (MMbls)...       12,967       11,443        6,946
Estimated Proved Gas Reserves (MMcf)...      513,531      458,820      364,791
Estimated Proved Reserves in Gas
 Equivalents (MMcfe)...................      591,331      527,478      406,468
Prices as of December 31, for Oil
 ($/Bbl)............................... $      17.35 $      14.43 $      11.05
Prices as of December 31, for Gas
 ($/Mcf)............................... $       1.77 $       1.67 $       1.95
Present Value of Estimated Future Net
 Revenues
 (before future income tax expense).... $432,603,000 $322,689,000 $277,571,000
</TABLE>
 
  Reference should be made to "SUPPLEMENTAL OIL AND GAS INFORMATION" on page
F-20 of this report for additional information pertaining to the Company's
proved oil and gas reserves. During 1995, the Company filed, prior to the
merger, as Barrett and Plains, the Annual Survey of Domestic Oil and Gas
Reserves with the Energy Information Administration (EIA) as required by law.
Only minor differences of less than five percent are anticipated in reserve
estimates, which were due to small variances in actual production versus year
end estimates, and in certain classifications reported in Form 10-K as
compared to those in the EIA report.
 
                                      12
<PAGE>
 
 Undeveloped Acreage
 
  Working Interest. The Company's working interests in undeveloped acreage as
of December 31, 1995 are summarized in the following table:
 
<TABLE>
<CAPTION>
                                                               WORKING INTEREST
                                                                     ACRES
                                                               -----------------
   STATE OF LOCATION                                            GROSS     NET
   -----------------                                           -----------------
   <S>                                                         <C>      <C>
   Arkansas...................................................      360      360
   Colorado...................................................   78,737   23,815
   Louisiana..................................................    5,803    1,516
   Montana....................................................   15,950    8,255
   New Mexico.................................................      240      240
   North Dakota...............................................   12,721    2,684
   Oklahoma...................................................   39,948   20,203
   Texas......................................................   22,937    4,493
   Utah.......................................................   10,823    9,703
   Wyoming....................................................  221,238  119,723
   Offshore...................................................   12,500    2,713
                                                               -------- --------
     Total....................................................  421,257  193,705
                                                               ======== ========
</TABLE>
 
  Substantially all of the leases summarized in the preceding table will
expire at the end of their respective primary terms unless 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 proceeding table that will expire:
 
<TABLE>
<CAPTION>
                                                                 ACRES EXPIRING
                                                                 ---------------
                                                                  GROSS    NET
                                                                 ------- -------
   <S>                                                           <C>     <C>
   Twelve Month Ending:
     December 31, 1996..........................................  82,041  23,555
     December 31, 1997..........................................  72,902  32,016
     December 31, 1998..........................................  45,551  25,636
     December 31, 1999 and later................................ 220,763 112,496
</TABLE>
 
  Overriding Royalty Interests. The Company owns overriding royalty interests
covering in excess of 52,394 gross acres. The majority of these overriding
royalty interests are within a range of approximately 0.25 to 2.5 percent.
 
 Gas Gathering
 
  The Company currently owns interests in and operates three gas gathering
systems through its wholly owned subsidiary, Bargath Inc. ("Bargath"). All
three systems connect to producing wells, in which the Company owns an
interest. The Company also owns various gathering assets in the Hugoton Field
through another wholly owned subsidiary, Plains Petroleum Gathering Company.
 
  Grand Valley and Trailridge Gas Gathering Systems. In 1985, Bargath designed
and constructed a gathering system in the Grand Valley Field to transport
natural gas from certain of the Company's wells to Questar Pipeline
Corporation's interstate pipeline at Rifle, Colorado. As of December 31, 1995,
the Grand Valley Gathering System was connected to 210 producing gas wells in
the Piceance Basin.
 
  The system has the flexibility to deliver gas to three interstate pipelines,
owned by Questar Pipeline Company, Northwest Pipeline Corporation, and
Colorado Interstate Gas Company, and one intrastate pipeline owned by Public
Service Company of Colorado and KN Energy, Inc. In December 1994, the Company
 
                                      13
<PAGE>
 
completed the construction of a 90,000 MMBtu per day gas processing plant to
extract liquid hydrocarbons from the gas stream. Depending on the take-away
capacity from time to time of these four pipeline systems, the gathering
system has the capability of delivering approximately 110,000 MMBtu of gas per
day. Bargath owns a 29.5 percent interest in and operates these systems in the
Piceance Basin.
 
  Latham Draw Gathering System. During fiscal 1992, Bargath designed and
constructed a gas gathering system in southwestern Wyoming to connect wells
drilled and completed by the Company on the Red Desert-Washakie prospect. To
date, the system consists of approximately 30 miles of pipeline connecting
seven gas wells. The Latham Draw Gathering System interconnects with the
Colorado Interstate Gas Co. interstate pipeline. Bargath owns a 48 percent
interest in and operates the Latham Draw Gathering System. At year end 1995,
the Company was negotiating to exchange these assets for assets that were more
closely aligned to its core needs.
 
  Blue Mountain Gathering System. The Company acquired the Blue Mountain
Gathering System in January 1995, to compliment drilling activity Barrett was
conducting in Latimer County, Oklahoma. The 5 1/2 mile system moves Barrett's
and third party gas into NorAm Gas Transmission System for flow to Midwest and
East Coast markets.
 
 Gas Marketing and Trading
 
  Natural Gas. The Company's gas marketing and trading activities consist of
marketing the Company's own production, and the production of others from
wells operated by the Company, and trading activities that consist of the
purchase and resale of natural gas.
 
  The Company has entered into a number of gas sales agreements on behalf of
itself and its industry partners with respect to the sale of 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, 1995, approximately 33 percent of the Company's
production was committed to gas sales contracts that had fixed prices.
However, with the exception of one contract covering approximately 1,500 MMBtu
per day of production from the Piceance Basin through 2011, none of the
contracts provides for fixed prices beyond March 1996. The Company believes
that it has sufficient production from its properties to meet the Company's
delivery obligations under its existing gas sales contracts.
 
  For 1996, the Company successfully renegotiated the pricing provisions
associated with its Hugoton and Panoma-Council Grove gas production. Pricing
is based upon the average price of a basket of four Mid-Continent indexes on a
monthly basis less a variable amount not to exceed $0.20 per MMbtu.
 
  During the year ended December 31, 1995, there was one gas purchaser who
accounted for approximately 18 percent of the Company's total revenues. The
Company believes it would be able to locate alternate customers in the event
of the loss of this customer.
 
  As a result of its gas trading activities, the Company may from time to time
have gas purchase or sales commitments without corresponding contracts to
offset these commitments, which could result in losses to the Company. The
Company currently attempts to control and manage its exposure to these risks
by monitoring and hedging its trading positions as it deems appropriate and by
having the Company's financial officers and Chief Executive Officer review
significant trades or positions before they are committed to by trading
personnel. All fixed price trading activities are hedged to lock in margins.
 
  During the year ended December 31, 1995, revenue from trading activities,
which includes the cost of gas purchased or sold for trading purposes, was
$28.6 million, representing 22 percent of the Company's consolidated revenues.
 
  Gas trading is highly competitive and the Company competes with many other
companies, some of which have more experience, personnel, and other resources
available to them. However, management does not believe
 
                                      14
<PAGE>
 
that any one competitor is dominant in the industry. The Company's ability to
generate profits from natural gas trading is dependent primarily on the
knowledge and experience of its employees. It is also dependent on its ability
to anticipate changes and trends in the natural gas market, including future
gas prices, which to a degree, depend upon factors beyond the Company's
control, such as gas supplies, competing fuel supplies, the weather, consumer
attitudes, the demand for natural gas, transportation constraints, and
government actions and regulations.
 
  Oil and Condensate. Oil, including wellhead condensate production, is
generally sold from the leases at currently posted field prices, plus
negotiated bonuses. Marketing arrangements are made locally with various
petroleum companies. The Company sells its oil production to numerous
customers. No customer's total 1995 oil purchases represented more than 10
percent of total Company revenues. Oil revenues totaled $26.8 million for 1995
and represented 21 percent of the Company's total revenues for the year.
 
 Government Regulation
 
  The production of oil and gas is subject to a variety of federal, state and
local government regulations including regulations concerning the prevention
of waste, the discharge of materials into the environment, the conservation of
oil and natural gas, pollution, permits for drilling operations, drilling
bonds, reports concerning operations, the spacing of wells, the unitization
and pooling of properties, and various other matters including taxes. The
costs of complying with these regulations, of monitoring compliance with these
regulations, and of dealing with the agencies that administer them, can be
significant.
 
  At present, there are 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. The Company believes that expenditures
for compliance with current federal, state or local provisions regulating the
discharge of materials into the environment, or otherwise relating to the
protection of the environment, will not have a material adverse effect in the
future upon the capital expenditures, earnings or competitive position of the
Company.
 
 Operating Hazards
 
  The Company's operations are subject to all the risks normally incident to
the exploration for and production of oil and gas, including blowouts,
encountering formations with abnormal pressure, cratering, pollution and
fires. Any of these events could result in damage to, or destruction of, oil
and gas wells or producing facilities, suspension of operations, damage to
property or the environment, and injury to persons. Losses and liabilities
arising from such events could reduce revenues and increase costs to the
extent the Company is liable and such loss or liability is not covered by
insurance. The Company maintains insurance, which it believes is customary in
the industry against some, but not all, of these risks. There is no assurance
that such insurance will continue to be available in the future at a
reasonable cost.
 
ITEM 3. LEGAL PROCEEDINGS
 
  On November 2, 1994, a putative class action was filed in Delaware Chancery
Court. In that case, entitled Miller v. Cody, the plaintiff has alleged that
certain named former directors of Plains and Plains have, among other things,
breached their fiduciary duties and otherwise acted to entrench themselves in
office. Plaintiff seeks various forms of injunctive relief, damages and an
award of plaintiff's costs and disbursements.
 
  On May 3, 1995, the same day Plains announced it had executed a merger
agreement with the Company, a putative class action, entitled Crandon Capital
Partners v. Miller, was filed in Delaware Chancery Court against Plains and
the then-current members of its Board of Directors. In this suit, it is
alleged that, among other things, the agreement was inadequate, plaintiff
seeks various forms of declaratory and injunctive relief, damages and an award
of plaintiff's costs and disbursements.
 
 
                                      15
<PAGE>
 
  Plains and its former directors have received a status report filed by
plaintiffs' counsel in both cases indicating a "stipulation of dismissal
without prejudice will be circulated shortly."
 
  Except as noted above, at December 31, 1995, 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, 1995.
 
                                    PART II
 
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SECURITY HOLDERS
MATTERS.
 
  (a) Market Information. Beginning on November 29, 1994, the Company's Common
Stock was listed and began trading on the New York Stock Exchange under the
symbol BRR. Before trading on the New York Stock Exchange, the Company's
Common Stock was traded on NASDAQ National Market System under the symbol
BARC. 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, 1994*................................................ $14.37 $10.37
   June 30, 1994*.................................................  16.50  13.25
   September 30, 1994*............................................  20.00  15.62
   December 31, 1994..............................................  22.75  17.87
   March 31, 1995.................................................  21.75  16.87
   June 30, 1995..................................................  25.87  19.37
   September 30, 1995.............................................  25.37  19.37
   December 31, 1995..............................................  30.62  21.00
</TABLE>
--------
* As reported by NASDAQ, before the Company's Common Stock began trading on
  the NYSE.
 
  On March 12, 1996, the closing price for the Company's Common Stock was
$22.625 per share.
 
  (b) Holders. The approximate number of record holders of the Company's
Common Stock as of March 12, 1996, was 4,956.
 
  (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.
 
                                      16
<PAGE>
 
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,
                         -----------------------------------------------------------------
                             1995          1994         1993         1992         1991
                         ------------  ------------ ------------ ------------ ------------
<S>                      <C>           <C>          <C>          <C>          <C>
Revenues................ $128,016,000  $109,458,000 $106,072,000 $ 89,050,000 $ 74,835,000
Net income (loss).......   (2,240,000)   11,299,000   13,666,000   13,872,000   19,167,000
 Per share..............        (0.09)         0.46         0.55         0.47         0.84
Total assets at the end
 of each period.........  340,412,000   310,952,000  243,452,000  208,601,000  184,187,000
Long-term debt at the
 end of each period.....   89,000,000    53,000,000   13,500,000   20,000,000   15,000,000
</TABLE>
 
ITEM 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
 
  On July 18, 1995, the Company consummated the merger of a wholly owned
subsidiary of the Company with Plains Petroleum Company ("Plains") by issuing
12.8 million shares of its common stock to the former Plains stockholders. As
a result of this merger, Plains became a wholly owned subsidiary of the
Company. Also, on July 18, 1995, the Company changed its fiscal year end from
September 30 to December 31 effective January 1, 1995. The merger is being
accounted for using the pooling of interests method. The pooling of interests
method combines previously reported results as though the combination occurred
at the beginning of the periods being presented. Merger costs have been
expensed during the 1995 year. The financial statements of the Company and
Plains for the 1993, 1994 and 1995 years have been restated and adjusted for
the merger with Plains and the change in fiscal year end. Due to this
restatement, these financial statements are not comparable to the financial
statements for the same periods as previously presented by the separate
companies.
 
 Liquidity and Capital Resources
 
  At December 31, 1995, the Company had cash and short-term investments of
$7.5 million, working capital of $3.7 million, property and equipment of
$300.7 million and total assets of $340.4 million. Compared to December 31,
1994, cash and short-term investments decreased $4.8 million, working capital
increased $1.2 million and property and equipment increased $39.2 million.
Total assets increased $29.5 million as the increase in property and equipment
was funded by a $36.0 million increase in long-term debt. During 1995, the
Company actively invested in oil and gas properties in its areas of activity,
which increased both property and equipment and long-term debt.
 
  During 1995, the Company generated operating cash flow of $33.4 million
before working capital changes, which is $5.6 million less than the amount
generated in 1994, as production increases were offset by merger costs
incurred during the year. After working capital changes, cash flow provided by
operations was $35.5 million, a decrease of three percent from 1994. Excluding
merger costs, cash flow from operations before working capital changes was
$47.6 million, ($49.7 million after working capital changes).
 
  As of December 31, 1995, the outstanding balance under the bank line of
credit was $89 million, a net increase of $36 million from the balance at
December 31, 1994. In July 1995, the Company entered into a $200 million
credit agreement. The line of credit matures on July 19, 1999 and is funded by
a consortium of six banks. The line of credit is unsecured and provides for
interest rates based on LIBOR or prime rates at the Company's option. The
availability under the Credit Agreement is based on the bank's review of the
collateral value of the Company's oil and gas properties. The current
borrowing base is $160 million determined from a review of the oil and gas
reserves as of December 31, 1994 for Plains and March 31, 1995 for Barrett.
The borrowing base is scheduled for a review in early 1996 based on the
Company's December 31, 1995 reserves.
 
 
                                      17
<PAGE>
 
  During the year, the Company invested $72.3 million in property and
equipment principally in the Piceance, Wind River and Arkoma Basins. The
Company's drilling activities were primarily to develop and extend producing
fields. Included in oil and gas property additions is $7.4 million to purchase
interests in proved properties to acquire 4.0 Bcf of gas and 831,000 barrels
of oil.
 
  During 1995, the Company increased its gas reserves by 12 percent to 514 Bcf
and its oil reserves by 13 percent to 13.0 million barrels. The Company
replaced 210 percent of its 1995 production. On an energy equivalent basis,
the Company's reserves are 87 percent natural gas. Proved undeveloped reserves
are 17 percent of the Company's total reserves, virtually unchanged from
December 31, 1994. Thirty-four percent of the Company's reserves are located
in the Hugoton Embayment, 20 percent are located in the Piceance Basin, and 15
percent are located in the Wind River Basin.
 
  Reserve quantities increased 12 percent on an energy equivalent basis over
the last year, while the standardized measure of discounted future net cash
flows increased $67.3 million, 28 percent, primarily due to reserve additions
and an increase in the sales price of oil and gas. As of December 31, 1995,
the Company was receiving an average of $17.35 per barrel for its oil
production and $1.77 per Mcf for its gas production. Reserve extensions and
discoveries added $85.5 million to the standardized measure, and purchases of
proved reserves added $7.4 million to the valuation. In addition the change in
sales prices and production costs increased the standardized measure of
discounted future net cash flows by $24.6 million. These additions were offset
by a $62.3 million reduction due to reserves produced during the year and
$33.2 million for additional income taxes being deducted in the computation.
The Company's reserve values remain sensitive to gas prices in the current
volatile commodities market.
 
  The Company uses gas price swaps to hedge the sales price of its oil and
natural gas. In a typical swap agreement, the Company and a counter party will
enter into an agreement whereby one party will pay a fixed price and the other
will pay an index price on a specified volume of production during a specified
period of time. Settlement is made by the parties for the difference between
the two prices approximately the same time as the physical transactions. The
intent of hedging activities is to reduce the volatility associated with the
sales price of oil and gas production.
 
  As of December 31, 1995 the Company held positions to hedge 16.9 Bcf of gas
and 91,000 barrels of oil for periods through March 31, 1996. Of these
positions, 834,000 Mcf of gas were being hedged to reduce risks associated
with gas trading activities, and the balance was associated with producing
activities. These positions include various hedging instruments based on
exchange based sales prices, index denominated prices or a combination of
both. The positions are more fully described in the notes to the financial
statements. During December 1995 the gas commodities market used as a basis
for the Company's hedging activities became unusually volatile causing
significant differences between the underlying commodity price and the market
price of the Company's gas production in certain basins. As a result, the
Company recorded an expense of $1.2 million in the fourth quarter due to the
lack of correlation between the hedging instrument and the sales price of
underlying natural gas.
 
  The Company's merger with Plains and its drilling activities have increased
its reserve base and its productive capacity and, therefore, its potential
cash flow. Continued low gas prices may adversely affect cash flow. The
Company intends 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
believes that the Company's borrowing capacities and cash flow are sufficient
to fund its currently anticipated activities. The Company intends to continue
to use financial leverage to fund its operations as investment opportunities
become available on terms that management believe warrant investment of the
Company's capital resources.
 
 
                                      18
<PAGE>
 
 Results of Operations
 
  1995 VS. 1994
 
  During 1995, the Company incurred a net loss of $2.2 million ($.09 per
share) compared to net income of $11.3 million ($.46 per share) in 1994. The
1995 results include merger and reorganization costs of $14.2 million.
Excluding the merger costs, the Company's net income after taxes would be $9.5
million ($.38 per share).
 
  Revenues increased 17 percent from 1994 to $128.0 million and operating
expenses, including $14.2 million of merger and reorganization costs,
increased 38 percent to $128.4 million. Oil and gas production revenue
increased 23 percent to $97.0 million. Lease operating expenses increased $6.3
million and depreciation, depletion and amortization increased $10.7 million.
 
  Production revenues increased $18.2 million primarily due to a 43 percent
increase in gas production to 47.7 Bcf (130,700 Mcf per day). Oil production
increased 32 percent to 1,702,000 barrels (4,660 barrels per day). Average gas
sales prices decreased 20 percent to $1.47 per Mcf, while average oil prices
increased 13 percent to $15.76 per barrel. Gas production accounted for 82
percent of total production on an energy equivalent basis. The Hugoton
Embayment and Piceance Basin properties accounted for 37 and 14 percent,
respectively, of total gas production. The Powder River and Permian Basins
accounted for 43 and 32 percent, respectively, of total oil production. The
decreased gas sales price was due to an overall deterioration in gas markets
during most of the year.
 
  Lease operating expenses of $34.5 million averaged $.60 per Mcfe ($3.58 per
BOE) of production compared to $.69 per Mcfe ($4.13 per BOE) in 1994.
Depreciation, depletion and amortization increased $10.7 million primarily due
to production increases. During 1995, depreciation, depletion and amortization
on oil and gas production was provided at an average rate of $.55 per Mcfe
($3.28 per BOE) compared to an average rate of $.52 per Mcfe ($3.14 per BOE)
in 1994.
 
  The gross margin on trading activities was virtually unchanged from 1994 at
$943,000. Gas trading volumes increased 26 percent to 22.2 Bcf in 1995.
 
  During 1995, the Company hedged 4.9 Bcf (22 percent) of its gas trading
volumes to achieve the margins on specific transactions at a cost of $2.1
million. In addition, the Company hedged 11.0 Bcf (23 percent) of gas
production for a net gain of $417,000. The hedging gain related to production
is net of $1.2 million for an expense recorded in the fourth quarter due to a
lack of correlation of the hedging instruments to the underlying commodity as
of December 31, 1995. The Company enters into the hedging arrangements to
minimize its exposure to price risks associated with commodities markets.
Although hedging transactions associated with its production minimize 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. At the end of December, 1995, the basis differential between the
commodities markets and the market price of the Company's gas widened to
historic levels. Because the increase in the commodities price was not
accompanied by a similar increase in the market price of the Company's gas,
the Company recorded an expense for the difference due to the inefficient
hedge and positions that did not qualify for hedge accounting treatment. With
respect to trading activities, the Company will not generally enter into a
commitment for either a purchase or a sale unless (i) it has established a
commitment for an offsetting sale or purchase, or (ii) it has established a
hedge arrangement with a counter party that creates the same matching
position.
 
  General and administrative expenses of $13.4 million are one percent greater
than the previous year. The 1995 amount is net of $3.8 million of operating
fee recoveries compared to a $3.4 million recovery in 1994. General and
administrative expense in 1995 is generally a combination of the separate
companies' expenses, since the integration of the two entities did not occur
until late in the year, and included costs for the Company to expand its
business in existing and new activity areas. The Company expects a reduction
in general and administrative expenses due to the elimination of duplicative
costs throughout 1996. Interest expense increased
 
                                      19
<PAGE>
 
significantly from $942,000 in 1994 to $4.6 million in 1995 as the Company
financed a portion of its growth with bank debt. The Company incurred a 1995
expense of $14.2 million to combine Barrett and Plains and to integrate the
separate company's operations. The costs consist primarily of $7.4 million of
investment banker and other professional fees to evaluate and consummate the
merger and $5.6 million for employee termination and benefit costs.
 
  During 1995, the Company recorded a $1.8 million income tax expense even
though it incurred a loss before taxes due to non-deductible merger costs.
Excluding non-deductible merger costs, the Company would have had a $600,000
tax benefit.
 
  The Company's results of operations depend primarily on the production of
natural gas which accounted for 87 percent of the Company's reserves and 82
percent of its production during 1995. Therefore, the Company's future results
will depend on both the volume of natural gas production and the sales price
for gas. The Company continues to explore for oil and gas to increase its
production. The lack of predictability of both production volumes and sales
prices may influence future operating results.
 
  1994 VS. 1993
 
  During 1994, the Company earned net income of $11.3 million ($.46 per share)
compared to net income of $13.7 million ($.55 per share) in 1993. The 1994
results include a tax benefit of $2.1 million due to an increase in financial
reporting value of the Company's net operating loss carryover. Without the tax
benefit from the net operating loss carryover, the Company's net income after
taxes in 1994 would have been $9.2 million ($.37 per share). The 1993 results
include a tax benefit of $1.4 million from the value of the tax loss carryover
and an expense of $656,000 for the cumulative effect of adopting SFAS No. 106
to recognize accumulated post retirement benefit liabilities as of January 1,
1993. Net income before income taxes and the cumulative effect of the change
in accounting method was $16.4 million in 1994 compared to $21.0 million in
1993.
 
  Revenues increased three percent from 1993 to $109.5 million, and operating
expenses increased nine percent to $93.0 million. Production revenue decreased
$2.1 million, and trading revenues increased $5.2 million. These changes were
offset by a decrease of $2.1 million in lease operating expenses, an increase
of $2.6 million in depreciation, depletion and amortization and an increase of
$5.5 million in the cost of trading.
 
  Production revenues decreased $2.1 million as a five percent increase in gas
production was offset by a six percent decrease in the average gas sales price
and a seven percent decline in the average oil sales price. Oil production was
virtually unchanged from 1993 to 1994. During 1994, the Company produced
91,200 Mcf of gas per day and 3,540 barrels of oil per day. Gas production
accounted for 81 percent of total production on an energy equivalent basis of
41.0 Bcf of gas equivalent (6.8 million barrels of oil equivalent). During
1994, the average gas sales price was $1.83 per Mcf ($1.94 in 1993) and the
oil sales price was $13.95 per barrel ($14.94 in 1993). The decreased oil and
gas sales prices were due to an overall market reduction in the commodity
prices of the products.
 
  Lease operating expenses of $28.2 million averaged $.69 per Mcfe ($4.13 per
BOE) of production compared with $.77 per Mcfe ($4.62 per BOE) in 1993.
Depreciation, depletion and amortization increased $2.6 million primarily due
to production increases. During 1994, depreciation, depletion and amortization
on oil and gas production was provided at an average rate of $.52 per Mcfe
($3.14 per BOE) compared to an average rate of $.48 per Mcfe ($2.87 per BOE)
in 1993.
 
  The gross margin on trading activities decreased to $924,000 from $1.3
million in 1993. Gas trading volumes increased 62 percent to 17.5 Bcf in 1994.
The reduced results are due to a reduction of margins available for gas
trading activities.
 
  General and administrative expenses of $13.3 million are 18 percent greater
than the previous year. The 1994 amount is net of $3.4 million of operating
fee recoveries compared to a $3.8 million recovery in 1993. The
 
                                      20
<PAGE>
 
increased general and administrative expense is due to additional costs
incurred by the Company to expand its activities and to explore in other
areas.
 
  During 1994, the Company recorded a $5.1 million net income tax expense
compared to a $6.7 net income tax expense in 1993. The 1994 expense is net of
a $2.1 million reduction in the valuation allowance provided for the deferred
income tax benefit of the net operating loss carryover. The valuation
allowance was reduced to reflect increased oil and gas reserves that are
expected to generate future taxable income and the tax gain realized on the
sale of the Wattenberg properties.
 
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.
 
                                      21
<PAGE>
 
                                    PART III
 
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY
 
  The following table sets forth certain information with respect to the
directors and executive officers of the Company, including, with respect to
each individual, his age, his position with the Company, the expiration of his
term as a director, and the year in which he first became a director of the
Company. Additional information concerning each of these individuals follows
the table:
 
<TABLE>
<CAPTION>
                                   POSITION WITH        EXPIRATION OF   INITIAL DATE
          NAME           AGE      THE COMPANY (7)      TERM AS DIRECTOR AS DIRECTOR
          ----           --- ------------------------- ---------------- ------------
<S>                      <C> <C>                       <C>              <C>
William J. Barrett ..... 67  Chief Executive           Next Annual          1983
 (3)                         Officer and Chairman      Meeting
                             of the Board of
                             Directors
C. Robert Buford........  61 Director                  Next Annual          1983
 (1)(2)(6)                                             Meeting
Derrill Cody............  57 Director                  Next Annual          1995
 (1)(2)                                                Meeting
James M. Fitzgibbons....  61 Director                  Next Annual          1987
 (1)(2)(4)                                             Meeting
Hennie L.J.M. Gieskes...  55 Director                  Next Annual          1985
 (1)(2)                                                Meeting
William W. Grant, III...  63 Director                  Next Annual          1995
 (1)                                                   Meeting
J. Frank Keller.........  52 Chief Financial Officer,  Next Annual          1983
 (3)                         Executive Vice President, Meeting
                             Secretary, and a Director
Paul M. Rady............  42 President, Chief          Next Annual          1994
                             Operating Officer,        Meeting
                             and a Director
A. Ralph Reed...........  58 Executive Vice            Next Annual          1990
                             President--Operations     Meeting
                             and a Director
James T. Rodgers........  61 Director                  Next Annual          1993
 (1)(2)                                                Meeting
Philippe S.E.             55 Director                  Next Annual          1985
 Schreiber..............                               Meeting
 (1)(2)(7)
William F. Wallace......  56 Vice Chairman             --(8)                1995
                             of the Board of Directors
Harry S. Welch..........  72 Director                  Next Annual          1995
 (2)                                                   Meeting
Joseph P. Barrett.......  42 Vice President--          --                    --
 (9)
Robert W. Howard........  41 Senior Vice               --                    --
                             President--Finance
                             and Treasurer
Eugene A. Lang, Jr......  42 Senior Vice President--   --                    --
                             General Counsel
Donald H. Stevens.......  43 Vice President--          --                    --
 (10)                        Corporate Relations
                             and Capital Markets
</TABLE>
 
                                       22
<PAGE>
 
--------
(1) Member of the Audit Committee of the Board of Directors.
(2) Member of the Compensation Committee of the Board of Directors.
(3) Mr. Barrett and Mr. Keller are brothers-in-law.
(4) 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.
(5) All officers are elected annually at the first Board Of Directors' meeting
    following the annual meeting of stockholders.
(6) One transaction in July 1995, required to be reported by Mr. Buford on a
    Statement Of Change In Beneficial Ownership Of Securities on Form 4, was
    reported late with the Securities and Exchange Commission ("SEC") on a
    Form 5, Annual Statement Of Changes In Beneficial Ownership.
(7) A Statement Of Changes In Beneficial Ownership Of Securities on Form 4
    with respect to one transaction by Mr. Schreiber in November 1995 was
    filed two days late with the SEC.
(8) Mr. Wallace resigned as Vice Chairman and as a member of the Board of
    Directors of the Company effective January 11, 1996.
(9) Joseph P. Barrett is the son of William J. Barrett.
(10) One transaction in October 1995, required to be reported by Mr. Stevens
     on a Statement Of Changes In Beneficial Ownership Of Securities on Form
     4, was reported late with the SEC on a Form 5, Annual Statement Of
     Changes In Beneficial Ownership.
 
  William J. Barrett has been Chief Executive Officer since December 1983 and
Chairman of the Board of Directors of the Company since March 1994. Mr.
Barrett was President of the Company from December 1983 through September
1994. Mr. Barrett has been the Chairman of the Board, Chief Executive Officer,
and a director of Plains since it became a wholly owned subsidiary of the
Company as the result of a merger in July 1995. Mr. Barrett has also been a
director of Barrett Fuels Corporation, a wholly owned subsidiary of the
Company, since its formation in September 1990. From January 1979 to February
1982, Mr. Barrett was an independent oil and gas operator in the western
United States in association with Aeon Energy, a partnership composed of four
sole proprietorships. From 1971 to 1978, Mr. Barrett served as Vice
President--Exploration and a director of Rainbow Resources, Inc., a publicly
held independent oil and gas exploration company that merged with a subsidiary
of the Williams Companies in 1978. Mr. Barrett served as President,
Exploration Manager and Director for B&C Exploration from 1969 until 1971 and
was a chief geologist for Wolf Exploration Company, now known as Inexco Oil
Co., from 1967 to 1969. He was an exploration geologist with Pan-American
Petroleum Corporation from 1963 to 1966 and worked as an exploration
geologist, a petroleum geologist and a stratigrapher for El Paso Natural Gas
Co. at various times from 1958 to 1963. Mr. Barrett received a B.S. Degree in
Geology and an M.S. Degree in Geology from Kansas State University in 1956 and
1957, respectively.
 
  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 is engaged in the oil and gas business and owns
approximately three 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 First Bancorp of Wichita, Kansas, a
bank holding company, and Lonestar Steakhouse & Saloon, Inc., a restaurant
company headquartered in Wichita, Kansas. He received a B.A. Degree in
Business Administration from Oklahoma State University in 1955.
 
  Derrill Cody has been a director of the Company since July 1995. Mr. Cody
was a director of Plains from May 1990 through July 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. He has been a director of the General partner of
TEPPCO Partners, L.P. since January 1990. Mr. Cody received a B.A. Degree in
History from East Central State College in 1960 and an L.L.B. from the
University of Oklahoma in 1964.
 
 
                                      23
<PAGE>
 
  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 October 1990, Mr. Fitzgibbons has been Chairman and Chief
Executive Officer of Fieldcrest Cannon, Inc., a manufacturer of home
furnishing textiles. From January 1986 until October 1990, Mr. Fitzgibbons was
President of Amoskeag Company in Boston, Massachusetts. Prior to 1986, he was
President of Howes Leather Company, a producer of leather. Mr. Fitzgibbons is
also member of the Board Of Directors of Lumber Insurance Company, American
Textile Manufacturers Institute and a Trustee of Laurel Funds, a series of
mutual funds. Mr. Fitzgibbons received an A.B. Degree from Harvard College in
1956.
 
  Hennie L.J.M. Gieskes has been a director of the Company since November
1985. Mr. Gieskes is the Managing Director of Spaarne Compagnie N.V., a
Netherlands company engaged in the investment business. From before 1976 until
December 1990, Mr. Gieskes was a Managing Director of Vitol Beheer B.V.
("Vitol"), a Netherlands trading company engaged primarily in energy-related
commodities. Mr. Gieskes received a law degree from the University of
Amsterdam, The Netherlands, in 1968.
 
  William W. Grant, III has been a director of the Company since July 1995.
Mr. Grant was a director of Plains from May 1987 through July 1995. He has
been an advisory director of Colorado National Bankshares, Inc. and Colorado
National Bank since 1993. He was a director of Colorado National Bankshares,
Inc. from 1982 to 1993 and the Chairman of the Board of Colorado National Bank
from 1986 to 1993. He served as the Chairman of the Board of Colorado Capital
Advisors from 1989 through 1994. Mr. Grant received a B.A. Degree in English
from Yale University in 1954 and attended the Harvard University Graduate
School of Business' Advanced Management Program from 1970 to 1971.
 
  J. Frank Keller has been Chief Financial Officer since July 1995 and an
Executive Vice President, the Secretary and a director of the Company since
December 1983. Mr. Keller has been the Chief Financial Officer, an Executive
Vice President, the Secretary, and a director of Plains, a wholly owned
subsidiary, since July 1995. He also has been the President and a director of
Barrett Fuels Corporation since its formation in September 1990. Mr. Keller
was an Executive Vice President of the Company from December 1983 through
September 1995. Mr. Keller was the President and a co-founder of Myriam Corp.,
an architectural design and real estate development firm beginning in 1976,
until it was reorganized as Barrett Energy in February 1982. Mr. Keller
graduated from Kansas State University in 1967 with a B.S. Degree and received
an M.B.A. Degree from Colorado State University in 1992.
 
  Paul M. Rady has been President, Chief Operating Officer, and a director of
the Company since September 1994. Prior to that time Mr. Rady served as
Executive Vice President--Exploration of the Company beginning February 1993.
Mr. Rady has been the President, Chief Operating Officer, and a director of
Plains, a wholly owned subsidiary, since July 1995. From August 1990 until
July 1992, Mr. Rady served as Chief Geologist for the Company, and from July
1992 until January 1993 he served as Exploration Manager for the Company. From
July 1980 until August 1990, Mr. Rady served in various positions with the
Denver, Colorado regional office of Amoco Production Company, the exploration
and production subsidiary of Amoco Corporation. Mr. Rady was a Geologist and
Geophysicist for Amoco Production Company. While with Amoco Production
Company, Mr. Rady's areas of responsibility included the Rocky Mountain
Basins, Utah-Wyoming Overthrust Belt, offshore Alaska, Oklahoma, particularly
with respect to the Arkoma Basin, and the New Ventures Group, which
concentrated on the western United States. Mr. Rady received a B.A. Degree in
Geology in 1978 from Western State College of Colorado in Gunnison, Colorado,
and an M.S. Degree in Geology in 1980 from Western Washington University in
Bellingham, Washington.
 
  A. Ralph Reed has been an Executive Vice President of the Company since
November 1989 and a director of the Company since September 1990. Mr. Reed has
served as Executive Vice President--Operations and a director of Plains, a
wholly owned subsidiary, since July 1995. From 1986 to 1989, Mr. Reed was an
independent oil and gas operator in the Mid-Continent region of the United
States, including the period from January 1988 to November 1989 when he acted
as a consultant to Zenith Drilling Corporation. From 1982 to 1986, Mr. Reed
was President and Chief Executive Officer of Cotton Petroleum Corporation, a
wholly owned exploration and
 
                                      24
<PAGE>
 
production subsidiary of United Energy Resources, Inc. Prior to joining Cotton
Petroleum Corporation in 1980, Mr. Reed was employed by Amoco Production
Company from 1962, holding various positions including Manager of
International Production, Division Production Manager and Division Engineer.
Mr. Reed received a B.S. Degree in Petroleum Engineering from the University
of Oklahoma in 1959 and in 1975 attended the Executive School at the
University of Virginia.
 
  James T. Rodgers has been a director of the Company since October 1993. Mr.
Rodgers served as the President, Chief Operating Officer and a director of
Anadarko Petroleum Corporation ("Anadarko") from 1986 through 1992. Anadarko
is a Houston-based oil and gas exploration and production company. Prior to
1986, Mr. Rodgers was employed in other capacities by Anadarko and Amoco
Production Company. Mr. Rodgers taught Petroleum Engineering at the University
of Texas in Austin in 1958 and at Texas Tech University in Lubbock from 1958
to 1961. Mr. Rodgers currently serves as a Director of Louis Dreyfus Natural
Gas Corporation and as an Advisory Director for Texas Commerce Bank in
Houston. Mr. Rodgers received a B.S. Degree from Louisiana State University in
1956 and an M.S. Degree from the University of Texas in 1958.
 
  Philippe S.E. Schreiber has been a director of the Company since November
1985. Mr. Schreiber is an independent lawyer and business consultant who also
is of counsel to the law firm of Walter, Conston, Alexander & Green, P.C. in
New York, New York. Mr. Schreiber has been affiliated with that law firm as
counsel or partner since August 1985. From 1988 to mid-1992, he also was the
Chairman of the Board and a principal shareholder of HSE, Inc., d/b/a
Manhattan Kids Limited, a privately owned corporation involved in catalogue
sales of American made children's clothing in Europe. From October 1985
through June 1992, Mr. Schreiber served as a director, and from July 1990
until June 1991 as Managing Director, of Owl Creek Investments Plc, a publicly
traded English oil and gas company. Mr. Schreiber received an A.B. Degree from
Columbia College in 1964 and a J.D. Degree from Columbia University School of
Law in 1967.
 
  Harry S. Welch has been a director of the Company since July 1995. Mr. Welch
was a director of Plains from May 1986 to July 1995. Since August 1989, he has
been an attorney in private practice in Houston, Texas. He served as Vice
President and General Counsel of Texas Eastern Corporation from 1988 to July
1989. Mr. Welch received a B.B.A. Degree and an L.L.B. Degree from the
University of Texas in 1947 and 1949, respectively.
 
  Joseph P. Barrett has been a Vice President since March 1995 and has been
with the Company since it began in 1982. Mr. Barrett has served as Vice
President--Land and a director of Plains, a wholly owned subsidiary, since
July 1995. He is a 1977 graduate of the University of Colorado where he earned
a Bachelor's Degree in Business and Mineral Land Management, and a 1982
graduate of Washburn University Law School where he earned his law degree.
 
  Robert W. Howard has been Senior Vice President of the Company since March
1992. Mr. Howard has served as Senior Vice President and a director of Plains,
a wholly owned subsidiary, since July 1995. Mr. Howard served as the Executive
Vice President--Finance from December 1989 until March 1992 and served as Vice
President--Finance of the Company from December 1983 until December 1989. Mr.
Howard has been the Treasurer of the Company since March 1986. During 1982,
Mr. Howard was a Manager/Accountant with Weiss & Co., a certified public
accounting firm. Mr. Howard received a B.B.A. Degree from the University of
Wisconsin, Eau Claire, in 1976.
 
  Eugene A. Lang, Jr. has been Senior Vice President--General Counsel of the
Company since September 1995. Mr. Lang served as a Senior Vice President,
General Counsel and Secretary of Plains from May 1994 to July 1995, and from
October 1990 to May 1994 he served as Vice President, General Counsel and
Secretary of Plains. From 1986 to 1990 he was an associate with the Houston,
Texas law firm of Vinson & Elkins. From 1984 to 1986, he was General Attorney
and Assistant Secretary of K N Energy, Inc. From 1978 to 1984, he was an
attorney for K N Energy, Inc.
 
 
                                      25
<PAGE>
 
  Donald H. Stevens has been the Vice President--Corporate Relations and
Capital Markets for the Company since August 1992. From July 1989 until August
1992, Mr. Stevens served as Manager of Corporate and Tax Planning for
Kennecott Corporation, a mining company. From May 1986 until September 1989,
Mr. Stevens served as Corporate Planning Analyst in Corporate Acquisition and
Divestitures for BP America, Inc., formerly The Standard Oil Company. Prior to
May 1986, Mr. Stevens served in various finance, tax and analyst positions
with Seco Energy Corporation and Gulf Oil Corporation, both of which are oil
and gas companies. Mr. Stevens received his B.S. Degree in Finance/Accounting
from the University of Wyoming in 1975.
 
ITEM 11. EXECUTIVE COMPENSATION
 
 Summary Compensation Table
 
  The following table sets forth, in summary form, the compensation received
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 compensation exceeded $100,000 during the year ended December
31, 1995. Beginning with the year ended December 31, 1995, the Company changed
its fiscal year end from September 30 to December 31. The figures in the
following table are for each of the one year periods ended December 31, 1995,
1994, and 1993:
 
  SUMMARY COMPENSATION TABLE
 
<TABLE>
<CAPTION>
                                                                 LONG-TERM COMPENSATION
                                                              -------------------------------
                                                                     AWARDS           PAYOUTS
                                                              ---------------------   -------
                                                                         SECURITIES
                                                              RESTRICTED UNDERLYING
                                                 OTHER ANNUAL   STOCK     OPTIONS/     LTIP    ALL OTHER
   NAME AND PRINCIPAL    FISCAL  SALARY   BONUS  COMPENSATION  AWARD(S)     SARS      PAYOUTS COMPENSATION
        POSITION          YEAR   ($)(1)  ($)(2)     ($)(3)      ($)(4)     (#)(5)     ($)(6)    ($) (7)
   ------------------    ------ -------- ------- ------------ ---------- ----------   ------- ------------
<S>                      <C>    <C>      <C>     <C>          <C>        <C>          <C>     <C>
William J. Barrett......  1995  $200,000       0       0           0            0         0      4,680
 Chief Executive
  Officer,                1994  $200,000 $40,000       0           0      100,000         0      4,560
 and Chairman of the
  Board                   1993  $175,000 $60,000       0           0            0         0      4,555
Paul M. Rady............  1995  $175,000       0       0           0            0         0      4,680
 President, Chief
  Operating               1994  $139,583 $30,000       0           0       70,000         0      4,247
 Officer, and a director  1993  $100,000 $30,000       0           0            0         0      3,060
A. Ralph Reed...........  1995  $200,000       0       0           0            0         0      4,680
 Executive Vice
  President--             1994  $164,583 $30,000       0           0      100,000         0      4,705
 Operations, and a
  director                1993  $135,000 $40,000       0           0            0         0      4,110
J. Frank Keller.........  1995  $150,000       0       0           0            0         0      4,560
 Chief Financial
  Officer,                1994  $128,750 $25,000       0           0       55,000         0      3,922
 Executive Vice
  President,              1993  $ 97,500 $31,075       0           0            0         0      2,985
 Secretary and a
  director
William F. Wallace......  1995  $211,373       0       0           0            0         0      3,412
 Former Vice Chairman of  1994  $ 76,993       0       0           0       99,030(9)      0      6,900
 the Board (8)            1993       --      --      --          --           --        --         --
</TABLE>
--------
(1) The dollar value of base salary (cash and non-cash) earned during the year
    indicated.
(2) The dollar value of bonus (cash and non-cash) earned during the year
    indicated.
(3) During the period covered by the Table, the Company did not pay any other
    annual compensation not properly categorized as salary or bonus, including
    perquisites and other personal benefits, securities or property.
(4) During the period covered by the Table, the Company did not make any award
    of restricted stock, including share units.
(5) The sum of the number of shares of Common Stock to be received upon the
    exercise of all stock options granted. The 1994 Stock Option Plan was
    approved by the Board Of Directors effective April 1, 1994 and was
    approved by stockholders at the March 16, 1995 Annual Meeting. At the
    March 5, 1996 meeting of the Board Of Directors, the Board approved,
    subject to stockholder approval, an amendment to the 1994 Plan to increase
    from 400,000 to 1,000,000 the number of shares subject to the 1994 Plan.
    See below "Option Grants Table".
 
                                      26
<PAGE>
 
(6) Except for stock option plans, the Company does not have in effect any
    plan that is intended to serve as incentive for performance to occur over
    a period longer than one fiscal year.
(7) All other compensation received that the Company could not properly report
    in any other column of the Table including annual Company contributions or
    other allocations to vested and unvested defined contribution plans, and
    the dollar value of any insurance premiums paid by, or on behalf of, the
    Company with respect to term life insurance for the benefit of the named
    executive officer, and the full dollar of the remainder of the premiums
    paid by, or on behalf of, the Company. Effective in November 1993, the
    Company obtained directors and officers insurance. Coverage of the named
    officers under this policy may be considered compensation for the named
    officers, although it has not been included in the table.
(8) Mr. Wallace's compensation was paid by Plains during the period from
    October 3, 1994 (when he first became an executive officer of Plains)
    through July 18, 1995 when Plains merged with and into the Company. Mr.
    Wallace resigned as an officer and director of the Company effective
    January 11, 1996 and as an employee of the Company effective as of March
    6, 1996.
(9) Consists of options to purchase 76,185 shares of Common Stock of Plains
    that became options to purchase 99,030 shares of Common Stock of the
    Company upon the merger of Plains with and into a subsidiary of the
    Company on July 18, 1995.
 
 Option Grants Table
 
  No grants of stock options were made during the fiscal year ended December
31, 1995 to the Company's Chief Executive Officer or the four other most
highly compensated executive officers of the Company whose compensation
exceeded $100,000 during the year ended December 31, 1995.
 
 Aggregated Option Exercises And Fiscal Year-End Option Value Table
 
  The following table sets forth information concerning each exercise of stock
options during the year ended December 31, 1995 by the Company's Chief
Executive Officer and the four other most highly compensated executive
officers of the Company whose compensation exceeded $100,000 during the year
ended December 31, 1995, and the year-end value of unexercised options held by
these persons:
 
                          AGGREGATED OPTION EXERCISES
                       FOR YEAR ENDED DECEMBER 31, 1995
                        AND YEAR-END OPTION/SAR VALUES
 
<TABLE>
<CAPTION>
                                                    NUMBER OF SECURITIES      VALUE OF UNEXERCISED
                                                   UNDERLYING  UNEXERCISED        IN-THE-MONEY
                                                       OPTIONS/SARS AT           OPTIONS/SARS AT
                              SHARES      VALUE        YEAR-END (#)(3)           YEAR-END ($)(4)
                           ACQUIRED ON   REALIZED ------------------------- -------------------------
          NAME            EXERCISE(#)(1) ($) (2)  EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
          ----            -------------- -------- ----------- ------------- ----------- -------------
<S>                       <C>            <C>      <C>         <C>           <C>         <C>
William J. Barrett......      25,000     $206,875        0       75,000      $      0    $  997,615
 Chief Executive
 Officer, and Chairman
 of the Board
Paul M. Rady............      30,000     $562,500   17,499       52,501      $253,859    $  731,641
 President, Chief
 Operating Officer, and
 a director
A. Ralph Reed...........           0            0   25,000       75,000      $339,650    $1,018,950
 Executive Vice
 President--Operations,
 and a director
J. Frank Keller.........      10,000     $202,500   13,749       41,251      $198,097    $  594,354
 Chief Financial
 Officer, Executive Vice
 President, Secretary
 and a director
William F. Wallace......           0            0   29,710       69,320      $272,818    $  636,545
 Former Vice Chairman of
 the Board
</TABLE>
 
                                      27
<PAGE>
 
--------
(1) The number of shares received upon exercise of options during the year
    ended December 31, 1995.
(2) With respect to options exercised during the Company's year ended December
    31, 1995, 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.
(3) The total number of unexercised options held as of December 31, 1995,
    separated between those options that were exercisable and those options
    that were not exercisable.
(4) For all unexercised options held as of December 31, 1995, 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, 1995. As
    required, the price used to calculate these figures was the closing sale
    price of the Common Stock at year-end. On December 29, 1995, the last day
    of trading for the year, the closing sale price of the Common Stock was
    $29.375 per share. On March 12, 1996, the closing sale price was $22.625
    per share.
 
 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. Employees of the Company are entitled to contribute to the 401(k)
Plan up to 15 percent of their respective salaries. For each pay period
through March 31, 1996, the Company will contribute, on behalf of each
employee, 50 percent of the contribution made by that employee, up to a
maximum contribution by the Company of three percent of that employee's gross
salary for that pay period. Effective April 1, 1996, the Company's matching
contribution will be increased to 100 percent of each participating employee's
contribution, up to a maximum of six percent of base salary, with one-half of
the match paid in cash and one-half of the match paid in the Company's Common
Stock. 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 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.
 
  Excluding the 401(k) Plan, the Company has no defined benefit or actuarial
or pension plans or other retirement plans.
 
 Compensation of Directors
 
  Standard Arrangements. Pursuant to the Company's standard arrangement for
compensating directors of the Company, no compensation for serving as a
director is paid to directors who are not also 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, for each meeting attended, each Outside Director
receives a $750 meeting attendance fee, and will have options to purchase 500
shares of the Common Stock become exercisable. Although these options become
exercisable only at the rate of 500 for each Board Of Directors meeting
attended, each director will be granted options to purchase 10,000 shares at
the time the person 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 subject to the restrictions on
exercise. The options are granted to the Outside Directors pursuant to the
Company's Non-Discretionary Stock Option Plan, and their exercise price is
equal to the closing sales price for the Company's Common Stock on the date of
grant. These options expire upon the later to occur of (i) five years after
the date of grant, and (ii) two years after the date those options first
become exercisable.
 
 
                                      28
<PAGE>
 
  Effective in November 1993, the Company obtained directors and officers
insurance coverage. Coverage of the directors of the Company under this policy
may be considered compensation for the directors.
 
  Other Arrangements. During the year ended December 31, 1995, no compensation
was paid to directors of the Company other than pursuant to the standard
compensation arrangements described in the previous section.
 
 Employment Contracts And Termination Of Employment And Change-In-Control
Arrangements
 
  The Company does not have any written employment contracts with respect to
any of its executive officers named in the Summary Compensation Table except
for William F. Wallace. The Company entered into a six month employment
agreement with Mr. Wallace effective at the consummation of the Barrett-Plains
merger. In addition, Mr. Wallace is a party to an agreement with Plains to
which the Company became bound as a result of the Barrett-Plains merger. That
agreement provides, among other things, that if, within three years after a
"Change In Control" (as defined in the agreement), Mr. Wallace's employment
with Plains is involuntarily terminated or is terminated by Mr. Wallace for
"Good Reason", Mr. Wallace is to be paid a cash amount equal to (a) 299
percent of the higher of (i) his then annual compensation (including salary,
bonuses and incentive compensation) or (ii) the highest annual compensation
(including salary, bonuses and incentive compensation) paid or payable during
any of the three calendar years ending with the year of his termination, plus,
(b) an amount equal to any excise taxes payable by Mr. Wallace with respect to
these amounts and any excise or income taxes payable by Mr. Wallace as a
result of the reimbursement of the excise taxes. "Good Reason" is defined as a
reduction in Mr. Wallace's compensation or employment responsibilities, a
required relocation outside the greater Denver, Colorado area or, generally,
any conduct by Plains that renders Mr. Wallace unable to discharge his
employment duties effectively. Following the cessation of Mr. Wallace's
employment with the Company on March 6, 1996, the Company paid to Mr. Wallace
$1,024,440 in satisfaction of the Company's obligations pursuant to Mr.
Wallace's employment agreement with Plains. The Company has no other
compensatory plan or arrangement that results or will result from the
resignation, retirement, or any other termination of the employment with the
Company and its subsidiaries of the executive officers named in the Summary
Compensation Table or from a change-in-control, except that (i) in January
1994, the Board Of Directors approved a resolution allowing all options
outstanding under the Company's 1990 Stock Option Plan to become exercisable
if an announcement is made concerning a business combination with the Company;
and (ii) in September 1994, the Compensation Committee committed to Mr. Reed
that all stock options that has been granted to him as of September 10, 1994
would become exercisable upon termination of his employment provided that he
remains in the employment of the Company continuously until September 10,
1997, and further provided that the Compensation Committee, or its successor,
determines as of the date of his termination that his employment performance
has satisfied the Company's employment standards for executive officers.
 
 Compensation Committee Interlocks And Insider Participation
 
  During the year ended December 31, 1995, each of C. Robert Buford, James M.
Fitzgibbons, Derrill Cody, Hennie L.J.M. Gieskes, James T. Rodgers, Philippe
S.E. Schreiber and Harry S. Welch served as members of the Compensation
Committee of the Board Of Directors. Mr. Schreiber served as the President of
Excel Energy Corp. 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 of Excel with and into the Company. No other person who served as a
member of the Compensation Committee during the year ended December 31, 1995
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. For a description of transactions involving Mr. Buford and the
Company, please see Item 13. "Certain Relationships and Related Transactions".
 
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
 
  The following table summarizes certain information as of March 12, 1996 with
respect to the ownership by each director, by each executive officer named in
the "Executive Compensation" section above, by all executive officers and
directors as a group, and by each other person known by the Company to be the
beneficial owner of more than five percent of the Common Stock:
 
                                      29
<PAGE>
 
<TABLE>
<CAPTION>
                                        AMOUNT/NATURE OF     PERCENT OF CLASS
      NAME OF BENEFICIAL OWNER        BENEFICIAL OWNERSHIP  BENEFICIALLY OWNED
      ------------------------        --------------------  ------------------
<S>                                   <C>                   <C>
William J. Barrett...................     386,660 Shares(1)        1.5%
C. Robert Buford.....................     623,111 Shares(2)        2.5%
Derrill Cody.........................       9,560 Shares(3)         (4)
James M. Fitzgibbons.................       8,500 Shares(3)         (4)
Hennie L.J.M. Gieskes................     896,214 Shares(3)        3.6%
William W. Grant, III................      22,650 Shares(3)         (4)
J. Frank Keller......................      81,570 Shares(3)         (4)
Paul M. Rady.........................      56,500 Shares(3)         (4)
A. Ralph Reed........................      63,822 Shares(5)         (4)
James T. Rodgers.....................       8,500 Shares(3)         (4)
Philippe S.E. Schreiber..............      16,507 Shares(3)         (4)
William F. Wallace...................      99,293 Shares(3)         (4)
Harry S. Welch.......................      16,800 Shares(3)         (4)
All Directors And Executive Officers    2,339,517 Shares(6)        9.3%
 As A Group (17 persons).............
State Farm Mutual Insurance Company     2,065,233 Shares           8.2%
 and related entities................
 One State Farm Plaza
 Bloomington, IL 61710
Wellington Management Company........   1,529,700 Shares(7)        6.1%
 75 State Street
 Boston, MA 02109
</TABLE>
--------
(1) The number of shares indicated includes 6,790 shares owned by Louise K.
    Barrett, Mr. Barrett's wife, 230,000 shares owned by the Barrett Family
    L.L.L.P., a Colorado limited partnership for which Mr. Barrett and his
    wife are general partners and owners of an aggregate of 77.21462 percent
    of the partnership interests, and 49,998 shares underlying options that
    currently are exercisable or become exercisable within the next 60 days.
    Pursuant to Rule 161-1(a)(4) under the Securities Exchange Act of 1934
    (the "1934 Act"), Mr. Barrett disclaims ownership of all but 177,594
    shares held by the Barrett Family L.L.L.P., which constitutes Mr. and Mrs.
    Barrett's proportionate shares of the shares held by the Barrett Family
    L.L.L.P.
(2) C. Robert Buford is considered the beneficial owner of the 604,830 shares
    of which Zenith Drilling Corporation ("Zenith") is the record owner. Mr.
    Buford owns approximately 89 percent of the outstanding common stock of
    Zenith. The number of shares 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 1934 Act. The number of shares indicated also includes
    8,000 shares underlying options currently exercisable at $10.375 per
    share.
(3) The number of shares indicated consists of or includes the following
    number of shares underlying options that currently are exercisable or that
    become exercisable within the next 60 days that are held by each of the
    following persons: Derrill Cody, 9,300; James M. Fitzgibbons, 6,500;
    Hennie L.J.M. Gieskes, 7,000; William W. Grant, III, 12,900; J. Frank
    Keller, 22,350; Paul M. Rady, 26,500; James T. Rodgers, 8,500; Philippe
    S.E. Schreiber, 6,500; William F. Wallace, 99,030; and Harry S. Welch,
    14,200. Mr. Wallace resigned as an executive officers of the Company
    effective January 11, 1996 and as an employee of the Company effective
    March 6, 1996.
(4) Less than one percent of the Common Stock outstanding.
(5) The number of shares indicated includes 12,500 shares owned by Mary C.
    Reed, Mr. Reed's wife and 35,800 shares underlying options currently are
    exercisable or that become exercisable within the next 60 days.
(6) The number of shares indicated includes the shares owned by Zenith that
    are beneficially owned by Mr. Buford as described in note (2), and the
    aggregate of 306,578 shares underlying the options described in notes (1),
    (2), (3) and (5), an aggregate of 27,127 shares owned by four executive
    officers not named in the above table, an aggregate of 745 shares the
    beneficial ownership of which is disclaimed by the four executive officers
    not named in the above table, and an aggregate of 74,109 shares underlying
    options that currently are exercisable or that are exercisable within 60
    days that are held by those four executive officers.
(7) Wellington Management company, in its capacity as investment adviser, may
    be deemed the beneficial owner of these shares which are owned by numerous
    investment counseling clients.
 
                                      30
<PAGE>
 
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
 
  During the year ended December 31, 1995, Zenith, which owns a working
interest in many of the leases for which the Company is the operator, paid to
the Company, as operator, approximately $1,062,000 as Zenith's portion of the
lease operating expenses and development costs for those leases. Also, as a
result of its working interest in those leases, Zenith received approximately
$942,000 as its share of revenues. Zenith owns working interests ranging from
three to 50 percent in leases of which the Company is the operator. All terms
and arrangements between Zenith and the Company with respect to these working
interests are the same as those between the Company and the other working
interest owners in the leases. Zenith is 89 percent owned by Mr. Buford.
 
 
  Mr. Buford also is the President of Grand Valley Corporation ("GVC"), which
owns approximately a 10 percent interest in the pipeline gathering system and
related facilities on the Company's Grand Valley Field. Ten percent of GVC is
owned by Mr. Buford, and 90 percent of GVC is owned by Mr. Buford's three
adult children. During the year ended December 31, 1995, GVC's proportionate
share of the pipeline gathering system's expenses, not including depreciation,
was approximately $148,000, and its share of the pipeline gathering system's
revenues was approximately $909,000. All terms and arrangements between GVC
and the Company with respect to this gathering system are the same as those
between the Company and the other owners of the gathering system.
 
                                    PART IV
 
ITEM 14. EXHIBITS, FINANCIAL SCHEDULES, AND REPORTS ON FORM 8-K
 
  (a)(1) and (a)(2) Financial Statements And Financial Statement Schedules
 
                                      31
<PAGE>
 
        INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
 
<TABLE>
<S>                                                                       <C>
Report Of Independent Public Accountants................................. F-1
Consolidated Balance Sheets at December 31, 1995 and 1994................ F-2
Consolidated Statements of Income for each of the three years in the
 period ended December 31, 1995.......................................... F-3
Consolidated Statements of Stockholders' Equity for each of the three
 years in the period ended December 31, 1995............................. F-4
Consolidated Statements of Cash Flows for each of the three years in the
 period ended December 31, 1995.......................................... F-5
Notes to the Consolidated Financial Statements........................... F-6
Supplemental Oil And Gas Information..................................... F-20
</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 33.
 
  (b) Reports On Form 8-K. No reports on Form 8-K were filed during the fourth
quarter of the year ended December 31, 1995.
 
                                       32
<PAGE>
 
                                 EXHIBIT INDEX
 
<TABLE>
 <C>     <S>
 EXHIBIT
  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.
  3.6    Bylaws of Barrett, as amended, are incorporated herein by reference
         from Exhibit 3.3 of Registrant's Registration Statement on Form S-4
         dated June 9, 1995.
 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 Plan is incorporated by
         reference from Registrant's Annual Report on Form 10-K for the year
         ended September 30, 1991.
 10.4    1994 Stock Option Plan, as amended, is incorporated by reference from
         the Registrant's Registration Statement on Form S-8 dated March 15,
         1995.
 10.5A   Gas Purchase Contract, No. P-1090, dated April 20, 1984, as amended,
         between Plains and KN Energy, Inc. is incorporated by reference from
         Plains Petroleum Company's Registration Statement on Form 10 dated
         August 21, 1985.
 10.5B   Letter Agreement dated January 11, 1996, amending the Gas Purchase
         Contract, No. P-1090, dated April 20, 1984, between Plains and KN
         Energy, Inc.
 10.6    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 banks.
 22      List of Subsidiaries.
 24      Consent of Arthur Andersen LLP.
</TABLE>
 
                                       33
<PAGE>
 
                         REPORT OF ARTHUR ANDERSEN LLP
 
                        INDEPENDENT PUBLIC ACCOUNTANTS
 
The Board of Directors
Barrett Resources Corporation
Denver, Colorado 80202
 
  We have audited the accompanying consolidated balance sheets of Barrett
Resources Corporation (a Delaware corporation) and subsidiaries as of December
31, 1995 and 1994, and the related consolidated statements of income,
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 1995. 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 generally accepted auditing
standards. 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 financial position of Barrett Resources
Corporation and subsidiaries as of December 31, 1995 and 1994, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 1995, in conformity with generally accepted
accounting principles.
 
  As explained in Note 8 to the financial statements, effective January 1,
1993, the Company changed its method of accounting for postretirement
benefits.
 
                                          Arthur Andersen LLP
 
Denver, Colorado
March 1, 1996
 
                                      F-1
<PAGE>
 
                         BARRETT RESOURCES CORPORATION
 
                          CONSOLIDATED BALANCE SHEETS
 
                           DECEMBER 31, 1995 AND 1994
                                 (IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                                              1995      1994
                                                            --------  --------
<S>                                                         <C>       <C>
                          ASSETS
Current assets:
  Cash and cash equivalents................................ $  7,529  $ 12,348
  Receivables, net.........................................   31,089    34,522
  Inventory................................................      554       643
  Other current assets.....................................      574     1,099
                                                            --------  --------
    Total current assets...................................   39,746    48,612
Net property and equipment (full cost method)..............  300,666   261,424
Other assets...............................................      --        916
                                                            --------  --------
                                                            $340,412  $310,952
                                                            ========  ========
           LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
  Accounts payable......................................... $ 14,369  $ 24,587
  Amounts payable to oil and gas property owners...........   13,366    16,091
  Accrued and other liabilities............................    8,325     5,468
                                                            --------  --------
    Total current liabilities..............................   36,060    46,146
Long term debt.............................................   89,000    53,000
Deferred income taxes......................................   23,524    21,726
Postretirement benefits....................................      --        927
Other long term liabilities................................      --      1,017
Commitments and contingencies--Note 10
Stockholders' equity:
  Preferred stock, $.001 par value: 1,000,000 shares
   authorized,
   none outstanding........................................      --        --
  Common stock, $.01 par value: 35,000,000 shares
   authorized,
   25,092,246 outstanding (24,694,669 at December 31,
   1994)...................................................      251       247
  Additional paid-in capital...............................   86,154    78,628
  Retained earnings........................................  105,890   109,304
  Treasury stock, at cost..................................     (467)      (43)
                                                            --------  --------
    Total stockholders' equity.............................  191,828   188,136
                                                            --------  --------
                                                            $340,412  $310,952
                                                            ========  ========
</TABLE>
 
                            See accompanying notes.
 
                                      F-2
<PAGE>
 
                         BARRETT RESOURCES CORPORATION
 
                       CONSOLIDATED STATEMENTS OF INCOME
 
                  YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
                     (IN THOUSANDS, EXCEPT PER SHARE DATA)
 
<TABLE>
<CAPTION>
                                                     1995      1994     1993
                                                   --------  -------- --------
<S>                                                <C>       <C>      <C>
Revenues:
  Oil and gas production.......................... $ 96,996  $ 78,794 $ 80,911
  Trading revenues................................   28,554    28,114   22,955
  Revenue from gas gathering......................    1,074       353      216
  Interest income.................................      714       864      736
  Other income....................................      678     1,333    1,254
                                                   --------  -------- --------
                                                    128,016   109,458  106,072
Operating expenses:
  Lease operating expenses........................   34,525    28,223   30,383
  Depreciation, depletion and amortization........   33,480    22,760   20,185
  Cost of trading.................................   27,611    27,190   21,675
  General and administrative......................   13,426    13,261   11,194
  Interest expense................................    4,631       942      725
  Other expenses, net.............................      588       645      867
  Merger and reorganization expense...............   14,161       --       --
                                                   --------  -------- --------
                                                    128,422    93,021   85,029
                                                   --------  -------- --------
Income (loss) before income taxes and cumulative
 effect of change in method of accounting for
 postretirement benefits..........................     (406)   16,437   21,043
Provision for income taxes........................    1,834     5,138    6,721
                                                   --------  -------- --------
Income (loss) before cumulative effect of change
 in method of accounting for postretirement
 benefits.........................................   (2,240)   11,299   14,322
Cumulative effect of change in accounting for
 postretirement benefits, net of tax..............      --        --       656
                                                   --------  -------- --------
Net income (loss)................................. $ (2,240) $ 11,299 $ 13,666
                                                   ========  ======== ========
Net income (loss) per common share and common
 share equivalent before change in method of
 accounting for post-retirement benefits..........     (.09) $    .46 $    .58
                                                   ========  ======== ========
Net income (loss) per common share and common
 share equivalent-- cumulative effect............. $    --   $    --  $   (.03)
                                                   ========  ======== ========
Net income (loss) per common share and common
 share equivalent................................. $   (.09) $    .46 $    .55
                                                   ========  ======== ========
</TABLE>
 
                            See accompanying notes.
 
                                      F-3
<PAGE>
 
                         BARRETT RESOURCES CORPORATION
 
                CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
 
                 YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
                                (IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                     ADDITIONAL                        TOTAL
                              COMMON  PAID-IN   TREASURY RETAINED  STOCKHOLDERS'
                              STOCK   CAPITAL    STOCK   EARNINGS     EQUITY
                              ------ ---------- -------- --------  -------------
<S>                           <C>    <C>        <C>      <C>       <C>
Balances, October 1, 1992
  As previously reported....   $ 97   $39,651    $ --    $  3,567    $ 43,315
  Effect of change to
   December 31 year end         --        --       --       1,333       1,333
    Net income for the three
     month period ending
     December 31, 1992......
  Pooling of interests with
   Plains Petroleum
   Company..................    128    19,163      --      84,144     103,435
                               ----   -------    -----   --------    --------
Balance, December 31, 1992
 as restated................    225    58,814      --      89,044     148,083
  Exercise of stock
   options..................      1       515     (204)       --          312
  Issuance of common stock..     20    18,881      --         --       18,901
  Cash dividends--Plains
   common stock.............    --        --       --      (2,352)     (2,352)
  Net income for the year
   ended December 31, 1993..    --        --       --      13,666      13,666
                               ----   -------    -----   --------    --------
Balance, December 31, 1993..    246    78,210     (204)   100,358     178,610
  Exercise of stock
   options..................      1       970     (313)       --          658
  Purchase of treasury
   stock....................    --        --       (78)       --          (78)
  Retirement of treasury
   stock....................    --       (552)     552        --          --
  Cash dividends--Plains
   common stock.............    --        --       --      (2,353)     (2,353)
  Net income for the year
   ended December 31, 1994..    --        --       --      11,299      11,299
                               ----   -------    -----   --------    --------
Balance, December 31, 1994..    247    78,628      (43)   109,304     188,136
  Exercise of stock
   options..................      4     7,690     (588)       --        7,106
  Retirement of treasury
   stock....................    --       (164)     164        --          --
  Cash dividends--Plains
   common stock.............    --        --       --      (1,174)     (1,174)
  Net loss for the year
   ended December 31, 1995..    --        --       --      (2,240)     (2,240)
                               ----   -------    -----   --------    --------
Balance, December 31, 1995..   $251   $86,154    $(467)  $105,890    $191,828
                               ====   =======    =====   ========    ========
</TABLE>
 
                            See accompanying notes.
 
                                      F-4
<PAGE>
 
                         BARRETT RESOURCES CORPORATION
 
                     CONSOLIDATED STATEMENTS OF CASH FLOWS
 
                  YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
                                 (IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                                    1995      1994      1993
                                                  --------  --------  --------
<S>                                               <C>       <C>       <C>
Cash flows from operations:
  Net income (loss).............................. $ (2,240) $ 11,299  $ 13,666
  Adjustments needed to reconcile to net cash
   flow provided by operations:
    Depreciation, depletion and amortization.....   33,480    22,760    20,185
    Unrealized (gain) loss on trading............    1,139        58      (124)
    Deferred income taxes........................    1,798     4,788     5,975
    Other........................................     (787)       70       782
                                                  --------  --------  --------
                                                    33,390    38,975    40,484
  Change in current assets and liabilities:
    Accounts receivables.........................    3,433    (8,436)   (4,304)
    Other current assets.........................      525      (148)     (209)
    Accounts payable.............................     (524)    6,803    (1,870)
    Amounts due oil and gas owners...............   (2,725)      623     5,640
    Accrued and other liabilities................    1,439    (1,244)    1,839
                                                  --------  --------  --------
Net cash flow provided by operations.............   35,538    36,573    41,580
                                                  --------  --------  --------
Cash flows from investing activities:
  Proceeds from sale of oil and gas properties...      504       458    16,210
  Purchase of short-term investments.............      --    (11,322)   (5,952)
  Maturity of short-term investments.............      --     15,290     1,984
  Acquisition of property and equipment..........  (82,758)  (95,589)  (45,488)
  Other..........................................      --        146        65
                                                  --------  --------  --------
Net cash flow used in investing activities.......  (82,254)  (91,017)  (33,181)
                                                  --------  --------  --------
Cash flows from financing activities:
  Proceeds from issuance of common stock.........    7,071       301    19,212
  Purchase of treasury stock.....................      --        (78)      --
  Borrowing under line of credit.................  115,000    44,000     1,300
  Payments on line of credit.....................  (79,000)   (4,500)   (7,800)
  Dividends paid.................................   (1,174)   (2,353)   (2,352)
  Other..........................................      --       (147)      868
                                                  --------  --------  --------
Net cash flow provided by financing activities...   41,897    37,223    11,228
                                                  --------  --------  --------
Increase (decrease) in cash and cash
 equivalents.....................................   (4,819)  (17,221)   19,627
Cash and cash equivalents at beginning of year...   12,348    29,569     9,942
                                                  --------  --------  --------
Cash and cash equivalents at end of year......... $  7,529  $ 12,348  $ 29,569
                                                  ========  ========  ========
</TABLE>
 
                            See accompanying notes.
 
                                      F-5
<PAGE>
 
                         BARRETT RESOURCES CORPORATION
 
                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
                       DECEMBER 31, 1995, 1994 AND 1993
 
1. 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
in the mid-continent states and Rocky Mountain region of the United States.
Barrett also operates gas gathering systems and related facilities in the
areas which are synergistic to the Company's production. Barrett has a gas
marketing and trading subsidiary, which allows the Company to market the
Company's natural gas production and to purchase and sell other companies'
natural gas.
 
 Principles of consolidation
 
  The consolidated financial statements include the accounts of the Company
and its subsidiaries, all of which are wholly-owned. All significant
intercompany transactions have been eliminated in consolidation. Certain
reclassifications have been made to 1993 and 1994 amounts to conform to the
1995 presentation.
 
 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.
 
 Cash and cash equivalents
 
  Cash in excess of daily requirements is invested in money market accounts
and commercial paper with maturities of three months or less. 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.
 
 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 extraordinary transactions.
 
  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 presently has only one cost center since all of its properties are
located in the United States. Amortizable costs include developmental drilling
in progress as well
 
                                      F-6
<PAGE>
 
                         BARRETT RESOURCES CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
                       DECEMBER 31, 1995, 1994 AND 1993
as estimates of future development costs of proved reserves but exclude the
costs of unevaluated oil and gas properties. Accumulated depreciation and
amortization is written off as assets are retired. Depletion and amortization
equaled approximately $.55, $.52 and $.48 per Mcfe ($3.28, $3.14 and $2.87 per
BOE) during the years ended December 31, 1995, 1994 and 1993, respectively.
 
  The Company capitalizes interest costs on amounts expended on assets during
the period in which activities are occurring to place the asset in service.
Amounts spent to develop properties included in the full cost center of oil
and gas properties are excluded from the interest capitalization computation.
 
  The Company acquires nonproducing 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.
 
 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 ten years, of the assets.
 
 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, production revenue that the Company, as operator, is
collecting and distributing to revenue interest owners and production revenue
taxes that the Company, as operator, has withheld for timely payment to the
tax agencies.
 
 Trading and hedging activities
 
  The Company's business activities include buying and selling of natural gas.
The Company recognizes revenue and costs on gas trading transactions at the
point in time when gas is delivered to the purchaser.
 
  The Company uses both commodity futures contracts and price swaps to hedge
the impact of price fluctuations on a portion of its production and trading
activities. The Company enters into a hedging position for specific
transactions that management deems expose the Company to an unacceptable
market price risk. Price swaps or commodities transactions without
corresponding scheduled physical transactions (scheduled physical transactions
include committed trading activities or production from producing wells) do
not qualify for hedge accounting. The Company classifies these positions as
trading positions and records these instruments at fair value. Gains and
losses are recognized as fair values fluctuate from time to time compared to
cost.
 
  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
 
                                      F-7
<PAGE>
 
                         BARRETT RESOURCES CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
                       DECEMBER 31, 1995, 1994 AND 1993
the physical transaction underlying the hedge position. Hedging gains or
losses significantly exceeding the price movement of the underlying physical
transaction are recorded in the consolidated statements of income in the
period in which the lack of correlation occurred. Gains or losses on hedging
activities are recorded in the consolidated statements of income as
adjustments of the revenue or cost of the underlying physical transaction.
Hedging transactions are reported as operating activities in the consolidated
statements of cash flows.
 
 Earnings per share
 
  Per share amounts were computed using the weighted average number of shares
of common stock and common stock equivalents outstanding during each year:
1995--24,931,000; 1994--24,967,000 and 1993--24,778,000. Options to purchase
stock are included as common stock equivalents, when dilutive, using the
treasury stock method.
 
 Change in fiscal year
 
  On July 18, 1995, the Company changed its fiscal year-end from September 30
to December 31. A transition report for the period October 1, 1994 through
December 31, 1994 was filed with the Securities and Exchange Commission.
During the three months ended December 31, 1994, the Company reported revenues
of $15 million and net income of $207,000.
 
2. MERGER
 
  On July 18, 1995 Plains Petroleum Company ("Plains") was merged with and
into a subsidiary of the Company, resulting in Plains becoming a wholly-owned
subsidiary of the Company. Approximately 12.8 million shares of the Company's
common stock were issued in exchange for all of the outstanding common stock
of Plains. Additionally, outstanding options to acquire Plains common stock
were converted to options to acquire approximately 593,000 shares of the
Company's common stock. In connection with the merger, the Company's
authorized number of shares of common stock was increased to 35 million. The
merger was accounted for as a pooling of interests, and accordingly, the
accompanying financial statements have been restated to include the accounts
and operations of Plains for all periods prior to the merger.
 
  Plains used the successful efforts method of accounting for its oil and gas
exploration and development activities. In conjunction with the merger, Plains
adopted the full cost method used by the Company resulting in increases of net
property and equipment due to the capitalization of exploration costs,
reversal of impairment and adjustments of depreciation, depletion and
amortization expense for periods prior to the merger. The financial statements
for 1994 and 1993 have been retroactively restated for the change in
accounting method which resulted in increased net income. Retained earnings
and deferred income taxes have been adjusted for the effect of the retroactive
application of the new method.
 
                                      F-8
<PAGE>
 
                         BARRETT RESOURCES CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
                       DECEMBER 31, 1995, 1994 AND 1993
 
  Certain reclassifications have been made to the historical consolidated
financial statements of the separate companies to conform the financial
statements to a comparable presentation. There were no intercompany
transactions between the Company and Plains. Separate results for the periods
preceding the merger, including the conversion to full cost for Plains and the
change to a December 31 year-end for the Company, were as follows (in 000's):
 
<TABLE>
<CAPTION>
                                    BARRETT PLAINS(1) ADJUSTMENTS(2) COMBINED
                                    ------- --------- -------------- --------
                                       (UNAUDITED)
   <S>                              <C>     <C>       <C>            <C>
   Six month period ended June 30,
    1995
     Net revenues.................. $29,277  $35,823         --      $ 65,100
     Net income....................   2,200    3,771         --         5,971
   12 month period ended            9/30/94 12/31/94                 12/31/94
     Net revenues.................. $41,252  $63,024     $ 5,182     $109,458
     Net income....................   4,439    7,768        (908)      11,299
   12 month period ended            9/30/93 12/31/93                 12/31/93
     Net revenues.................. $42,686  $64,998     $(1,612)    $106,072
     Net income....................   5,756    8,128        (218)      13,666
</TABLE>
--------
(1) Restated to full cost to conform accounting policies
(2) To conform year ends
 
  In connection with the merger, approximately $14.2 million of merger and
reorganization costs and expenses were incurred and have been charged to
expense in the Company's third and fourth quarters of fiscal 1995. These
nonrecurring costs and expenses consist of (1) investment banker and
professional fees of $7.4 million; (2) severance and employee benefit costs of
$5.6 million for approximately 38 employees, terminated through consolidation
of administrative and operational functions; (3) a non-cash credit of
approximately $.9 million associated with the termination of Plains'
postretirement benefit plans and other related benefit plans and (4) other
merger and reorganization related costs of $2.1 million.
 
3. RECEIVABLES
 
<TABLE>
<CAPTION>
                                                                 1995    1994
                                                                ------- -------
                                                                (IN THOUSANDS)
   <S>                                                          <C>     <C>
   Oil and gas revenue receivable.............................. $15,535 $13,257
   Joint interest billings.....................................   7,652  14,542
   Trading receivables.........................................   5,665   6,483
   Other accounts receivable...................................   2,237     240
                                                                ------- -------
                                                                $31,089 $34,522
                                                                ======= =======
</TABLE>
 
  The Company's accounts receivable are primarily due from medium size oil and
gas entities in the Rocky Mountain region. Collection of joint interest
billings is generally secured by future production. The Company performs
periodic credit evaluations of customers purchasing production for which no
collateral is required. Historically, the Company has not experienced
significant losses related to these extensions of credit.
 
  As of December 31, 1995 and 1994, receivables are recorded net of allowance
for doubtful accounts of $201,000 and $224,000, respectively.
 
                                      F-9
<PAGE>
 
                         BARRETT RESOURCES CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
                       DECEMBER 31, 1995, 1994 AND 1993
 
4. PROPERTY AND EQUIPMENT
 
<TABLE>
<CAPTION>
                                                               1995     1994
                                                             -------- --------
                                                              (IN THOUSANDS)
   <S>                                                       <C>      <C>
   Oil and gas properties, full cost method:
     Unevaluated costs, not being amortized................. $ 10,579 $ 12,611
     Evaluated costs........................................  420,784  346,950
     Gas gathering systems..................................    8,815    8,388
   Furniture, vehicles and equipment........................    9,801    9,765
                                                             -------- --------
                                                              449,979  377,714
   Less accumulated depreciation, depletion, amortization
    and impairment..........................................  149,313  116,290
                                                             -------- --------
                                                             $300,666 $261,424
                                                             ======== ========
</TABLE>
 
  The Company capitalized interest costs of $403,000 in 1995 with respect to
qualifying properties. Total interest costs incurred after recognition of the
capitalized interest amount was $4.6 million in 1995.
 
5. UNEVALUATED OIL AND GAS PROPERTY COSTS
 
  Unevaluated oil and gas property costs consist of the following:
 
<TABLE>
<CAPTION>
                                                     COSTS INCURRED DURING
                                                --------------------------------
                                                 1995   1994  1993  1992  TOTAL
                                                ------ ------ ----- ---- -------
                                                         (IN THOUSANDS)
   <S>                                          <C>    <C>    <C>   <C>  <C>
   Acquisition costs........................... $5,623 $2,130 $ --  $71  $ 7,824
   Exploration costs...........................  2,659     53    32  11    2,755
                                                ------ ------ ----- ---  -------
                                                $8,282 $2,183 $  32 $82  $10,579
                                                ====== ====== ===== ===  =======
</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 three years.
 
6. LONG-TERM DEBT
 
  The Company has a reserve-based line of credit with a group of banks which
provides up to $200 million for a four year period ending July 19, 1999. The
amount actually available to the Company under the line at any given time is
limited to the collateral value of proved reserves as determined by the
lenders. Based on the lenders' determination of collateral value, as of
December 31, 1995 (which was based on the March 31, 1995 and December 31, 1994
reserve reports), the Company has a borrowing limit of $160 million. In order
to reduce the commitment fees, the Company voluntarily requested that the
lenders limit the maximum borrowing to $90 million through December 31, 1995.
Subsequent to December 31, 1995, the Company increased the maximum borrowing
limit to $110 million. The lenders are currently reviewing the December 31,
1995 reserve report to determine current collateral value. The Company is
required to pay interest only during the revolving period. At its option, the
Company has elected to use the London interbank eurodollar rate (LIBOR) plus a
spread ranging from .5 percent to 1.0 percent (depending on the Company's
borrowing relative to its borrowing base) for a substantial portion of the
outstanding balance. As of December 31, 1995 the Company's outstanding balance
under the line of credit was $89 million of which $83 million was accruing
interest at an average LIBOR based rate of 6.62 percent and $6 million was
accruing interest on a prime based rate of 8.50 percent. The line of credit
agreement restricts the payment of dividends, borrowings, sale of assets,
loans to others, investment and merger
 
                                     F-10
<PAGE>
 
                         BARRETT RESOURCES CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
                       DECEMBER 31, 1995, 1994 AND 1993
activity over certain limits without the prior consent of the bank and
requires the Company to maintain certain net worth and debt to equity levels.
Based on the variable borrowing rates and re-pricing terms currently available
to the Company for the line of credit, management believes the fair value of
long-term debt approximates the carrying value.
 
7. OPTIONS
 
  The Company has two employee stock option plans, a 1990 Plan and a 1994
Plan, under which the Company's common stock may be granted to officers and
employees of the Company and subsidiaries. The 1990 Plan, as amended, provided
for the granting of 775,000 shares. The 1994 Plan provides for the granting of
400,000 shares of the Company's common stock. In addition, the Company has a
non-discretionary stock option plan under which options for an aggregate of
100,000 shares of the Company's common stock may be granted to non-employee
directors. In connection with the merger discussed in Note 2, the Company
assumed preexisting Plains stock option plans 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.
 
  Summary of options granted, exercised and outstanding during 1994 and 1995
is as follows:
 
<TABLE>
<CAPTION>
                                              NUMBER                   OPTION
                                             OF SHARES  OPTION PRICE   VALUE
                                             ---------  ------------- --------
                                                                      ($000'S)
   <S>                                       <C>        <C>           <C>
   Outstanding at December 31, 1993.........   336,500  $ 3.88-$13.38 $ 1,949
   Plains outstanding options...............   592,611  $15.91-$27.50  13,962
                                             ---------  ------------- -------
   Outstanding at December 31, 1993,
    restated................................   929,111  $ 3.88-$27.50  15,911
   Granted..................................   585,500  $10.38-$20.88   8,560
   Exercised or canceled....................  (154,820) $ 3.88-$12.13    (712)
                                             ---------  ------------- -------
   Outstanding at December 31, 1994......... 1,359,791  $ 3.88-$27.50  23,759
   Granted..................................   110,000  $13.38-$22.75   2,454
   Exercised or canceled....................  (477,460) $ 3.88-$27.50  (9,443)
                                             ---------  ------------- -------
   Outstanding at December 31, 1995.........   992,331  $ 5.00-$26.94 $16,770
                                             =========  ============= =======
   Exercisable at December 31, 1995.........   354,883  $ 5.13-$26.94 $ 6,349
                                             =========  ============= =======
</TABLE>
 
8. RETIREMENT BENEFITS
 
  The Company has a voluntary 401(k) employee savings plan. Under this plan,
the Company matches 50% of each of the participating employees' contributions,
up to a maximum of 6% of base salary. Effective April 1, 1996, the Company's
match will be increased to 100% of each of the participating employees
contributions, up to a maximum of 6% of base salary, with one-half of the
match paid in cash and one half of the match paid in the Company's common
stock. The Company's matching contributions are subject to a vesting schedule.
Company contributions were $239,000, $179,000 and $166,000 in 1995, 1994 and
1993, respectively.
 
  Plains had several employee benefit plans described below. Pursuant to the
terms of the merger agreement between Plains and the Company, these plans were
terminated.
 
  Plains' qualified, defined benefit retirement plan covered substantially all
of its employees. The benefits were based on a specified level of the
employee's compensation during plan participation. As of July 18, 1995, the
plan froze benefit accruals. Pursuant to the plan, all participants became
fully vested. Plan assets consist of
 
                                     F-11
<PAGE>
 
                         BARRETT RESOURCES CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
                        DECEMBER 31, 1995, 1994 AND 1993
cash and equivalents, corporate stocks and bonds, U.S. treasury notes, insured
annuity contracts, and accrued interest. Contributions totaled $169,000,
$312,000 and $341,000 for the 1995, 1994 and 1993 plan years, respectively.
 
  The following table sets forth the plan's funded status:
 
<TABLE>
<CAPTION>
                                                        1995    1994     1993
                                                       ------  -------  -------
                                                           (IN THOUSANDS)
   <S>                                                 <C>     <C>      <C>
   Actuarial present value of benefit obligations:
     Accumulated benefit obligation, including vested
      benefits of $2,961,000, $1,637,000 and
      $1,290,000 respectively........................  $2,961  $(1,666) $(1,383)
                                                       ======  =======  =======
     Projected benefit obligation....................  $2,961  $(2,396) $(2,321)
     Plan assets at fair value.......................   2,709    2,205    1,977
                                                       ------  -------  -------
     Projected benefit obligation in excess of plan
      assets.........................................    (252)    (191)    (344)
     Unrecognized net (gain) loss....................     --      (141)      16
     Prior service cost not yet recognized in net
      periodic pension costs.........................     --        93       64
     Unrecognized net obligation being recognized
      over 9.5 and 10.5 years in 1994 and 1993,
      respectively...................................     --       132      146
                                                       ------  -------  -------
     Accrued pension cost............................  $ (252) $  (107) $  (118)
                                                       ======  =======  =======
   Net pension cost included the following
    components:
     Service cost--benefits earned...................  $  140  $   290  $   346
     Interest cost on projected benefit obligation...     160      157      150
     Actual loss (return) on plan assets.............    (369)      70     (145)
     Net amortization of unrecognized obligation and
      deferral.......................................     347     (216)      28
     Curtailment gain................................    (735)     --       --
                                                       ------  -------  -------
   Net periodic pension cost (benefit)...............  $ (457) $   301  $   379
                                                       ======  =======  =======
</TABLE>
 
  The weighted average discount rate used in determining the actuarial present
value of the projected benefit obligation was 4.5% (termination rates). The
rate of increase used for compensation levels was nil in 1995 and 5% in 1994
and 1993, respectively. The expected long-term rate of return on assets was
8.5%.
 
  Plains also contributed the lesser of 10% of its net earnings or 10% of
employee compensation to a profit sharing plan of Plains. No contributions were
made for 1995. Plains contributed $334,000 and $188,000 for 1994 and 1993,
respectively.
 
  Through June 30, 1995 and during 1994, Plains matched 401(k) plan deferrals
with contributions equal to 50% of each deferral up to 6% of current salary.
This matching contribution was invested in Plains stock and were subject to a
vesting schedule. Participants became fully vested with the merger with and
into Barrett. Contributions were approximately $112,000, $192,000 and $250,000
for 1995, 1994 and 1993, respectively.
 
  The above described profit-sharing and 401(k) plans were terminated July 1,
1995; the pension plans were terminated September 18, 1995. Internal Revenue
Service approval for termination of these plans was received in January 1996.
Final distribution of plan assets will be made to participants in the second
quarter of 1996.
 
  Plains' executive deferred compensation plan and directors' deferred plan
permitted the deferral of current salary or directors' fees for the purpose of
providing funds at retirement or death for employees, directors and
 
                                      F-12
<PAGE>
 
                         BARRETT RESOURCES CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
                        DECEMBER 31, 1995, 1994 AND 1993
their beneficiaries. These plans were terminated effective June 30, 1995 and
will be disbursed to the participants by the trustee of the assets over a
period ending January 1, 1997. Total accrued liability under these plans at
December 31, 1995 and 1994 was $36,000 and $1,006,000, respectively.
 
  Concurrently with the effective date of the merger, Plains' postretirement
healthcare benefit and salary continuation plans were terminated. Participants
in the salary continuation plan received (1) a lump sum benefit equal to the
present value of the remaining monthly payments if receiving Death Benefits
under the plan at the date of the termination, or (2) insurance policies, the
cost of which was limited to the cash values of the life insurance policies
owned by Plains. Benefits associated with the postretirement healthcare benefit
plan were terminated and, accordingly, accrued postretirement benefit costs
were relieved.
 
  Effective January 1, 1993, Plains adopted Statement No. 106 (FAS 106) issued
by the Financial Accounting Standards Board on accounting for postretirement
benefits other than pensions. In accordance with this statement, Plains elected
to recognize the accumulated postretirement benefit liability as of the
effective date, totaling approximately $800,000 (pretax). With the termination
of these plans in 1995, all future obligations were settled and ceased to
exist.
 
  Obligations for previous periods were as follows:
 
<TABLE>
<CAPTION>
                                                                 DECEMBER 31,
                                                                     1994
                                                                --------------
                                                                (IN THOUSANDS)
   <S>                                                          <C>
   Accumulated postretirement benefit obligation:
     Active plan participants..................................     $(458)
     Retirees..................................................      (302)
                                                                    -----
                                                                     (760)
     Plan assets...............................................         0
                                                                    -----
     Net accumulated postretirement benefit obligation.........      (760)
     Unrecognized net gain from past experience different from
      that assumed and from changes in assumptions.............      (167)
                                                                    -----
     Accrued postretirement benefit cost.......................     $(927)
                                                                    =====
   Net periodic postretirement benefit cost included the
    following components:
     Service cost of benefits earned...........................     $  41
     Interest cost on accumulated post-retirement benefit
      obligation...............................................        61
                                                                    -----
     Net periodic postretirement benefit cost..................     $ 102
                                                                    =====
</TABLE>
 
9. HEDGING ACTIVITIES
 
  The Company uses various hedging techniques to reduce the effect of price
volatility on the sales price of a portion of its oil and gas sales. The
objective of its hedging activities is to achieve more predictable revenues and
cash flows. The following is a summary of the Company's hedging transactions in
effect as of December 31, 1995.
 
  A. The Company is the fixed price payor for hedging transactions relating
  to 6,000 MMBtu of gas per day for 1996 at $1.33 per MMBtu and approximately
  7,000 MMBtu of gas per day for January through May 1996 at an average price
  of $2.12 per MMBtu. Under these price swap arrangements, the Company has
  agreed to buy gas at a fixed price and sell gas at an index price. These
  price swaps were entered to accommodate markets desiring fixed price
  supplies.
 
                                      F-13
<PAGE>
 
                         BARRETT RESOURCES CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
                       DECEMBER 31, 1995, 1994 AND 1993
 
    B. The Company will receive fixed prices ranging from $1.46 to $2.12 per
  MMBtu in swap transactions associated with an average of 52,000 MMBtu of
  gas per day to be produced by the Company subsequent to December 31, 1995
  through March 1996. The Company is required to pay an index price to its
  financial counterparty. The Company sold a call option on 20,000 MMBtu per
  day for April through October 1996. Under this option, the Company will
  receive $1.86 per MMBtu should the option holder elect to exercise.
 
    C. The Company's gas hedges also include a collar in which the Company
  sold a call and purchased a put with respect to 10,000 MMBtu per day in
  1996 with an average floor (put) price of $1.60 per MMBtu and an average
  ceiling (call) price of $1.92 per MMBtu. Under this arrangement, the
  Company receives a payment if the index price falls below the floor and
  makes a payment to the counterparty if the index price exceeds the ceiling.
  To reduce exposure to increasing index prices, the Company purchased call
  options with prices averaging $2.673 per MMBtu January--March and $1.969
  per MMBtu April--December, 1996.
 
    D. The Company has entered into basis swaps to minimize different index
  price fluctuations. The Company will receive a payment in the event that
  the New York Mercantile Exchange ("NYMEX") price per MMBtu for a reference
  period exceeds the average specified index price by more than an average of
  $.29 on 10,000 MMBtu of gas per day from January through March 1996 ($.44
  on 5,000 MMBtu of gas per day for April 1996). In separate basis swaps, the
  Company will receive a payment in the event the specified index price
  exceeds the NYMEX price net of a basis adjustment of an average of $.48 on
  10,000 MMBtu of gas per day from January through October 1996. Conversely,
  the Company will be required to make payments to the counterparty if the
  opposite situation exists in these swaps. These swaps were entered to
  offset a portion of the risk associated with the Company's long-term firm
  transportation portfolio.
 
    E. With respect to crude oil production, the Company entered into a price
  swap whereby the Company will receive a fixed price of $18.00 per Bbl for
  1,000 Bbls per day through March 1996. The Company is required to pay the
  counterparty a NYMEX settlement price.
 
  As of December 31, 1995, some of the Company's hedging positions described
above did not qualify for hedge accounting due to reduced correlation between
the index price and the prices to be realized for certain physical gas
deliveries. Accordingly, the Company recognized hedging losses of $1.2 million
in the fourth quarter of 1995. These losses offset hedging gains of $1.6
million realized in 1995. The net hedging gain was included in oil and gas
revenues. The Company paid and received certain premiums related to its option
contracts for future periods. The unrealized hedging losses and net deferred
premium costs have been included in other liabilities.
 
  During 1995, the Company incurred a net cost of $2.1 million to hedge the
index based price for a portion of its gas purchased in various transactions
for gas trading activities. These payments allowed the Company to purchase gas
on a fixed price basis to satisfy fixed price sales commitments. This hedging
allowed the Company to avoid gas price fluctuations for the related
transactions so that the Company realized the gross profit margins anticipated
upon entering into the trading arrangements. This hedging cost is included in
the income statement as a component of "Cost of Trading."
 
                                     F-14
<PAGE>
 
                         BARRETT RESOURCES CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
                       DECEMBER 31, 1995, 1994 AND 1993
 
10. COMMITMENTS AND CONTINGENCIES
 
 Lease Commitments
 
  The minimum future payments under the terms of operating leases, principally
for office space, are as follows:
 
<TABLE>
<CAPTION>
                                           (IN THOUSANDS)
            <S>                            <C>
            Year ended December 31,
              1996........................     $1,012
              1997........................        988
              1998........................      1,001
              1999........................        887
              2000........................        610
              2001........................        205
                                               ------
                                               $4,703
                                               ======
</TABLE>
 
  The Company plans to sublet office space vacated with the consolidation and
relocation of its Denver offices and accordingly anticipates a substantial
reduction in rental expense for the years 1996 through 1999. Rent expense was
$956,000, $859,000 and $788,000 for the years ended December 31, 1995, 1994
and 1993, respectively.
 
 Litigation
 
  On November 2, 1994, a putative class action was filed in Delaware Chancery
Court. In that case, entitled Miller v. Cody, the plaintiff has alleged that
certain named former directors of Plains, and Plains, have, among other
things, breached their fiduciary duties and otherwise acting to entrench
themselves in office. Plaintiff seeks various forms of injunctive relief,
damages and an award of plaintiff's costs and disbursements.
 
  On May 3, 1995, the same day Plains announced it had executed a merger
agreement with the Company, a putative class action, entitled Crandon Capital
Partners v. Miller, was filed in Delaware Chancery Court against Plains and
the then-current members of its Board of Directors. In this suit it is alleged
that, among other things, the agreement was inadequate, plaintiff seeks
various forms of declaratory and injunctive relief, damages and an award of
plaintiff's costs and disbursements.
 
  Plains and its former directors have received a status report filed by
plaintiffs' counsel in both cases indicating a "stipulation of dismissal
without prejudice will be circulated shortly."
 
  Except as noted above, at December 31, 1995, 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.
 
 Environmental Controls
 
  At year end 1995, 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 is not expected to have, a material
adverse effect on the Company's capital expenditures, earnings or competitive
position.
 
                                     F-15
<PAGE>
 
                         BARRETT RESOURCES CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
                       DECEMBER 31, 1995, 1994 AND 1993
 
 Major Purchaser
 
  During 1995, one purchaser accounted for 18 percent of the Company's total
revenue (24 percent of oil and gas revenues.) Sales of gas to this purchaser
represented 19 percent and 29 percent of total revenues in 1994 and 1993,
respectively.
 
11. INCOME TAXES
 
  The provision for income taxes consists of the following:
 
<TABLE>
<CAPTION>
                                                            1995    1994   1993
                                                           ------  ------ ------
                                                              (IN THOUSANDS)
   <S>                                                     <C>     <C>    <C>
   Current:
     Federal.............................................. $  269  $  233 $  174
     State................................................   (233)    117    416
                                                           ------  ------ ------
                                                               36     350    590
   Deferred:
     Federal..............................................  2,039   4,511  5,138
     State................................................   (241)    277    993
                                                           ------  ------ ------
                                                            1,798   4,788  6,131
                                                           ------  ------ ------
                                                           $1,834  $5,138 $6,721
                                                           ======  ====== ======
</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 before provision for income taxes is analyzed below:
 
<TABLE>
<CAPTION>
                                                      1995    1994     1993
                                                     ------  -------  -------
                                                         (IN THOUSANDS)
   <S>                                               <C>     <C>      <C>
   Tax by applying the statutory federal income tax
    rate to pretax accounting income (loss)........  $ (138) $ 5,753  $ 7,365
   Increase (decrease) in tax from:
     Change in valuation allowance.................     396   (2,148)  (1,477)
     State income taxes............................    (474)     394    1,409
     Non-deductible merger costs...................   2,429      --       --
     Other, net....................................    (379)   1,139     (576)
                                                     ------  -------  -------
                                                     $1,834  $ 5,138  $ 6,721
                                                     ======  =======  =======
</TABLE>
 
                                     F-16
<PAGE>
 
                         BARRETT RESOURCES CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
                       DECEMBER 31, 1995, 1994 AND 1993
 
  Long-term deferred tax assets (liabilities) are comprised of the following
at December 31, 1995 and 1994:
 
<TABLE>
<CAPTION>
                                                              1995      1994
                                                            --------  --------
                                                             (IN THOUSANDS)
   <S>                                                      <C>       <C>
   Deferred tax assets:
     Allowance for losses.................................. $     81  $    624
     Loss carryforwards and other..........................   26,520    30,221
                                                            --------  --------
       Gross deferred tax assets...........................   26,601    30,845
   Deferred tax liabilities:
     Deferred revenue--partnership activities..............     (466)   (1,086)
     Depreciation, depletion and amortization..............  (48,460)  (50,650)
     Capitalized interest on other assets..................       (6)      (38)
                                                            --------  --------
     Gross deferred tax liabilities........................  (48,932)  (51,774)
                                                            --------  --------
       Net deferred tax liability..........................  (22,331)  (20,929)
       Valuation allowance.................................   (1,193)     (797)
                                                            --------  --------
                                                            $(23,524) $(21,726)
                                                            ========  ========
</TABLE>
 
  Valuation allowances of $1,193,000 and $797,000 were provided at December
31, 1995 and 1994, respectively, based on carryforward amounts which may not
be utilized before expiration and the possible effect of exploratory drilling
costs.
 
  The Company has the following net operating loss and investment tax credit
carryforwards available:
 
<TABLE>
<CAPTION>
        EXPIRATION                                      NET OPERATING INVESTMENT
          YEAR                                              LOSS      TAX CREDIT
        ----------                                      ------------- ----------
                                                             (IN THOUSANDS)
        <S>                                             <C>           <C>
        1996...........................................    $ 4,227       $172
        1997...........................................      4,673        246
        1998...........................................      8,090        103
        1999...........................................      6,530        100
        2000...........................................      4,900         25
        2001...........................................      3,274          5
        2002...........................................        108        --
        2004...........................................        197        --
        2005...........................................        685        --
        2006...........................................      1,446        --
        2007...........................................         37        --
        2008...........................................     22,352        --
        2009...........................................      6,123        --
                                                           -------       ----
        Total..........................................    $62,642       $651
                                                           =======       ====
</TABLE>
--------
A substantial portion of the net operating losses were acquired in conjunction
with purchased operations.
 
  The 1990 public offering of common stock by the Company before the Plains
merger resulted in a change in the Company's ownership as defined in Section
382 of the Internal Revenue Code. The effect of this change in ownership
limits the utilization of net operating losses for income tax purposes to
approximately $3,069,000 per year which affects $13,590,000 of the net
operating losses. The 1995 merger with Plains also resulted in a
 
                                     F-17
<PAGE>
 
                         BARRETT RESOURCES CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
                       DECEMBER 31, 1995, 1994 AND 1993
change in the Company's and Plains' ownership as defined by Section 382 of the
Internal Revenue Code. The change effectively limits the utilization of the
remaining net operating losses for income tax purposes to approximately
$14,000,000 for each company. Portions of the above limitations which are not
used each year may be carried forward to future years.
 
  The Internal Revenue Service (IRS) is currently examining the federal tax
returns of Plains and subsidiaries for calendar years 1991, 1992 and 1993. The
examinations are not yet complete, but based on preliminary comments from the
IRS examiner, management anticipates that the IRS will propose adjustments to
disallow net operating loss deductions claimed by Plains thereby increasing
taxable income for the years under examination. Management is of the opinion
that the federal tax returns of Plains for years 1991 through 1993 reflect the
proper federal income tax liability as supported by relevant authority. The
Company intends to vigorously dispute any adjustments proposed by the
examining agent and furthermore believes that the Company will prevail in its
positions.
 
12. SUPPLEMENTAL CASH FLOW SCHEDULES AND INFORMATION
 
  Cash paid during years
<TABLE>
<CAPTION>
                                                               1995  1994 1993
                                                              ------ ---- ----
                                                               (IN THOUSANDS)
   <S>                                                        <C>    <C>  <C>
   Income tax................................................ $   65 $338 $426
   Interest..................................................  5,129  711  792
 
  Supplemental information of noncash investing and financing activities:
 
   Issuance of common stock exchanged for treasury shares in
    cashless option transactions............................. $  545 $313 $204
</TABLE>
 
  In May 1994, Plains completed a contingent provision of the 1990 McAdams,
Roux and Associates, Inc. (MRA) Agreement and Plan of Merger, as it related to
the right of the MRA shareholders to receive additional shares of Plains'
common stock and cash subject to reserves additions on certain property
interests owned by MRA prior to the merger. Under this Agreement, 31,873
shares of Plains' common stock were issued and a cash payment of $1.5 million
was paid to MRA's shareholders in settlement of this obligation.
 
13. RELATED PARTIES
 
  During the years ended December 31, 1995, 1994 and 1993 Zenith Drilling
Corporation ("Zenith") was billed by the Company as operator, approximately
$1,062,000, $1,853,000 and $2,555,000, respectively, for Zenith's portion of
lease operating expenses and development costs in certain leases operated by
the Company. Also as a result of Zenith's working interest ownership, the
Company distributed oil and gas revenue of approximately $942,000, $936,000
and $1,074,000 to Zenith during 1995, 1994 and 1993, respectively. Zenith owns
its working interests subject to the same terms and arrangements that exist
for all working interest owners in the properties. Zenith owns approximately
three percent of the Company's common stock and its president is a member of
the Company's board of directors.
 
  During 1993, the Company and Zenith both sold their respective interests in
the Wattenberg field. The Company and Zenith jointly negotiated the sale but
the purchaser independently determined the individual offer prices and entered
into separate sales agreements with each party.
 
  Grand Valley Corporation owns approximately 10 percent of a pipeline joint
venture for gas gathering of which a subsidiary of the Company owns
approximately 29 percent. A member of the Company's board of
 
                                     F-18
<PAGE>
 
                         BARRETT RESOURCES CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
                       DECEMBER 31, 1995, 1994 AND 1993
directors owns 10 percent of the outstanding stock, and is the president of
Grand Valley Corporation. His three adult children own the remaining 90
percent of the outstanding stock of Grand Valley Corporation.
 
14. QUARTERLY INFORMATION (UNAUDITED)
 
<TABLE>
<CAPTION>
                                                THREE MONTHS ENDED
                                       ------------------------------------------
                                       3/31/95   6/30/95    9/30/95    12/31/95
                                       --------- --------- ----------  ----------
                                       (IN THOUSANDS, EXCEPT PER SHARE DATA)
   <S>                                 <C>       <C>       <C>         <C>
   1995
   Net revenues......................  $  33,060 $  31,277 $   27,217  $  35,070
   Gross margin......................      8,611     8,039      6,476      7,882
   Income (loss) from operations.....      4,327     3,997    (11,389)     2,659
   Net income (loss).................      3,014     2,957    (11,848)     3,637
   Net income (loss) per share.......        .11       .13       (.47)       .14
<CAPTION>
                                                THREE MONTHS ENDED
                                       ------------------------------------------
                                       3/31/94   6/30/94    9/30/94    12/31/94
                                       --------- --------- ----------  ----------
                                       (IN THOUSANDS, EXCEPT PER SHARE DATA)
   <S>                                 <C>       <C>       <C>         <C>
   1994
   Net revenues......................  $  25,543 $  24,420 $   24,222  $  33,076
   Gross margin......................      8,572     7,499      6,027      6,990
   Income from operations............      5,217     3,869      2,834      4,517
   Net income........................      3,799     2,610      2,081      2,809
   Net income per share..............        .15       .12        .08        .11
<CAPTION>
                                                THREE MONTHS ENDED
                                       ------------------------------------------
                                       3/31/93   6/30/93    9/30/93    12/31/93
                                       --------- --------- ----------  ----------
                                       (IN THOUSANDS, EXCEPT PER SHARE DATA)
   <S>                                 <C>       <C>       <C>         <C>
   1993
   Net revenues......................  $  30,258 $  26,157 $   22,836  $  24,831
   Gross margin......................      8,832     8,759      6,902      7,346
   Income from operations............      6,163     5,649      4,845      4,386
   Income before cumulative effect of
    change in method of accounting
    for income taxes.................      3,828     3,492      3,934      3,068
   Net income........................      3,172     3,492      3,934      3,068
   Earnings per share:
     From continuing operations......        .16       .14        .16        .12
     Net income......................        .13       .14        .16        .12
</TABLE>
 
                                     F-19
<PAGE>
 
                     SUPPLEMENTAL OIL AND GAS INFORMATION
 
  The following is information pertaining to the Company's oil and gas
producing activities for the years ended December 31, 1995, 1994 and 1993.
 
  Costs incurred in oil and gas property acquisition, exploration, and
development activities:
 
<TABLE>
<CAPTION>
                                                    1995     1994      1993
                                                   -------  -------  --------
                                                        (IN THOUSANDS)
<S>                                                <C>      <C>      <C>
Acquisition of evaluated properties............... $ 7,429  $35,234  $  6,119
Acquisition of unevaluated properties.............   8,383    8,446     1,013
Exploration costs.................................  23,272   36,232    12,593
Development costs.................................  33,029   20,190    21,538
Other, principally proceeds from mineral
 conveyances......................................    (426)    (173)  (15,680)
                                                   -------  -------  --------
  Total additions to oil and gas properties....... $71,687  $99,929  $ 25,583
                                                   =======  =======  ========
</TABLE>
 
OIL AND GAS RESERVE INFORMATION (UNAUDITED):
 
  The following reserve related information for 1995 is based on estimates
prepared by the Company. The 1995 reserve information for the Company,
exclusive of the reserves owned by its subsidiary, Plains, were reviewed by
Ryder Scott, an independent reservoir engineer. The 1995 reserve information
for Plains was reviewed by Netherland, Sewell & Associates, Inc., an
independent reservoir engineer. The Company's 1994 and 1993 reserves,
exclusive of Plains were prepared by the Company and reviewed by Ryder Scott
as of September 30, of each year. The 1994 and 1993 proved developed reserve
estimates of Plains were prepared by Netherland, Sewell & Associates, Inc.
whereas the proved undeveloped reserve estimates were prepared by Plains.
Reserve estimates are inherently imprecise and are continually subject to
revisions based on production history, results of additional exploration and
development, prices of oil and gas and other factors.
 
<TABLE>
<CAPTION>
                                 1995                 1994                 1993
                         -------------------- -------------------- --------------------
                         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.....  11,444    458,820     6,947    364,791    10,553    370,621
  Revisions of previous
   estimates............   1,209     (3,805)      772     (5,640)   (3,426)    (5,418)
  Purchase of minerals
   in place.............     831      3,983     2,533     38,717       217      6,794
  Extensions and
   discoveries..........   1,232    102,329     2,547     94,276     1,208     28,482
  Production............  (1,702)   (47,692)   (1,293)   (33,282)   (1,293)   (31,712)
  Sale of minerals in
   place................     (47)      (104)      (62)       (42)     (312)    (3,976)
                          ------    -------    ------    -------    ------    -------
  End of year...........  12,967    513,531    11,444    458,820     6,947    364,791
                          ======    =======    ======    =======    ======    =======
Proved developed
 reserves:
  Beginning of year.....   7,848    393,051     5,548    342,287     7,398    350,131
                          ======    =======    ======    =======    ======    =======
  End of year...........  11,669    419,672     7,848    393,051     5,548    342,287
                          ======    =======    ======    =======    ======    =======
</TABLE>
 
                                     F-20
<PAGE>
 
  The following is the standardized measure of discounted future net cash
flows relating to proved oil and gas reserves in which the Company has an
interest.
 
<TABLE>
<CAPTION>
                                                1995       1994       1993
                                             ----------  ---------  ---------
                                                     (IN THOUSANDS)
<S>                                          <C>         <C>        <C>
Future cash inflows......................... $1,132,711  $ 931,404  $ 789,693
Future production costs.....................   (355,756)  (310,485)  (266,920)
Future development costs....................    (46,888)   (41,972)   (22,349)
Future income tax expenses..................   (207,922)  (152,890)  (135,165)
                                             ----------  ---------  ---------
  Future net cash flows.....................    522,145    426,057    365,259
10% annual discount for estimated timing of
 cash flows.................................   (212,271)  (183,436)  (162,173)
                                             ----------  ---------  ---------
Standardized measure of discounted future
 net cash flows............................. $  309,874  $ 242,621  $ 203,086
                                             ==========  =========  =========
</TABLE>
 
  The future income tax expenses have been computed considering the tax basis
of the oil and gas properties, and net operating and other loss carryforwards.
 
  The following are the principal sources of changes in the standardized
measure of discounted future net cash flows:
 
<TABLE>
<CAPTION>
                                                    1995      1994      1993
                                                  --------  --------  --------
                                                        (IN THOUSANDS)
<S>                                               <C>       <C>       <C>
Net change in sales price and production costs..  $ 24,558  $(22,409) $ 12,283
Changes in estimated future development costs...    10,301    14,492    11,160
Sales and transfers of oil and gas produced, net
 of production costs............................   (62,294)  (50,571)  (53,594)
Net change due to extensions and discoveries....    85,524    60,613    20,739
Net change due to purchases and sales of
 minerals in place..............................     7,424    32,726    (1,210)
Net change due to revisions in quantities.......    (1,393)     (588)  (18,272)
Net change in income taxes......................   (33,172)  (10,202)   (4,711)
Accretion of discount...........................    23,112    27,589    26,965
Other, principally revisions in estimates of
 timing of production...........................    13,193   (12,115)    5,859
                                                  --------  --------  --------
Net changes.....................................    67,253    39,535      (781)
Balance, beginning of year......................   242,621   203,086   203,867
                                                  --------  --------  --------
Balance, end of year............................  $309,874  $242,621  $203,086
                                                  ========  ========  ========
</TABLE>
 
 
                                     F-21
<PAGE>
 
                                  SIGNATURES
 
  PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES AND
EXCHANGE 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
 
                                                  /s/ William J. Barrett
Date: March 5, 1996                       By: _________________________________
                                                 WILLIAM J. BARRETT, CHIEF
                                                     EXECUTIVE OFFICER
 
Date: March 5, 1996                                 /s/ John F. Keller
                                          By: _________________________________
                                                      JOHN F. KELLER, 
                                                  CHIEF FINANCIAL OFFICER,
                                                  SECRETARY, AND PRINCIPAL
                                              FINANCIAL AND ACCOUNTING OFFICER
 
              SIGNATURE                        TITLE                 DATE
 
       /s/ William J. Barrett                Director           March 5, 1996
-------------------------------------
         WILLIAM J. BARRETT
 
        /s/ C. Robert Buford                 Director           March 5, 1996
-------------------------------------
          C. ROBERT BUFORD
 
          /s/ Derrill Cody                   Director           March 5, 1996
-------------------------------------
            DERRILL CODY
 
      /s/ James M. Fitzgibbons               Director           March 5, 1996
-------------------------------------
        JAMES M. FITZGIBBONS
 
      /s/ Hennie L.J.M. Gieskes              Director           March 5, 1996
-------------------------------------
        HENNIE L.J.M. GIESKES
 
      /s/ William W. Grant, III              Director           March 5, 1996
-------------------------------------
        WILLIAM W. GRANT, III
 
         /s/ John F. Keller                  Director           March 5, 1996
-------------------------------------
           JOHN F. KELLER
 
          /s/ Paul M. Rady                   Director           March 5, 1996
-------------------------------------
            PAUL M. RADY
 
          /s/ A. Ralph Reed                  Director           March 5, 1996
-------------------------------------
            A. RALPH REED
 
        /s/ James T. Rodgers                 Director           March 5, 1996
-------------------------------------
          JAMES T. RODGERS
 
     /s/ Philippe S.E. Schreiber             Director           March 5, 1996
-------------------------------------
       PHILIPPE S.E. SCHREIBER
 
         /s/ Harry S. Welch                  Director           March 5, 1996
-------------------------------------
           HARRY S. WELCH
 
                                     II-1