BARRETT RESOURCES CORP, 424B4, 1997-02-12

BARRETT RESOURCES CORP
424B4, 1997-02-12
CRUDE PETROLEUM & NATURAL GAS

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[LOGO OF BARRETT RESOURCES CORPORATION APPEARS HERE]

$150,000,000

BARRETT RESOURCES CORPORATION

7.55% SENIOR NOTES DUE 2007

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

The 7.55% Senior Notes due 2007 of Barrett Resources Corporation will be
senior unsecured obligations of the Company and will mature on February 1,
2007. Interest on the Notes is payable on February 1 and August 1 of each
year, commencing August 1, 1997. The Notes may be redeemed at any time, at the
option of the Company, in whole or in part, at a price equal to 100% of the
principal amount plus accrued and unpaid interest (if any) to the date of
redemption plus a Make-Whole Premium, if any, relating to the then prevailing
Treasury Yield and the remaining life of the Notes. The Notes will rank pari
passu in right of payment with any existing and future senior unsecured
indebtedness of the Company, including under its bank credit facility, and
senior in right of payment to all existing and future subordinated
indebtedness of the Company. See "Description of Notes."

The Company will use the net proceeds of the Offering to repay in full
indebtedness under its bank credit facility, to fund a portion of its planned
exploration and development activities and for other general corporate
purposes, including possible acquisitions. See "Use of Proceeds."

The Notes will be evidenced by a Global Certificate in fully registered form
without coupons, deposited with a custodian for and registered in the name of
a nominee of The Depository Trust Company. Except as described herein,
beneficial interests in the Global Certificate will be shown on, and transfers
thereof will be effected only through, records maintained by DTC and its
direct and indirect participants. See "Description of Notes." The Notes are
not entitled to any sinking fund. The Company does not intend to apply for
listing of the Notes on any securities exchange or for inclusion of the Notes
in any automated quotation system.

SEE "RISK FACTORS" COMMENCING ON PAGE 9 FOR INFORMATION THAT SHOULD BE
CONSIDERED BY PROSPECTIVE INVESTORS IN CONNECTION WITH AN INVESTMENT IN THE
NOTES.

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

THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE
ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.

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

<TABLE>
<CAPTION>
INITIAL PUBLIC UNDERWRITING PROCEEDS TO
OFFERING PRICE(1) DISCOUNT(2) COMPANY(1)(3)
----------------- ------------ -------------
<S> <C> <C> <C>
Per Note..................................... 99.732% 2.000% 97.732%
Total........................................ $149,598,000 $3,000,000 $146,598,000
</TABLE>
- --------
(1) Plus accrued interest from February 1, 1997.
(2) The Company has agreed to indemnify the Underwriters against certain
liabilities, including liabilities under the Securities Act of 1933. See
"Underwriting."
(3) Before deducting estimated expenses of $450,000 payable by the Company.

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

The Notes offered hereby are offered severally by the Underwriters, as
specified herein, subject to receipt and acceptance by them and subject to
their right to reject any order in whole or in part. It is expected that the
Notes will be ready for delivery in book-entry form only through the
facilities of DTC in New York, New York, on or about February 14, 1997,
against payment therefor in immediately available funds.

GOLDMAN, SACHS & CO.

CHASE SECURITIES INC.

LEHMAN BROTHERS

PETRIE PARKMAN & CO.

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

The date of this Prospectus is February 11, 1997.

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[CORE AREAS OF ACTIVITY MAP APPEARS HERE]

IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT
TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE NOTES OFFERED
HEREBY AT A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN MARKET.
SUCH STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME.

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PROSPECTUS SUMMARY

The following summary is qualified in its entirety by the more detailed
information and financial statements appearing elsewhere in this Prospectus and
in the documents incorporated by reference into this Prospectus. As used
herein, the "Company" or "Barrett" means Barrett Resources Corporation and its
subsidiaries unless the context requires otherwise. Unless otherwise indicated,
all references to annual or quarterly periods refer to the Company's fiscal
year ending December 31. Unless otherwise indicated herein, the information in
this Prospectus includes the effects of the restatement of the Company's
financial, operating and reserve information to include Plains Petroleum
Company ("Plains") on a combined basis effective for all periods as a result of
the July 18, 1995 merger with Plains, which was accounted for as a pooling of
interests. Investors should carefully consider the information set forth under
the heading "Risk Factors." Certain terms used herein relating to the oil and
gas industry are defined in "Certain Definitions" included on pages 55 and 56
of this Prospectus.

THE COMPANY

GENERAL

Barrett is an independent natural gas and crude oil exploration and
production company with core areas of activity in the Rocky Mountain Region of
Colorado, Wyoming and Utah; the Mid-Continent Region of Kansas, Oklahoma, New
Mexico and Texas; and the Gulf of Mexico Region of offshore Texas and
Louisiana. At December 31, 1996, the Company's estimated proved reserves were
814.3 Bcfe (83% natural gas and 17% crude oil) with an implied reserve life of
11.3 years based on 1996 total production of 72.3 Bcfe.

The Company concentrates its activities in core areas in which it has
accumulated detailed geologic knowledge and developed significant management
expertise. The Company continues to build on its interests in the Piceance
Basin in northwestern Colorado, the Uinta Basin of northeastern Utah, the
Anadarko and Arkoma Basins in Oklahoma, the Wind River Basin in Wyoming and the
Gulf of Mexico. The Company also has significant interests in the Hugoton
Embayment in Kansas and Oklahoma, the Permian Basin in Texas and New Mexico and
the Powder River Basin in Wyoming. At December 31, 1996, these principal areas
of focus represented approximately 94% of the Company's estimated proved
reserves.

The Company continues to experience significant growth in its proved
reserves, production volumes, revenues and cash flow, particularly in the Wind
River, Piceance, Anadarko, Arkoma and Uinta Basins. The Company currently is
pursuing development projects in the Wind River, Piceance, Anadarko, Arkoma and
Uinta Basins, and exploration projects in the Wind River and Anadarko Basins,
the Gulf of Mexico and the Republic of Peru. The Company's average net daily
production increased to 198 MMcfe for the year ended December 31, 1996 from 159
MMcfe for the year ended December 31, 1995.

As of September 30, 1996, the Company owned interests in 2,124 producing
wells and operated 1,131 of these wells. These operated wells contributed
approximately 82% of Barrett's natural gas and oil production for the nine
months ended September 30, 1996. The Company also owns interests in and
operates a natural gas gathering system, a 27-mile pipeline and a natural gas
processing plant in the Piceance Basin.

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parties and selling natural gas to other parties at prices and volumes that
management anticipates will result in profits to the Company. Through these
natural gas trading activities, the Company obtains knowledge and information
that enables it to more effectively market its own production. See "Business
and Properties--Natural Gas and Oil Marketing and Trading."

BUSINESS STRATEGY

Barrett's business strategy is to generate strong growth in reserves,
production, earnings and cash flow through exploration, development and
selective acquisitions of natural gas and oil properties in its core areas of
activity. The Company implements this strategy through a series of continuing
initiatives:

SPECIALIZED GEOLOGIC EXPERTISE. Both the CEO and President of Barrett are
experienced, practicing geologists. They have established a team of geologists
and geophysicists with expertise in the Company's core areas of activity. Prior
to undertaking projects in new areas, the Company assembles specialized
geologic expertise to identify and evaluate drilling prospects.

ACTIVE DRILLING PROGRAM. Barrett maintains a high quality, balanced portfolio
of lower risk development projects complemented by higher potential exploration
prospects. The Company's preliminary 1997 capital expenditure budget is $278
million, approximately 75% of which is allocated to drilling and production
activities. This budget, which is subject to revision based upon market
conditions and other factors, contemplates that the Company will participate in
drilling approximately 290 gross wells in 1997 as compared with 196 gross wells
drilled in 1996. The Company expects to continue high levels of drilling
activity after 1997.

ADVANCED TECHNOLOGY. The Company makes extensive use of advanced
technologies, including 3-D seismic and in-house analytical and processing
capabilities, to better define drilling prospects. The Company also uses
advanced production techniques, such as alkaline surfactant polymer ("ASP")
technology, in its enhanced recovery operations.

OPERATING CORE PROPERTIES. At September 30, 1996, Barrett served as operator
for 1,131 wells, which contributed approximately 82% of the Company's
production during the nine months ended September 30, 1996. As operator, the
Company coordinates drilling activities and arranges for the production,
gathering and sale of its natural gas and oil from operated wells. Serving as
operator enables the Company to exert greater control over the cost and timing
of its exploration, development and production activities.

CONTINUING COST MANAGEMENT. The Company continually strives to reduce
expenses through implementation of cost control programs and active management
of its operations, personnel and administrative activities. Current cost
management initiatives include entering into multi-well and longer term
contracts with drilling companies and participating in alliances with oil field
service companies to obtain more favorable terms.

FINANCIAL STRENGTH. The Company is committed to maintaining financial
flexibility in order to pursue exploration and development activities and to
take advantage of other opportunities that may arise. Historically, the Company
has funded its growth primarily through the issuance of common stock, including
four public stock offerings, its 1995 stock-for-stock merger with Plains and
several recent acquisitions financed with common stock. The issuance of the
Notes offered hereby (the "Notes") adds ten-year fixed rate debt financing to
the Company's capital structure, which will improve Barrett's liquidity,
diversify its capital base and enhance the Company's ability to pursue its
business strategy.

SELECTIVE RESERVE AND LEASEHOLD ACQUISITIONS. From time to time the Company
seeks to augment activities in its core areas, establish operations in new
areas and build acreage positions for

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exploration prospects through selective acquisitions. As a result of
acquisitions completed during 1996, the Company increased its working interests
in the Piceance Basin, expanded its operations in the Uinta Basin and
substantially increased its leased acreage position in the Gulf of Mexico.

RECENT DEVELOPMENTS

CAPITAL EXPENDITURES. The Company's preliminary 1997 capital expenditure
budget for natural gas and oil activities is $278 million. Total estimated 1997
expenditures are allocated approximately 41% to the Gulf of Mexico Region, 25%
to the Rocky Mountain Region, 19% to the Mid-Continent Region, 6% to
international activities and 9% to possible acquisitions. This budget is
subject to revision based upon market conditions and other factors. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and "Business and Properties--Core Areas of Activities."

OFFSHORE FEDERAL LEASE SALES. At the September 1996 Western Gulf of Mexico
Offshore Lease Sale, the Company significantly expanded its position in the
Gulf of Mexico. The Minerals Management Service ("MMS") awarded the Company
leases covering 17 blocks. The Company has a 100% working interest in 14 of
these blocks and a 50% working interest in the three other blocks. The
Company's net share of the bonus payments for these leases was $34.4 million.
As a result of these transactions, Barrett holds interests in 46 lease blocks
in the Gulf of Mexico covering approximately 185,000 gross acres. See "Business
and Properties--Core Areas of Activity--Gulf of Mexico Region."

UINTA BASIN ACQUISITIONS. In November 1996, the Company expanded its
operations in the Uinta Basin of northeastern Utah when it acquired producing
and non-producing natural gas and oil properties in the Altamont-Bluebell
Field. The effective date of the acquisition of a significant portion of these
properties is January 1, 1997. The purchase included 120 operated wells with an
average working interest of 80%, together with 100,000 gross and 72,000 net
acres of leasehold interests. The total purchase price was approximately $32
million, including approximately $14 million in cash, 50,000 shares of the
Company's common stock, and certain non-strategic producing properties owned by
the Company. In January 1997, the Company acquired additional interests in the
Altamont-Bluebell Field for an aggregate purchase price of $3.5 million in
cash. These interests consist of 16 non-operated wells with average working
interests of 42% together with approximately 10,000 gross and 4,600 net acres
of leasehold interests. See "Business and Properties--Core Areas of Activity--
Rocky Mountain Region--Uinta Basin."

PARTICIPATION IN MARANON BASIN, PERU. In late January 1997, the Company
entered into an agreement with industry partners that provided the Company with
a license covering approximately 2.0 million gross acres located in the Maranon
Basin of northeastern Peru. The Company and its partners intend to acquire and
analyze 200 to 250 miles of seismic data in preparation for exploratory
drilling to begin in late 1997 or early 1998. The Company's participation,
which is subject to approval of the government of Peru, is intended to consist
of a 45% working interest, subject to a cost commitment of 60% of the 1996 and
1997 seismic costs and 60% of the cost of up to three exploratory wells. It is
anticipated that the Company will be designated operator for operations in this
area in mid-1997. See "Business and Properties--Core Areas of Activity--
International Operations."

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THE OFFERING

<TABLE>
<S> <C>
Issuer Barrett Resources Corporation.
Securities Offered $150,000,000 principal amount of 7.55% Senior Notes due
2007.
Maturity Date February 1, 2007.
Interest Payment Dates February 1 and August 1 of each year, beginning on August
1, 1997.
Optional Redemption The Notes may be redeemed at any time, at the option of
the Company, in whole or in part, at a price equal to
100% of the principal amount plus accrued and unpaid
interest (if any) to the date of redemption plus a Make-
Whole Premium (if any) relating to the then prevailing
Treasury Yield and the remaining life of the Notes.
Mandatory Redemption None.
Ranking The Notes will be senior unsecured obligations of the
Company and will rank pari passu in right of payment with
any existing and future senior unsecured indebtedness of
the Company, including under its bank credit facility,
and senior in right of payment to all existing and future
subordinated indebtedness of the Company.
Certain Covenants The indenture (the "Indenture") relating to the Notes
will contain limitations on, among other things, the
Company's ability to (i) incur indebtedness secured by
certain liens, (ii) engage in certain sale/leaseback
transactions, and (iii) engage in certain merger,
consolidation or reorganization transactions. See
"Description of Notes."
Use of Proceeds The net proceeds from the offering of the Notes will be
used to repay in full indebtedness under the Company's
bank credit facility ($70 million outstanding as of
December 31, 1996 and $85 million outstanding as of
February 7, 1997), to fund a portion of the Company's
planned exploration and development activities and for
other general corporate purposes, including possible
acquisitions. See "Use of Proceeds."
</TABLE>

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SELECTED CONSOLIDATED FINANCIAL, RESERVE AND OPERATING DATA

The following table sets forth the selected historical consolidated
financial, reserve and operating data of Barrett for each of the periods
indicated. The historical financial data of Barrett for the three-year period
ended December 31, 1995 have been derived from Barrett's audited consolidated
financial statements. The historical financial data for the nine months ended
September 30, 1995 and 1996 are derived from unaudited financial statements of
the Company. Production data for all periods are unaudited. Barrett's
previously reported data for 1995 and prior years have been restated to reflect
the merger with Plains under the pooling of interests method of accounting and
the change in fiscal year end from September 30 to December 31. The selected
consolidated financial, reserve and operating data set forth below should be
read in conjunction with "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and the Consolidated Financial Statements
and notes thereto and other information included elsewhere in this Prospectus
and the documents incorporated herein by reference.

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER NINE MONTHS ENDED
31, SEPTEMBER 30,
----------------------- -------------------
1993 1994 1995(1) 1995(1) 1996
------ ------ ------- ---------- --------
(UNAUDITED)
(DOLLARS IN MILLIONS,
EXCEPT PER SHARE AND SALES PRICE DATA)
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA (2):
Revenues.......................... $106.1 $109.5 $128.0 $ 92.7 $ 136.1
Depreciation, depletion and
amortization..................... 20.2 22.8 33.5 23.6 31.9
Interest expense(3)............... 0.7 0.9 4.6 3.3 3.2
Income (loss) before income taxes
and cumulative effect of change
in method of accounting for
postretirement benefits.......... 21.0 16.4 (0.4) (3.1) 27.4
Net income (loss)................. 13.7 11.3 (2.2) (5.9) 17.0
Net income (loss) per share....... 0.55 0.46 (0.09) (0.23) 0.62
CASH FLOW STATEMENT DATA:
Cash flow from operations before
changes in working capital....... $ 40.5 $ 39.0 $ 33.4 $ 19.5 $ 57.5
Cash flow from operations after
changes in working capital....... 41.6 36.6 35.5 16.5 62.7
Cash flow used in investing
activities....................... 33.2 91.0 82.3 46.7 122.1
Cash flow provided by financing
activities....................... 11.2 37.2 41.9 36.5 61.3
OTHER FINANCIAL DATA:
EBITDA(4)......................... $ 41.2 $ 39.3 $ 37.0 $ 23.3 $ 61.7
Additions to property, plant and
equipment........................ 45.5 95.6 82.8 46.9 124.1
EBITDA/Interest expense(5)........ 56.9x 37.1x 7.3x 6.4x 19.5x
Ratio of earnings to fixed
charges(6)....................... 20.3x 12.2x 0.9x 0.1x 8.8x
RESERVE AND OPERATING DATA:
Estimated proved reserves(7)
Natural gas (Bcf)................ 364.8 458.8 513.5 -- --
Oil and condensate (MMBbls)...... 6.9 11.4 13.0 -- --
Total (Bcfe).................... 406.5 527.5 591.3 -- --
Present value of estimated future
net revenues before future income
taxes discounted at 10%(7)(8).... $277.6 $322.7 $432.6 -- --
Standardized measure of discounted
net cash flows (9)............... $203.1 $242.6 $309.9 -- --
Production
Natural gas (Bcf)................ 31.7 33.3 47.7 33.9 44.1
Oil and condensate (MMBbls)...... 1.3 1.3 1.7 1.3 1.4
Total (Bcfe)(7)................. 39.5 41.0 57.9 41.7 52.5
Reserves to production ratio
(years)(7)....................... 10.3 12.9 10.2 -- --
Average sales price
Natural gas ($/Mcf).............. $ 1.94 $ 1.83 $ 1.47 $ 1.48 $ 1.73
Oil and condensate ($/Bbl)....... 14.93 13.95 15.76 15.84 18.61
</TABLE>

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<TABLE>
<CAPTION>
AS OF
AS OF DECEMBER 31, SEPTEMBER 30, 1996
------------------- -----------------------
1994 1995 ACTUAL AS ADJUSTED (10)
--------- --------- ------ ----------------
(UNAUDITED)
(IN MILLIONS)
<S> <C> <C> <C> <C>
BALANCE SHEET DATA:
Cash and cash equivalents.......... $ 12.3 $ 7.5 $ 9.4 $ 143.6
Working capital.................... 2.5 3.7 2.0 136.2
Total assets....................... 311.0 340.4 472.1 610.1
Total debt......................... 53.0 89.0 12.0 150.0
Stockholders' equity............... 188.1 191.8 363.6 363.6
Total capitalization(11)........... 241.1 280.8 375.6 513.6
</TABLE>
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(1) Excluding 1995 nonrecurring transaction costs relating to the Plains merger
totaling $14.2 million ($13.2 million for the nine months ended September
30, 1995), net income (loss) for the year ended December 31, 1995 and the
nine months ended September 30, 1995 would be $9.5 million and $7.0
million, respectively, EBITDA would be $51.2 million and $36.5 million,
respectively, and cash flow from operations before changes in working
capital would be $47.6 million and $32.7 million, respectively. EBITDA and
cash flow from operations before changes in working capital are not
measures determined pursuant to generally accepted accounting principles
("GAAP") nor are they alternatives to GAAP income or cash flow provided by
operations. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations."
(2) Plains used the successful efforts method of accounting and adopted the
full cost method used by Barrett in the retroactively restated financial
statements. See Note 2 to the Consolidated Financial Statements.
(3) Interest expense is net of capitalized interest of $0, $0.1 million and
$0.4 million for the years ended December 31, 1993, 1994 and 1995,
respectively, and $0.3 million and $0, for the nine months ended September
30, 1995 and 1996, respectively. On a pro forma basis, assuming the sale of
the Notes and the application of a portion of the net proceeds therefrom to
repay $70 million under the bank credit facility at the beginning of each
period, interest expense would be $11.7 million for the year ended
December 31, 1995 and $8.8 million for the nine months ended September 30,
1996.
(4) EBITDA is defined as income before income taxes less interest income, plus
interest expense, plus depreciation, depletion and amortization expense.
EBITDA does not purport to reflect any measure of operations or cash flow.
(5) Represents the ratio of EBITDA to interest expense. On a pro forma basis,
assuming the sale of the Notes and the application of a portion of the net
proceeds therefrom to repay $70 million under the bank credit facility at
the beginning of each period, and excluding the nonrecurring 1995 merger
costs, EBITDA/Interest expense would be 4.2x for the year ended December
31, 1995 and 7.0x for the nine months ended September 30, 1996.
(6) For purposes of determining the ratio of earnings to fixed charges,
earnings are computed as net income (loss) before income taxes, plus fixed
charges. Fixed charges consist of interest expense, whether expensed or
capitalized, on all indebtedness plus amortization of debt issuance costs.
For the year ended December 31, 1995 and the nine months ended September
30, 1995, earnings were not sufficient to cover historical fixed charges
due to the incurrence of $14.2 million of nonrecurring merger costs ($13.2
million for the nine months ended September 30, 1995). On a pro forma
basis, assuming the sale of the Notes and the application of a portion of
the net proceeds therefrom to repay $70 million under the bank credit
facility at the beginning of each period, and excluding the nonrecurring
1995 merger costs, the ratio of earnings to fixed charges would be 1.7x for
the year ended December 31, 1995 and 3.7x for the nine months ended
September 30, 1996.
(7) At December 31, 1996, the Company's estimated proved reserves were 674.9
Bcf of natural gas and 23.2 MMBbls of oil and condensate, for a total of
814.3 Bcfe with an implied reserve life of 11.3 years based on 1996 total
production of 72.3 Bcfe. At December 31, 1996, the Present value of
estimated future net revenues on a non-escalated basis was $1,121.5 million
based on weighted average prices realized by the Company of $3.46 per Mcf
of natural gas and $24.12 per Bbl of oil at December 31, 1996.
(8) The Present value of estimated future net revenues on a non-escalated basis
is based on weighted average prices realized by the Company of $1.95 per
Mcf of natural gas and $11.05 per Bbl of oil at December 31, 1993, $1.67
per Mcf of natural gas and $14.43 per Bbl of oil at December 31, 1994 and
$1.77 per Mcf of natural gas and $17.35 per Bbl of oil at December 31,
1995.
(9) The Standardized measure of discounted net cash flows prepared by the
Company represents the Present value of estimated future net revenues after
income taxes discounted at 10%.
(10) As adjusted to give effect to the issuance and sale of the $150,000,000
principal amount of the Notes and the application of net proceeds
therefrom. See "Use of Proceeds" and "Management's Discussion and Analysis
of Financial Condition and Results of Operations."
(11) The sum of total debt and stockholders' equity.

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RISK FACTORS

In addition to the other information contained in this Prospectus, including
but not limited to information under the heading "Disclosure Regarding
Forward-Looking Statements," the following risk factors should be considered
when evaluating an investment in the Notes offered hereby:

VOLATILITY OF PRICES AND AVAILABILITY OF MARKETS

The Company's revenues, profitability and future rate of growth are
dependent in part upon prevailing prices for natural gas and oil, which can be
extremely volatile. There can be no assurance that current price levels can be
sustained. Prices also are affected by actions of state and local agencies,
the United States and foreign governments, and international cartels. These
external factors and the volatile nature of the energy markets make it
difficult to estimate future prices of natural gas and oil. Any substantial or
extended decline in the price of natural gas would have a material adverse
effect on the Company's financial condition and results of operations,
including reduced cash flow and borrowing capacity. All of these factors are
beyond the control of the Company. The marketability of the Company's
production depends in part upon the availability, proximity and capacity of
natural gas gathering systems, pipelines and processing facilities. Federal
and state regulation of natural gas and oil production and transportation,
general economic conditions, changes in supply and changes in demand all could
adversely affect the Company's ability to produce and market its natural gas
and oil. If market factors were to change dramatically, the financial impact
on the Company could be substantial. For the year ended December 31, 1995, the
Company's production and reserve base were approximately 82% and 87% natural
gas, respectively, on an energy equivalent basis. For the year ended December
31, 1996, the Company's production and reserve base were approximately 84% and
83% natural gas, respectively, on an energy equivalent basis. As a result, the
Company's earnings and cash flow are more sensitive to fluctuations in the
price of natural gas than to fluctuations in the price of oil. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and "Business and Properties--Natural Gas and Oil Marketing and
Trading."

The Company engages in hedging activities with respect to some of its
natural gas and oil production through a variety of financial arrangements
designed to protect against price declines, including swaps. To the extent
that Barrett engages in such activities, it may be prevented from realizing
the benefits of price increases above the levels of the hedges. Risks related
to hedging activities include the risk that counterparties to hedge
transactions will default on obligations to the Company. The Company maintains
a Risk Management Committee to oversee its production hedging and trading
activities. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and "Business and Properties--Natural Gas and Oil
Marketing and Trading."

The Company reports its operations using the full cost method of accounting
for natural gas and oil properties. Under full cost accounting rules, the net
capitalized costs of natural gas and oil properties may not exceed a "ceiling"
limit of the present value of estimated future net revenues from proved
reserves, discounted at 10%, plus the lower of cost or fair market value of
unproved properties. This rule requires calculating future revenues at
unescalated prices in effect as of the end of each fiscal quarter and requires
a write-down if the net capitalized costs of the natural gas and oil
properties exceed the ceiling limit, even if price declines are temporary. The
risk that the Company will be required to write-down the carrying value of its
natural gas and oil properties increases when natural gas and oil prices are
depressed or unusually volatile. A ceiling limitation write-down is a one-time
charge to earnings, which does not impact cash flow from operating activities.

OTHER INDUSTRY AND BUSINESS RISKS

The Company competes in the areas of natural gas and oil exploration,
production, development and transportation with other companies, many of which
may have substantially greater financial and other resources. The nature of
the natural gas and oil business also involves a variety of risks,

9
<PAGE>

including the risks of operating hazards such as fires, explosions, cratering,
blow-outs, encountering formations with abnormal pressures and, in horizontal
wellbores, the increased risk of mechanical failure and collapsed holes, and
damage or loss from adverse weather and seas, the occurrence of any of which
could result in losses to the Company. The operation of the Company's natural
gas processing plant and its natural gas gathering systems involves certain
risks, including explosions and environmental hazards caused by pipeline leaks
and ruptures. The effect of these hazards are increased with respect to the
Company's Gulf of Mexico activities due to the difficulty of containing leaks
and ruptures in offshore locations as well as hazards inherent in marine
operations, such as capsizing, grounding, collision and damage from weather or
sea conditions or unsound location. In accordance with customary industry
practices, the Company maintains insurance against some, but not all, of these
risks in amounts that management believes to be reasonable. The occurrence of
a significant event that is not fully insured could have a material adverse
effect on the Company's financial position. International operations are
subject to certain risks, including expropriation of assets, governmental
changes in applicable law, policies and contract terms, foreign government
approvals, political instability, guerilla activity, payment delays, and
currency exchange and repatriation losses.

The Company's revenues depend on its level of success in acquiring or
finding additional reserves. Certain areas in which the Company is engaged in,
or planning, significant exploration and development activities are
experiencing increased activity by other companies. This may result in
shortages of, or delays in the availability of, drilling rigs and other
equipment and increased costs as more users pursue available rigs. Except to
the extent that the Company acquires properties containing proved reserves or
conducts successful exploration and development activities, or both, the
proved reserves of the Company will decline as reserves are produced. There
can be no assurance that the Company's planned exploration and development
projects will result in additional reserves or that the Company will have
future success in drilling productive wells.

Natural gas trading activities involve a high degree of risk because of the
inherent uncertainties associated with the natural gas trading process. These
uncertainties include the lack of predictability in natural gas prices, risk
of non-performance by counterparties, market imperfections caused by regional
price differentials, possible lack of liquidity in the trading markets and
possible failure of physical delivery. Although the possibility of lower
natural gas prices tends to add risk to the Company's exploration and
development activities, it is the possibility of unexpected price volatility
that represents a primary risk for the Company's natural gas trading
activities. In addition, natural gas trading is highly competitive and the
Company competes with several other companies, many of which have more
experience, personnel and other resources available to them. However, the
Company does not believe that any one competitor is dominant in the industry.
See "Management's Discussion and Analysis of Financial Condition and Results
of Operations" and "Business and Properties--Natural Gas and Oil Marketing and
Trading."

ENGINEERS' ESTIMATES OF RESERVES AND FUTURE NET REVENUES

This Prospectus contains estimates of reserves and of future net revenues
which have been prepared by the Company and have been reviewed by independent
petroleum engineers. However, petroleum engineering is not an exact science
and involves estimates based on many variable and uncertain factors. Estimates
of reserves and of future net revenues prepared by different petroleum
engineers may vary substantially depending, in part, on the assumptions made
and may be subject to adjustment either up or down in the future. The actual
amounts of production, revenues, taxes, development expenditures, operating
expenses, and quantities of recoverable natural gas and oil reserves to be
encountered may vary substantially from the engineers' estimates. Estimates of
reserves also are extremely sensitive to the market prices for natural gas and
oil. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations" and "Business and Properties--Reserves."

10
<PAGE>

FUTURE CAPITAL NEEDS

The Indenture under which the Notes will be issued restricts the Company's
ability to grant liens. However, the Company will be able to incur substantial
amounts of additional debt. Existing and possible future leverage of the
Company poses risks to the holders of the Notes. These risks include higher
interest rates on floating rate debt and the risk that the Company might not
be able to generate sufficient cash to service or repay the Notes and its
other existing and possible future debt and to adequately fund its capital
expenditures. Existing and possible future leverage also may reduce the
ability of the Company to respond to changing business and economic
conditions, particularly the ability to make capital expenditures or to
withstand competitive pressures.

GOVERNMENT REGULATION AND ENVIRONMENTAL RISKS

The production and sale of natural gas and oil are subject to a variety of
federal, state and local government regulations that may be changed from time
to time in response to economic or political conditions. The regulations
concern, among other matters, the prevention of waste, the discharge of
materials into the environment, the conservation of natural gas and oil,
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 Company currently has a dispute
with the Internal Revenue Service. Although the Company believes it will
prevail in its position, there can be no assurance of a favorable outcome. See
Note 11 to the Consolidated Financial Statements. Many jurisdictions have at
various times imposed limitations on the production of natural gas and oil by
restricting the rate of flow for natural gas and oil wells below their actual
capacity to produce. In addition, many states have raised state taxes on
energy sources and additional increases may occur, although there can be no
certainty of the effect that increases in state energy taxes would have on
natural gas and oil prices. Although the Company believes it is in substantial
compliance with applicable environmental and other government laws and
regulations and to date such compliance has not had a material adverse effect
on the earnings or competitive position of the Company, there can be no
assurance that significant costs for compliance will not be incurred in the
future. Compliance with environmental laws, including the preparation of
environmental assessments and impact statements, can delay drilling activity,
thereby potentially reducing revenue and cash flow. See "Business and
Properties--Core Areas of Activity--Rocky Mountain Region--Wind River Project"
and "--Government Regulation of the Oil and Gas Industry."

11
<PAGE>

USE OF PROCEEDS

The net proceeds to the Company from the sale of the Notes are estimated to
be $146.1 million after deducting underwriting discounts and estimated
offering expenses payable by the Company. The Company intends to use these net
proceeds to repay the outstanding balance on its bank credit facility, which
had $85 million outstanding as of February 7, 1997 at an average interest rate
of 6.08%. The remainder of the net proceeds will be used to fund a portion of
the Company's planned exploration and development activities and for other
general corporate purposes, including possible acquisitions. See
"Capitalization," "Management's Discussion and Analysis of Financial Condition
and Results of Operations--Liquidity and Capital Resources," and "Business and
Properties--Core Areas of Activity."

The estimated amounts and uses set forth above indicate the Company's
intentions for use of the net proceeds from the sale of the Notes. The Company
may reallocate the proceeds or utilize the proceeds for other natural gas and
oil opportunities the Company deems to be in its best interests, due to a
change in circumstances concerning matters such as economic conditions,
availability of additional debt financing or the existence of a property
acquisition or development opportunity.

The excess of net proceeds from the Offering after paying the outstanding
balance of the Company's bank credit facility will be placed temporarily in
certificates of deposit, short-term obligations of the United States
government, or other money-market instruments that are rated investment grade
or its equivalent until used for the purposes described above.

To date, funds borrowed under the Company's bank credit facility, which
matures on October 31, 2000, have been used primarily for the Company's
natural gas and oil activities. Texas Commerce Bank is a lending agent under
the Company's bank credit facility and is affiliated with Chase Securities
Inc., one of the Underwriters of the Offering. See "Underwriting."

12
<PAGE>

CAPITALIZATION

The following table sets forth the capitalization of the Company as of
September 30, 1996 and as adjusted to give effect to the sale of the Notes as
of such date and the application of the net proceeds therefrom (assumed to be
approximately $146.1 million) as described under "Use of Proceeds." This table
should be read in conjunction with "Selected Consolidated Financial, Reserve
and Operating Data," "Use of Proceeds," "Management's Discussion and Analysis
of Financial Condition and Results of Operations" and the Consolidated
Financial Statements and notes thereto and other information included
elsewhere in this Prospectus.

<TABLE>
<CAPTION>
SEPTEMBER 30, 1996
--------------------
ACTUAL AS ADJUSTED
------- -----------
(IN MILLIONS)
<S> <C> <C>
Cash and cash equivalents................................. $ 9.4 $ 143.6
======= =======
Debt:
Bank credit facility(1)................................. $ 12.0 $ --
Notes offered hereby.................................... -- 150.0
------- -------
Total debt............................................ $ 12.0 $ 150.0
Stockholders' equity:
Common stock, $.01 par value: 35,000,000 shares autho-
rized, 31,319,193 issued and outstanding(2)............ 0.3 0.3
Additional paid-in capital.............................. 241.4 241.4
Retained earnings....................................... 122.8 122.8
Treasury stock, at cost................................. (1.0) (1.0)
------- -------
Total stockholders' equity............................ $ 363.6 $ 363.6
------- -------
Total capitalization.................................. $ 375.6 $ 513.6
======= =======
</TABLE>
- --------
(1) As of December 31, 1996, the outstanding balance under the Company's bank
credit facility was $70 million with interest at the average rate of 6.51%
per annum, and as of February 7, 1997 the outstanding balance was $85
million with interest at the average rate of 6.08% per annum. See "Use of
Proceeds," "Management's Discussion and Analysis of Financial Condition
and Results of Operations--Liquidity and Capital Resources" and Note 6 to
Consolidated Financial Statements for certain terms of the Company's bank
credit facility.

(2) Does not include 1,338,892 shares of common stock issuable upon exercise
of outstanding stock options.

13
<PAGE>

MANAGEMENT'S 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 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. The
merger was accounted for using the pooling of interests method. The pooling of
interests method combines previously reported results as though the
combination had 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 1993 through 1995 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
Company or Plains. The following discussion should be read in conjunction with
the Consolidated Financial Statements and Notes thereto presented elsewhere in
this Prospectus.

LIQUIDITY AND CAPITAL RESOURCES

Capital Expenditures. Capital expenditures were $156 million for the nine
months ended September 30, 1996 as compared to $47 million for the nine months
ended September 30, 1995. Full year 1996 capital expenditures were
approximately $235 million and the preliminary capital expenditure budget for
1997 is $278 million.

Capital Sources. The Company's drilling activities and its acquisitions have
increased its reserve base and its productive capacity and, therefore, its
potential cash flow. The Company anticipates that funds available from the
Company's operations, the Notes offered hereby and borrowings under the
Company's bank credit facility will be sufficient to fund the capital
expenditures described above. At September 30, 1996, the Company had cash and
short-term investments of $9.4 million, working capital of $2.0 million,
property and equipment of $422.2 million and total assets of $472.1 million.
Compared to December 31, 1995, cash and short-term investments increased $1.9
million, working capital decreased $1.7 million and property and equipment
increased $121.5 million. Total assets increased by $131.4 million, funded by
the Company's cash flow and the issuance of 5.4 million shares of the
Company's common stock in June 1996. As of December 31, 1996, as adjusted for
the sale of the Notes and repayment of the $70 million outstanding under the
bank credit facility, the Company's cash and cash equivalents will increase by
$76.1 million.

During the first nine months of 1996 and 1995, the Company generated
operating cash flow of $57.5 million and $19.5 million, respectively, before
working capital changes. After working capital changes, cash flow provided by
operations was $62.7 million and $16.5 million, respectively. Excluding merger
costs, cash flow from operations before working capital changes for the first
nine months of 1995 was $32.7 million ($29.7 million after working capital
changes).

As of September 30, 1996 and December 31, 1995, respectively, the
outstanding balance under the bank credit facility was $12 million and $89
million, as compared with $53 million at December 31, 1994. The Company's bank
credit facility is an unsecured $200 million facility entered into by the
Company in July 1995 with a consortium of six banks. The amount of borrowing
base under the bank credit facility at any time is determined by the lenders
with reference to the collateral value of the Company's proved reserves and
the Company's projected cash requirements. The current borrowing base is $205
million, based on the banks' review of June 30, 1996 proved reserve
information and the Company's projected cash requirements. Upon issuance of
the Notes, representing $150 million of senior indebtedness of the Company,
the borrowing base will be reduced to $75 million. Also upon the issuance of
the Notes, the banks will cancel the guarantees of the bank credit facility by
the Company's

14
<PAGE>

subsidiaries, and the Company will undertake to merge or consolidate certain
of its subsidiaries, including Plains Petroleum Operating Company, into or
with the Company. At the Company's election at the time of borrowing funds,
interest begins to accrue on those funds either at the London interbank
eurodollar rate (LIBOR) plus a spread ranging from 0.5% to 1.0% (depending on
the ratio of the Company's outstanding indebtedness to its borrowing base) or
at the U.S. prime rate of interest. The Company is required to pay interest on
a quarterly basis until the entire outstanding balance matures on October 31,
2000. As of December 31, 1996, the outstanding balance under the bank credit
facility was $70 million, which was accruing interest at an average rate of
6.51% per annum. As of February 7, 1997, the outstanding balance was $85
million with interest accruing at the average rate of 6.08% per annum.

From time to time the Company uses swaps to hedge the sales price of its
natural gas and oil. In a typical swap agreement, the Company and a
counterparty 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 at approximately the same
time as the physical transactions. The intent of hedging activities is to
reduce the volatility associated with the sales prices of the Company's
natural gas and oil production. Although hedging transactions associated with
the Company's production minimize the Company's exposure to reductions in
production revenue as a result of unfavorable price changes, these
transactions also limit the Company's ability to benefit from favorable price
changes. The Company maintains a Risk Management Committee to oversee its
production hedging and trading activities. See "Business and Properties--
Natural Gas and Oil Marketing and Trading."

RESULTS OF OPERATIONS

NINE MONTHS ENDED SEPTEMBER 30, 1996 AS COMPARED TO NINE MONTHS ENDED
SEPTEMBER 30, 1995

The following discussion of operating results is based on historical
consolidated financial information that has been restated to reflect the
merger of the Company and Plains on July 18, 1995 under the pooling of
interests method of accounting.

Net income for the nine months ended September 30, 1996 was $17.0 million
($.62 per share) compared with a net loss of $5.9 million ($.23 per share) for
the 1995 period. This increase is primarily due to increased natural gas and
oil production revenue, a 17% increase in average natural gas sales prices, a
17% increase in average oil sales prices, a $1.3 million increase in gross
profit from natural gas trading and the merger costs of $13.2 million that
were incurred in the first nine months of 1995.

Total revenues for the nine months ended September 30, 1996 were $136.1
million, an increase of 47% from $92.7 million for the same period in 1995.
This increase is attributable to higher production revenues and a 52% increase
in trading revenues.

15
<PAGE>

Production revenues for the nine months ended September 30, 1996 increased
45% from $70.5 million to $102.4 million. Production revenues and related
volumes and average prices during the periods presented were as follows:

<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
-----------------
1996 1995
-------- --------
<S> <C> <C>
Natural Gas Revenues (in millions)...................... $ 76.4 $ 50.1
Natural Gas Production (Bcf)............................ 44.1 33.9
Average Price per Mcf................................... $ 1.73 $ 1.48
Oil Revenues (in millions).............................. $ 26.0 $ 20.4
Oil Production (MBbls).................................. 1,397 1,288
Average Price per Barrel................................ $ 18.61 $ 15.84
</TABLE>

Natural gas revenues increased 53% during the nine months ended September
30, 1996 as compared with the same period in 1995, principally due to a 30%
increase in production volumes and a 17% increase in average natural gas
prices.

The 28% increase for the nine months ended September 30, 1996 in oil
revenues from the same period in 1995 is directly attributable to an 8%
increase in production volumes and a 17% increase in average oil prices.

For the nine months ended September 30, 1996, revenues from trading were
$30.5 million compared with $20.2 million for the same period in 1995. The
associated costs of trading increased to $28.4 million from $19.4 million due
to the increase in natural gas trading volumes. Gross profit from trading was
$2.1 million and $771,000 for the respective nine months ended September 30,
1996 and 1995.

To reduce its exposure to natural gas and oil price fluctuations, the
Company enters into hedging arrangements from time to time for both trading
and producing activities. During the nine months ended September 30, 1996, the
Company hedged approximately 21% of the Company's natural gas production at an
average price of $1.99 per Mcf.

For the fourth quarter of 1996, the Company hedged approximately 30% of the
Company's natural gas production at an average price of $2.05 per Mcf. As of
December 31, 1996, the Company held positions to hedge approximately 8.8 Bcf
of the Company's future natural gas production at an average price of $1.87
per Mcf. In addition, during January 1997 the Company hedged an aggregate of
25.6 Bcf of natural gas production from the Rocky Mountain Region for the
five-year period from March 1998 through February 2003 at an average price of
$1.75 per Mcf and on February 10, 1997 the Company hedged an aggregate of an
additional approximately 18.2 Bcf of natural gas production from the Rocky
Mountain Region for the same period at an average price of $1.735 per Mcf.

Production costs increased in the first nine months of 1996 compared to 1995
due to increases in sales and higher operating costs in the winter months in
the first quarter of 1996.

Depreciation, depletion and amortization increased to $31.9 million from
$23.6 million due to a 26% increase in gas and oil equivalent production.
During the 1996 and 1995 periods, depletion, depreciation and amortization was
$.58 and $.53 per Mcfe, respectively.

Interest expense for the nine months ended September 30, 1996 decreased from
$3.3 million in 1995 to $3.2 million in 1996. This decrease is attributable to
the repayment in June 1996 of the Company's debt under the bank credit
facility with proceeds from the June 1996 common stock offering.

The Company's largest source of operating income is from sales of its
natural gas and oil production. Therefore, the levels of the Company's
revenues and earnings are affected by prices at

16
<PAGE>

which natural gas and oil are being sold. This is particularly true with
respect to natural gas, which accounted for approximately 75% of the Company's
production revenue for the nine months ended September 30, 1996. As a result,
the Company's operating results for any prior period are not necessarily
indicative of future operating results because of the fluctuations in natural
gas and oil prices and the lack of predictability of those fluctuations as
well as changes in production levels.

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

During 1995, the Company incurred a net loss of $2.2 million ($0.09 per
share) compared to net income of $11.3 million ($0.46 per share) in 1994. The
1995 results include merger and reorganization costs of $14.2 million.
Excluding these merger costs, the Company's net income after taxes would have
been $9.5 million ($0.38 per share).

Revenues increased 17% from 1994 to $128.0 million, and operating expenses,
including $14.2 million of merger and reorganization costs, increased 38% to
$128.4 million. Oil and natural gas production revenue increased 23% 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% increase
in natural gas production to 47.7 Bcf (130.7 MMcf per day). Oil production
increased 32% to 1,702,000 barrels (4,660 barrels per day). Average natural
gas sales prices decreased 20% to $1.47 per Mcf, while average oil prices
increased 13% to $15.76 per barrel. Natural gas production accounted for 82%
of total production on an energy equivalent basis. The Hugoton Embayment and
Piceance Basin properties accounted for 37% and 14%, respectively, of total
natural gas production. The Powder River and Permian Basins accounted for 43%
and 32%, respectively, of total oil production. The decreased natural gas
sales price was due to an overall deterioration in natural gas markets during
most of the year.

Lease operating expenses of $34.5 million was $0.60 per Mcfe compared to
$0.69 per Mcfe in 1994. Depreciation, depletion and amortization increased
$10.7 million primarily due to production increases. During 1995,
depreciation, depletion and amortization on natural gas and oil production was
provided at an average rate of $0.55 per Mcfe compared to an average rate of
$0.52 per Mcfe in 1994.

The gross margin on trading activities was virtually unchanged from 1994 at
$943,000. Natural gas trading volumes increased 26% to 22.2 Bcf in 1995.

During 1995, the Company hedged 4.9 Bcf (22%) of its natural gas trading
volumes to lock in margins on specific transactions at a cost of $2.1 million.
In addition, the Company hedged 11.0 Bcf (23%) of natural 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 reduce
its exposure to price risks associated with commodities markets. Although
hedging transactions associated with its production minimize the Company's
exposure to reductions in production revenue as a result of unfavorable price
changes, these 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 natural
gas widened to historically high levels. Because the increase in the
commodities price was not accompanied by a similar increase in the market
price of the Company's natural 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
generally will not 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.

17
<PAGE>

General and administrative expenses of $13.4 million were 1% 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, because 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 to eliminate
duplicative costs in 1996. Interest expense increased significantly from $0.9
million 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 companies'
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. See "Underwriting."

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% of the Company's reserves and 82% 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 natural gas and oil to increase its
production. The lack of predictability of both production volumes and sales
prices may influence future operating results.

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

During 1994, the Company earned net income of $11.3 million ($0.46 per
share) compared to net income of $13.7 million ($0.55 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 ($0.37 per share).
The 1993 results include a tax benefit of $1.5 million from the value of the
tax loss carryover and an expense of $656,000 for the cumulative effect of
adopting Statement No. 106 of the Financial Accounting Standards Board to
recognize accumulated postretirement 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 3% from 1993 to $109.5 million, and operating expenses
increased 9% 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 $2.2 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 5% increase in gas
production was offset by a 6% decrease in the average natural gas sales price
and a 7% decline in the average oil sales price. Oil production was virtually
unchanged from 1993 to 1994. During 1994, the Company produced 91.2 MMcf of
natural gas per day and 3.5 MBbls of oil per day. Natural gas production
accounted for 81% of total production on an energy equivalent basis of 41.0
Bcfe. During 1994, the average natural gas sales price was $1.83 per Mcf
($1.94 in 1993) and the average oil sales price was $13.95 per barrel ($14.93
in 1993). The decreased natural gas and oil sales prices were due to an
overall market reduction in the commodity prices of the products.

Lease operating expenses of $28.2 million averaged $0.69 per Mcfe compared
with $0.77 per Mcfe in 1993. Depreciation, depletion and amortization
increased $2.6 million primarily due to production increases. During 1994,
depreciation, depletion and amortization was $0.52 per Mcfe compared to $0.48
per Mcfe in 1993.

18
<PAGE>

The gross margin on trading activities decreased to $924,000 from $1.3
million in 1993. Natural gas trading volumes increased 62% to 17.5 Bcf in
1994. The reduced results were due to a reduction of margins available for gas
trading activities.

General and administrative expenses of $13.3 million were 18% 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 increased general
and administrative expense was 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.

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

This Prospectus includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended (the "Securities Act"),
and Section 21E of the Securities Exchange Act of 1934, as amended (the
"Exchange Act"). All statements other than statements of historical facts
included in this Prospectus, including without limitation statements under
"Prospectus Summary," "Risk Factors," "Management's Discussion and Analysis of
Financial Condition and Results of Operations," and "Business and Properties,"
regarding the Company's financial position, reserve quantities and net present
values, business strategy, plans and objectives of management of the Company
for future operations and capital expenditures, are forward-looking
statements. Although the Company believes that the expectations reflected in
the forward-looking statements and the assumptions upon which such forward-
looking statements are based are reasonable, it can give no assurance that
such expectations and assumptions will prove to have been correct. Reserve
estimates are generally different from the quantities of oil and natural gas
that are ultimately recovered. Additional statements concerning important
factors that could cause actual results to differ materially from the
Company's expectations ("Cautionary Statements") are disclosed in the "Risk
Factors" section and elsewhere in this Prospectus. All written and oral
forward-looking statements attributable to the Company or persons acting on
its behalf subsequent to the date of this Prospectus are expressly qualified
in their entirety by the Cautionary Statements.

19
<PAGE>

BUSINESS AND PROPERTIES

OVERVIEW

The Company concentrates its activities in core areas in which it has
accumulated detailed geologic knowledge and developed significant management
expertise. The Company continues to build on its interests in the Piceance
Basin in northwestern Colorado, the Uinta Basin of northeastern Utah, the
Anadarko and Arkoma Basins in Oklahoma, the Wind River Basin in Wyoming and
the Gulf of Mexico. The Company also has significant interests in the Hugoton
Embayment in Kansas and Oklahoma, the Permian Basin in Texas and New Mexico
and the Powder River Basin in Wyoming. At December 31, 1996, these principal
areas of focus represented approximately 94% of the Company's estimated proved
reserves.

The Company continues to experience significant growth in its proved
reserves, production volumes, revenues and cash flow, particularly in the Wind
River, Piceance, Anadarko, Arkoma and Uinta Basins. The Company currently is
pursuing development projects in the Wind River, Piceance, Anadarko, Arkoma
and Uinta Basins, and exploration projects in the Wind River and Anadarko
Basins, the Gulf of Mexico and the Republic of Peru. The Company's average net
daily production increased to 198 MMcfe for the year ended December 31, 1996
from 159 MMcfe for the year ended December 31, 1996.

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

BUSINESS STRATEGY

SPECIALIZED GEOLOGIC EXPERTISE. Both the CEO and President of Barrett are
experienced, practicing geologists. They have established a team of geologists
and geophysicists with expertise in the Company's core areas of activity.
Prior to undertaking projects in new areas, the Company assembles specialized
geologic expertise to identify and evaluate drilling prospects.

ACTIVE DRILLING PROGRAM. Barrett maintains a high quality, balanced
portfolio of lower risk development projects complemented by higher potential
exploration prospects. The Company's

20
<PAGE>

preliminary 1997 capital expenditure budget is $278 million, approximately 75%
of which is allocated to drilling and production activities. This budget,
which is subject to revision based upon market conditions and other factors,
contemplates that the Company will participate in drilling approximately 290
gross wells in 1997 as compared with 196 gross wells drilled in 1996. The
Company expects to continue high levels of drilling activity after 1997.

ADVANCED TECHNOLOGY. The Company makes extensive use of advanced
technologies, including 3-D seismic and in-house analytical and processing
capabilities, to better define drilling prospects. The Company also uses
advanced production techniques, such as ASP technology, in its enhanced
recovery operations.

CONTINUING COST MANAGEMENT. The Company continually strives to reduce
expenses through implementation of cost control programs and active management
of its operations, personnel and administrative activities. Current cost
management initiatives include entering into multi-well and longer term
contracts with drilling companies and participating in alliances with oil
field service companies to obtain more favorable terms.

FINANCIAL STRENGTH. The Company is committed to maintaining financial
flexibility in order to pursue exploration and development activities and to
take advantage of other opportunities that may arise. Historically, the
Company has funded its growth primarily through the issuance of common stock,
including four public stock offerings, its 1995 stock-for-stock merger with
Plains and several recent acquisitions financed with common stock. The
issuance of the Notes adds ten-year fixed rate debt financing to the Company's
capital structure, which will improve Barrett's liquidity, diversify its
capital base and enhance the Company's ability to pursue its business
strategy.

SELECTIVE RESERVE AND LEASEHOLD ACQUISITIONS. From time to time the Company
seeks to augment activities in its core areas, establish operations in new
areas and build acreage positions for exploration prospects through selective
acquisitions. As a result of acquisitions completed during 1996, the Company
increased its working interests in the Piceance Basin, expanded its operations
in the Uinta Basin and substantially increased its leased acreage position in
the Gulf of Mexico.

RECENT DEVELOPMENTS

CAPITAL EXPENDITURES. The Company's preliminary 1997 capital expenditure
budget for natural gas and oil activities is $278 million. Total estimated
1997 expenditures are allocated approximately 41% to the Gulf of Mexico
Region, 25% to the Rocky Mountain Region, 19% to the Mid-Continent Region, 6%
to international activities and 9% to possible acquisitions. This budget is
subject to revision based upon market conditions and other factors. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and "--Core Areas of Activities."

OFFSHORE FEDERAL LEASE SALES. At the September 1996 Western Gulf of Mexico
Offshore Lease Sale, the Company significantly expanded its position in the
Gulf of Mexico. The MMS awarded the Company leases covering 17 blocks. The
Company has a 100% working interest in 14 of these blocks and a 50% working
interest in the three other blocks. The Company's net share of the bonus
payments for these leases was $34.4 million. As a result of these
transactions, Barrett holds interests in 46 lease blocks in the Gulf of Mexico
covering approximately 185,000 gross acres. See "--Core Areas of Activity--
Gulf of Mexico Region."

21
<PAGE>

UINTA BASIN ACQUISITIONS. In November 1996, the Company expanded its
operations in the Uinta Basin of northeastern Utah when it acquired producing
and non-producing natural gas and oil properties in the Altamont-Bluebell
Field. The effective date of the acquisition of a significant portion of these
properties is January 1, 1997. The purchase included 120 operated wells with
an average working interest of 80%, together with 100,000 gross and 72,000 net
acres of leasehold interests. The total purchase price was approximately $32
million, including approximately $14 million in cash, 50,000 shares of the
Company's common stock, and certain non-strategic producing properties owned
by the Company. In January 1997, the Company acquired additional interests in
the Altamont-Bluebell Field for an aggregate purchase price of $3.5 million in
cash. These interests consist of 16 non-operated wells with average working
interests of 42% together with approximately 10,000 gross and 4,600 net acres
of leasehold interests. See "--Core Areas of Activity--Rocky Mountain Region--
Uinta Basin."

PARTICIPATION IN MARANON BASIN, PERU. In late January 1997, the Company
entered into an agreement with industry partners that provided the Company
with a license covering approximately 2.0 million gross acres located in the
Maranon Basis of northeastern Peru. The Company and its partners intend to
acquire and analyze 200 to 250 miles of seismic data in preparation for
exploratory drilling to begin in late 1997 or early 1998. The Company's
participation, which is subject to approval of the government of Peru, is
intended to consist of a 45% working interest, subject to a cost commitment of
60% of the 1996 and 1997 seismic costs and 60% of the cost of up to three
exploratory wells. It is anticipated that the Company will be designated
operator for operations in this area in mid-1997. See "--Core Areas of
Activity--International Operations."

CORE AREAS OF ACTIVITY

[CORE AREAS OF ACTIVITY MAP APPEARS HERE]

<PAGE>

The following table sets forth certain information concerning these core
areas of activity:

<TABLE>
<CAPTION>
PRELIMINARY
AVERAGE DAILY 1997
ESTIMATED PROVED ESTIMATED PROVED PRODUCTION FOR CAPITAL
RESERVES AT RESERVES AT THREE MONTHS ENDED EXPENDITURE
BASIN OR FIELD DECEMBER 31, 1995 DECEMBER 31, 1996 SEPTEMBER 30, 1996 BUDGET
-------------- ----------------- ----------------- ------------------ -------------
(BCFE) (BCFE) (MMCFE) (IN MILLIONS)
<S> <C> <C> <C> <C>
Rocky Mountain Region
Wind River............ 88.1 95.8 45.9 $ 25
Piceance.............. 119.1 201.7 32.3 25
Powder River.......... 30.0 32.0 16.5 6
Green River........... 12.5 14.8 1.5 1
Uinta................. 4.2 92.2 6.2 12
Mid-Continent Region
Arkoma................ 27.4 26.7 12.6 18
Anadarko.............. 33.7 46.2 22.5 27
Hugoton Embayment..... 200.7 211.9 38.8 2
Permian............... 39.1 31.8 14.0 6
Gulf of Mexico Region... 8.7 23.8 4.5 114
International(1)........ -- -- -- 16
Other Natural Gas and
Oil Activities(2)...... 27.8 37.4 6.6 26
----- ----- ----- ----
Total............... 591.3 814.3 201.4 $278
===== ===== ===== ====
</TABLE>
- --------
(1) Consists of the Company's Republic of Peru project.
(2) Reserves primarily located in northeastern Colorado, the Paradox Basin
(Utah and Colorado) and Nevada. Also includes preliminary 1997 capital
budget of $25 million for possible acquisitions.

ROCKY MOUNTAIN REGION

WIND RIVER BASIN. In 1994, following its major natural gas discovery in the
Cave Gulch Field, the Company began a focused exploration program in the Wind
River Basin of Wyoming, particularly along the Owl Creek Thrust fault.

Cave Gulch Field. In August 1994, the Company drilled the Cave Gulch Federal
Unit #1 well and discovered a significant natural gas field in the Fort Union
and Lance Sandstones below the Owl Creek Thrust. The Company currently owns a
94% working interest in the Cave Gulch Federal Unit. Since August 1994, the
Company has acquired additional interests in the area and currently owns
working interests ranging from 5% to 100% in 16,011 gross leasehold acres,
constituting 9,590 net leasehold acres, in the Cave Gulch area. Combined daily
production for the Cave Gulch Field net to the Company's interest at September
30, 1996 was 42.9 MMcf of natural gas and 160 barrels of oil.

In February 1997, the Company reached total depth on the Cave Gulch #16 deep
test well, which was drilled to 19,106 feet to test the deeper Frontier,
Muddy, Lakota, Morrison and Sundance formations. The well encountered these
formations at least 1,100 feet structurally updip (high) to the productive
zones in four offset gas wells, three of which have produced from the Frontier
formation and the fourth of which has produced from the Muddy, Lakota,
Morrison and Sundance formations. The Company plans to run production casing
and begin testing the well in mid-March 1997. The Company owns an 85.2%
working interest in this well, subject to reduction to 84.9% after payout.

During 1996, the Company had planned to drill up to 10 wells in the Cave
Gulch Field. However, the Bureau of Land Management (the "BLM") determined
that an environmental impact statement ("EIS") in the greater Cave Gulch area
would be required to assess future development proposals from the Company and
other operators in the area. As a result, the Company drilled four wells in
1996, with the Cave Gulch #16 drilling at year-end. The BLM has indicated that
the EIS will be completed in August 1997, but there is no assurance that this
will be the case. No additional drilling activity in this area for 1997 has
been approved by the BLM, and the BLM has indicated that no drilling activity
will

23
<PAGE>

be approved prior to the completion of the EIS. The Company will, however, be
permitted to recomplete wells. In the event that the BLM allows drilling
activity in this area pending the completion of the EIS, the Company will
proceed accordingly.

Through December 31, 1996, the Company had drilled 14 wells in the Cave
Gulch area to test the Lance and Fort Union Sandstones. Five of these wells
are producing, two are shut in due to line pressures, four are shut in due to
limited pipeline capacity, two are being completed and one is waiting on
completion. The Company's natural gas production is currently constrained to a
production rate of approximately 39 MMcf per day due to pipeline take-away
capacity in the Cave Gulch area of operation and the Wind River Basin. Two
interstate pipelines serve the Cave Gulch area, and both have proposed
expansions to increase their take-away capacity. The Company is supporting
these expansion proposals with transportation volume commitments. Both
pipeline expansions are scheduled to be completed by mid-1997. In an effort to
increase production, the Company is in the process of starting up a temporary
gas conditioning facility that will allow the Company to remove liquids from
the portion of the gas that currently does not meet pipeline specifications
and to compress gas prior to entering one of the interstate pipelines. Once
fully operational, estimated to be in February 1997, the Company believes that
this temporary facility will be able to increase its natural gas production in
the Cave Gulch area to approximately 59 MMcf per day. See "--Natural Gas and
Oil Marketing and Trading."

Stone Cabin Project. In the second quarter of 1996, the Company acquired a
100% working interest in 9,754 acres in the Wallace Creek Unit and adjacent
land. This acreage, in the Company's Stone Cabin Project, is along the south
flank of the Wind River Basin. In July 1996, the Company began an exploration
and development program to target the Upper Cretaceous Muddy Sandstone and the
Raderville Sandstone of the Lower Cody Shale Formation. The Company has
drilled four wells in this program, two of which are producing. The Company is
testing the other two wells to determine if they are capable of commercial
production. The Company plans to drill up to nine wells in 1997 to test the
Muddy Formation. However, the BLM is imposing restrictions on winter drilling
activities and drilling is not expected to resume until April 1997.

Owl Creek Thrust. The Company continues to evaluate additional exploration
prospects in the Owl Creek Thrust and central Wind River Basin. The Company
has 82,406 gross and 76,681 net acres under lease in portions of the Owl Creek
Thrust and central Wind River Basin outside of the Cave Gulch area. In 1997,
the Company plans to drill three exploratory test wells along the Owl Creek
Thrust and one exploratory test well in the central portion of the Basin.

At December 31, 1995, the Wind River Basin represented 15% of the Company's
estimated proved reserves. At December 31, 1996, this Basin represented 12% of
the Company's estimated proved reserves, and for the year ended December 31,
1996, it represented 21% of the Company's total production. In 1997, 9% of
Barrett's preliminary capital expenditure budget is planned to be spent in the
Wind River Basin for development, leasehold acquisition, seismic surveys and
exploration, including participating in drilling up to 17 wells.

PICEANCE BASIN. 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. The Company's activities in the Piceance
Basin are conducted primarily in three fields: Parachute, Rulison and Grand
Valley.

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. Barrett drilled its first well in the
Piceance Basin in 1984. At present, the Company owns interests in 297 wells
and operates 285 wells in the Piceance Basin.

24
<PAGE>

In 1996, the Company completed the acquisition of working interests in the
Piceance Basin from some of the Company's former joint working interest owners
in this project, and the Company's average working interest in properties in
this area increased from approximately 29% to approximately 62%. The Company
paid an aggregate of $28.9 million cash and issued an aggregate of 585,661
shares of common stock to acquire these interests.

In February 1995, the Company received approval for 40-acre well density by
the Colorado Oil and Gas Conservation Commission (the "Colorado Commission")
with respect to 81 640-acre sections in the Parachute, Rulison and Grand
Valley Fields, and has commenced an active development drilling program on 40-
acre sites in the Rulison, Grand Valley and Parachute Fields. In November
1996, the Company requested and received approval from the Colorado Commission
for two four-well pilot drilling programs on 20-acre well density. These two
pilot programs are located in the Grand Valley and Rulison Fields and are
scheduled to be drilled in early 1997. The Company will evaluate the
engineering and geologic data resulting from these pilot programs and
determine whether to apply for approval for 20-acre well density on all or
selected acreage in the Piceance Basin in the future. There is no assurance
that the Colorado Commission will approve any additional requests for 20-acre
well density.

At December 31, 1995, the Piceance Basin represented 20% of the Company's
estimated proved reserves. At December 31, 1996, this Basin represented 25% of
the Company's estimated proved reserves, and for the year ended December 31,
1996, it represented 14% of the Company's total production. The Company
currently is continuously operating three drilling rigs in the Basin. In 1997,
the Company intends to spend 9% of its preliminary capital expenditure budget
in the Piceance Basin for development and exploration, including participating
in drilling up to 56 wells and 20 recompletions.

Grand Valley Gathering System. In 1985, the Company's wholly-owned
subsidiary, Bargath, Inc., 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. This gathering
system subsequently has been expanded to approximately 150 miles, and a 16-
inch, 27-mile pipeline has been added. Through three acquisitions in 1996, the
Company increased its ownership interest in this system to approximately 62%.
As of December 31, 1996, the Grand Valley Gathering System was connected to
220 producing natural gas wells in the Piceance Basin. The system now has the
flexibility to deliver natural gas to three interstate pipelines, which are
owned respectively by Questar Pipeline Company, Northwest Pipeline Corporation
and Colorado Interstate Gas Company, and one intrastate pipeline owned by
Public Service Company of Colorado and K N Energy, Inc. ("K N"). In December
1994, the Company completed the construction of a 90,000 MMBtu per day natural
gas processing plant to extract liquid hydrocarbons from the natural 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 90,000 MMBtu of natural gas per day.

POWDER RIVER BASIN. The Powder River Basin in Wyoming 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 approximately 40% of the Company's daily oil production. The
Company currently anticipates that additional activity will concentrate on
development drilling and enhanced recovery projects utilizing 3-D seismic
technology where appropriate.

The Company has initiated or is planning the use of ASP technology to
chemically enhance oil recovery in a number of fields. The Company also is
using 3-D seismic technology to identify development opportunities in this
area.

At December 31, 1995, the Powder River Basin represented 5% of the Company's
estimated proved reserves. At December 31, 1996, this Basin represented 4% of
the Company's estimated proved reserves, and for the year ended December 31,
1996, it represented 8% of the Company's total

25
<PAGE>

production. In 1997, the Company intends to spend 2% of its preliminary
capital expenditure budget for development, enhanced recovery projects
utilizing 3-D seismic technology, and exploration opportunities in the Powder
River Basin, including participating in drilling up to 15 wells.

GREEN RIVER BASIN/WYOMING OVERTHRUST. The Company owns leasehold interests
within the greater Green River Basin, primarily in the Moxa Arch, Rock Springs
Uplift and Wamsutter Arch areas, the West Side Canal Field, and in the Wyoming
Overthrust Trend. The Company participated in two wells in the Green River
Basin in 1996. At December 31, 1995, the Green River Basin represented 2% of
the Company's estimated proved reserves. At December 31, 1996, this Basin
represented 2% of the Company's estimated proved reserves, and for the year
ended December 31, 1996, it represented 2% of the Company's total production.
In 1997, the Company intends to spend approximately $626,000 for capital
expenditures in drilling up to six wells and recompleting three additional
wells in the Green River Basin.

UINTA BASIN. As an extension of its Piceance Basin operations, in 1995, the
Company entered the Uinta Basin of Duchesne and Uintah Counties, in
northeastern Utah. The Uinta Basin is separated from the Piceance Basin by the
Douglas Creek Arch.

Brundage Canyon Field. Beginning in December 1995, the Company made
acquisitions totaling $5.2 million in the Brundage Canyon Field. As a result
of these acquisitions and new drilling, the Company currently owns working
interests ranging from 47% to 100% in 32 producing wells, a gathering and
transmission system, and 40,000 gross acres, covering approximately 34,000 net
acres, all of which are on the Ute Indian Reservation. Wells in this Field
produce primarily from multiple sandstone reservoirs of the lower Green River
Formation at depths averaging 5,500 feet. As of December 31, 1996, these wells
produced approximately 640 barrels of black wax crude oil per day.

The Company plans extensive work in this Field during 1997, including a 15-
well program to develop infill and field extension locations, a 40-acre pilot
waterflood project, and recompletions and workovers of existing wells to test
the viability of shallower horizons for potential future development.

Altamont-Bluebell Project. The Altamont-Bluebell Field complex, which
includes the Cedar Rim area, covers a large portion of the northern Uinta
Basin. In 1996, the Company acquired through a number of transactions working
interests ranging from 25% to 100% in 159 producing wells, and approximately
126,000 gross and 91,000 net acres of leasehold interests. The largest of
these acquisitions was completed on November 1, 1996 when the Company acquired
producing and non-producing natural gas and oil properties in the Altamont-
Bluebell Field. The effective date of the acquisition of a significant portion
of these properties is January 1, 1997. The purchase included 120 operated
wells with an average working interest of 80%, together with approximately
100,000 gross and 72,000 net acres of leasehold interests. The total purchase
price for the November 1996 acquisition was approximately $32 million,
including approximately $14 million cash, 50,000 shares of the Company's
common stock, and certain non-strategic producing properties owned by the
Company. The Company's production in this area is predominantly from the
multiple sandstone reservoirs in the Wasatch Formation which are found at an
average depth of 12,000 feet. Also productive in the Field are the upper,
lower, and middle portions of the Green River Formation at depths of 5,000 to
7,000 feet.

In January 1997, the Company acquired additional interests in this Field for
$3.5 million. These interests consist of 16 non-operated wells with average
working interests of 42%, together with approximately 10,000 gross and 4,600
net acres of leasehold interests.

In 1997, the Company plans a 30 well recompletion/restimulation program and
the drilling of six development and extension wells in the Uinta Basin.
Expenditures for this activity in 1997 are expected to total $12 million, or
4% of the Company's preliminary capital expenditure budget. With this activity

26
<PAGE>

the Company plans to test the potential in the lower, middle, and upper Green
River Formation both from behind pipe in existing wells and in new infill
locations.

MID-CONTINENT REGION

ARKOMA BASIN. Due to the complex structure and overlapping nature of the
rock formations, the Company has been using and will continue to use 3-D
seismic surveys extensively in the Arkoma Basin in Oklahoma. In 1996, Barrett
participated in the drilling of 15 wells in five areas of the Arkoma Basin in
Oklahoma: South Panola 3-D area, Limestone Ridge area, Wilburton Field, the
Choctaw Thrust 3-D area, and Alderson area. At December 31, 1995, the Arkoma
Basin represented 5% of the Company's estimated proved reserves. At December
31, 1996, this Basin represented 3% of the Company's estimated proved
reserves, and for year ended December 31, 1996, it represented 7% of the
Company's total production.

In 1997, the Company intends to spend 7% of its preliminary capital
expenditure budget for drilling in the Arkoma Basin, including participating
in drilling up to 22 wells, together with land and seismic surveys.

ANADARKO BASIN. Since 1993, the Anadarko Basin in southwestern Oklahoma has
been one of the Company's most active drilling areas. In 1996, the Company
participated in the drilling of 58 wells with working interests ranging from
1.5% to 100% after payout. While staying active in the Strong City Red Fork
Play, the Company has become increasingly active in the Mountain Front Granite
Wash play and the Sentinel Field area. At December 31, 1995, the Anadarko
Basin represented 6% of the Company's estimated proved reserves. At December
31, 1996, this Basin represented 6% of the Company's estimated proved
reserves, and for the year ended December 31, 1996, it represented 11% of the
Company's total production.

The Company plans to spend 10% of its preliminary 1997 capital expenditure
budget in the Anadarko Basin for development and exploration drilling,
including participating in drilling up to 60 wells, together with leasehold
acquisitions and seismic surveys as currently planned.

HUGOTON EMBAYMENT. The largest single producing area for the Company is the
Hugoton Embayment, which is one of the largest natural gas producing areas in
the United States, located in southwest Kansas, the Oklahoma panhandle and the
Texas panhandle. The Company produces natural gas from three fields in the
Hugoton Embayment: the Hugoton, the Guymon-Hugoton and Panoma Fields. At
December 31, 1995, the Hugoton Embayment represented 34% of the Company's
estimated proved reserves. At December 31, 1996, this Basin represented 26% of
the Company's estimated proved reserves, and for the year ended December 31,
1996, it represented 21% of the Company's total production.

Hugoton and Guymon-Hugoton Fields. In the Hugoton and Guymon-Hugoton Fields,
the Company has working interests in 359 gross wells and operates 314 of them.
The Hugoton and the Guymon-Hugoton Fields produce from the Chase Formation.
Six wells were drilled in the Hugoton Field in 1996, three of which are on
production and the remaining three of which are expected to begin production
in February 1997.

Panoma Field. Panoma is the field designation for natural gas produced from
the Council Grove Formation, a formation beneath the Chase Formation. The
Council Grove Formation has similar reservoir rocks as the Chase Formation.
However, the productive limits are not as extensive. Presently, the Company
has a working interest in 55 gross Panoma wells and operates 51 of those
wells, including one well drilled in 1996 which was placed on production in
January 1997.

Natural Gas Sales Agreement. The majority of the Company's natural gas
production from the Hugoton and Panoma Fields is sold under a long-term
contract (life-of-field) to KN Gas Supply

27
<PAGE>

Services, Inc. ("KNGSS"). Among other things, this contract provides for
annual re-determination of the price the Company is to receive. In 1997, as in
1996, the price is calculated each month by using the average of four Mid-
Continent index prices less a variable amount ranging from $.11 per MMBtu for
an average index price less than $.75 to a maximum of $.20 for an average
index price of $2.26 or higher. The volume of natural gas for which the
Company receives payment is reduced by one percent of the volume as an in-kind
fuel charge for moving the natural gas.

Net Profit Agreements. The Company produces natural gas in the Guymon-
Hugoton Field and the nearby Camrick Field under a Dry Gas Agreement with
Chevron U.S.A. Inc. ("Chevron"). This agreement allows the Company to expend
funds for the operation of the properties (including the cost of drilling
wells) and to recoup the funds so expended from current production income.
Eighty percent of net operating income generated by the natural gas production
(after operational costs are recouped, including the cost of drilling and
equipping wells) is then paid to Chevron. At each of December 31, 1995 and
1996, the Company had interests in 56 wells subject to the terms of this
agreement. The Company also produces natural gas in the Hugoton Field under
various agreements similar to the Chevron agreement, except that net operating
income is allocated 15% to the Company and 85% to other parties. At December
31, 1996, the Company had interests in an aggregate of 49 Chase Formation
wells and eight Council Grove Formation wells under these other agreements.

The third party interests under all the net profit agreements are treated as
lease operating expenses by the Company. Additional or replacement wells
drilled on the properties would be operated under the same terms and
conditions as existing wells, and would result in the commencement of the
80/20 or 85/15 net operating income allocation after the cost of the new wells
is recovered.

Hugoton Gas Trust Agreement. Natural gas rights established in 1955 to
approximately 50,000 acres in Finney and Kearny Counties, Kansas were
transferred to Plains by K N on October 1, 1984 subject to a natural gas
payment of $0.06 per Mcf for natural gas produced from the acreage. Quarterly
payments are made by the Company to the Hugoton Gas Trust, a publicly held
trust created in 1955. Payments terminate when the estimated gross recoverable
natural gas reserves decline to 50 Bcf or less. As of December 31, 1995, the
gross proved natural gas reserves attributable to the leases burdened by this
agreement were estimated to be 176.4 Bcf. The natural gas payments are treated
as lease operating expenses by the Company. At December 31, 1996, the Company
had working interests in 196 wells that were subject to these payments. Any
additional natural gas wells drilled on this acreage also will be subject to
the $0.06 payment per Mcf of natural gas produced.

Barrett intends to spend $2 million of its preliminary 1997 capital
expenditure budget on the Hugoton Embayment for development drilling and
increased deliverability through compression, including participating in
drilling eight new wells.

PERMIAN BASIN. The Permian Basin in west Texas and southeast New Mexico is
primarily an oil province. As of December 31, 1996, the Company had an
interest in 224 gross wells (170 net wells) located in the Permian Basin,
which produce approximately 2,200 barrels of oil per day net to the Company's
interests. In 1996, Barrett participated in drilling 15 wells in the Permian
Basin. At December 31, 1995, the Permian Basin represented 7% of the Company's
estimated proved reserves. At December 31, 1996, this Basin represented 4% of
the Company's estimated proved reserves, and for the year ended December 31,
1996, it represented 7% of the Company's total production. Barrett intends to
spend 2% of its preliminary 1997 capital expenditure budget in the Permian
Basin, including participating in drilling up to 31 wells. If a pending down-
spacing request regarding the Spraberry Trend area is approved, which would
allow an optional well on each existing 80 acre well site, the Company intends
to drill approximately 15 additional infill wells in 1997.

28
<PAGE>

GULF OF MEXICO REGION

Beginning in the latter half of 1995 and continuing during 1996, the Company
established a new core area in the Gulf of Mexico offshore Louisiana and
Texas. The Company believes that this area has significant reserve potential
and is well suited to its exploration emphasis and geologic expertise. The
availability of extensive 3-D seismic coverage over most of the Outer
Continental Shelf ("OCS"), the frequency of lease sales and the turnover of
expiring leases also make the Gulf of Mexico an attractive area. In addition,
wells in the Gulf of Mexico typically produce at higher rates, which increases
cash flow, but have relatively shorter productive lives. This production
profile will complement the Company's long-lived, relatively lower
deliverability wells in the Rocky Mountain and Mid-Continent regions. Also,
Gulf of Mexico natural gas prices historically have been higher than prices in
other regions in which the Company operates.

Initially, the Company's Gulf of Mexico operations centered on developing
high quality prospects with established operators. At the April 1996 Central
Gulf of Mexico Outer Continental Shelf Lease Sale, the Company joined another
operator in acquiring nine blocks. The Company has a 25% working interest
through completion of production facilities and a 22% working interest
thereafter in each of these nine blocks. Separately, the Company joined with a
second operator with a 50% working interest, in acquiring one block. In
addition, the Company acquired a block in which it has a 100% interest. Bonus
payments net to the Company for these lease interests totaled $2.3 million.

The Company's efforts are now directed at internally developing an inventory
of high quality prospects for future drilling. This effort was significantly
advanced at the Western Gulf of Mexico Outer Continental Shelf Sale in
September 1996. The Company was high bidder on 19 blocks in water depths
ranging from 33 feet to 315 feet. The MMS awarded the Company leases covering
17 of these blocks. The Company has a 100% working interest in 14 of these
blocks and a 50% working interest in the three other blocks. The Company's net
share of the bonus payments for these leases was $34.4 million. The MMS
rejected the two remaining high bids submitted by the Company because the MMS
deemed these bids insufficient.

In 1996, the Company participated in 15 Gulf of Mexico wells, 12 of which
were successful. The preliminary 1997 Gulf of Mexico capital expenditure
budget is estimated at $114 million to drill 31 wells, acquire additional 3-D
seismic for future prospects, lease additional future prospects and to put
into production eight wells drilled in 1996. This amount represents 41% of the
Company's preliminary 1997 capital expenditure budget.

At December 31, 1995, the Gulf of Mexico represented 1% of the Company's
estimated proved reserves. At December 31, 1996, the Gulf of Mexico
represented 3% of the Company's estimated proved reserves, and for the year
ended December 31, 1996, it represented 3% of the Company's total production.

INTERNATIONAL OPERATIONS

With an industry partner, the Company obtained in November 1996 a license to
evaluate, explore and develop approximately 820,000 acres in the Maranon Basin
of eastern Peru. The Company currently has a 55% working interest in this
project and has the right to increase its working interest to 77.5%. Pursuant
to the license, the Republic of Peru receives a variable royalty payment on
production that is anticipated to average approximately 23%. In the initial
phase of the license, which is underway, the Company and its co-venturer will
be conducting seismic reprocessing and environmental and engineering
feasibility studies regarding the viability of developing the Bretana Field,
which was discovered in 1974 by another company. Gross costs of approximately
$1.3 million for this first phase are expected. Following those studies, it is
anticipated that an appraisal well will be drilled in the third quarter of
1997. The gross costs of drilling and testing this well are anticipated to be
approximately $4.5 million.

29
<PAGE>

In late January 1977, the Company entered into an agreement with industry
partners that provided the Company with a license covering approximately 2.0
million gross acres located in the Maranon Basin of northeastern Peru. The
Company and its partners intend to acquire and analyze 200 to 250 miles of
seismic data in preparation for exploratory drilling to begin in late 1997 or
early 1998. The Company's participation, which is subject to approval of the
government of Peru, is intended to consist of a 45% working interest, subject
to a cost commitment of 60% of the 1996 and 1997 seismic costs and 60% of the
cost of up to three exploratory wells. The Company estimates that its total
net cost for this participation in seismic acquisition and the drilling of
three exploratory wells will approximate $7.5 million in 1997 and $7.2 million
in 1998. It is anticipated that the Company will be designated operator for
operations in this area in mid-1997. Estimated capital expenditures for
international operations for 1997 constitute approximately 6% of the Company's
preliminary capital expenditure budget.

NATURAL GAS AND OIL MARKETING AND TRADING

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
natural gas from its properties in each of the Company's basins. These
contracts vary with respect to their specific provisions, including price,
quantity, and length of contract. As of December 31, 1996, less than 7% of the
Company's production was committed to natural gas sales contracts that had
fixed prices or price ceilings. With the exception of two contracts covering
approximately 8,100 MMBtu per day of natural gas production from the Piceance
Basin through 2011, none of the contracts provides for fixed prices or price
ceilings beyond October 1997. The Company believes that it has sufficient
production from its properties to meet the Company's delivery obligations
under its existing natural gas sales contracts.

The Company has entered into a series of firm transportation agreements with
various Rocky Mountain pipeline companies. At January 1, 1997, these
transportation arrangements had terms ranging from seven months to ten years.
These transportation agreements provide the Company the opportunity to
transport its Rocky Mountain natural gas production into the Mid-Continent
area. These agreements in total provide transportation of approximately 52% of
the Company's current daily Rocky Mountain production.

In addition to the agreements described above, the Company has entered into
transportation arrangements to support future expansions of Rocky Mountain
interstate pipelines. These expansions are designed to transport Rocky
Mountain natural gas production to the Mid-Continent area for sale. The
Company has committed to 5,000 MMBtu per day of pipeline capacity for terms
ranging from five years to 10 years. These expansions are subject to Federal
Energy Regulatory Commission ("FERC") approval and are scheduled to be
operational by the third quarter of 1997.

For each of 1996 and 1997, the Company renegotiated the pricing provisions
with KNGSS with respect to a majority of its Hugoton and Panoma Fields natural
gas production. The price is calculated on a monthly basis by using the
average of four Mid-Continent index prices less a variable amount ranging from
$.11 per MMBtu for an average index price less than $.75 to a maximum of $.20
for an average index price of $2.26 or higher. The volume of natural gas for
which the Company receives payment is reduced by one percent of the volume as
an in-kind fuel charge for moving the natural gas.

During the year ended December 31, 1996, there was one natural gas
purchaser, KNGSS, that accounted for approximately 11% 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.

30
<PAGE>

The Company has established a Risk Management Committee to oversee its
production hedging and trading activities. The Risk Management Committee
consists of the Chief Executive Officer, the President and Chief Operating
Officer, the Chief Financial Officer, and the Executive Vice President--
Operations. With respect to production hedge transactions, it is the policy of
the Company that the Risk Management Committee review and approve all such
transactions.

As a result of its natural gas trading activities, the Company may from time
to time have natural 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 Risk Management Committee review
significant trades or positions before they are committed to by trading
personnel. All fixed price trading activities are hedged to lock in margins.

As of December 31, 1996, the Company had entered into financial transactions
to hedge approximately 8.8 Bcf of natural gas production for the period from
January 1997 through October 1997. In January 1997, the Company entered into a
transaction to hedge an aggregate of 25.6 Bcf of natural gas production from
the Rocky Mountain Region for the five-year period from March 1998 through
February 2003. On February 10, 1997, the Company entered into a transaction to
hedge an aggregate of an additional approximately 18.2 Bcf of natural gas
production from the Rocky Mountain Region for the same five-year period.

For the year ended December 31, 1995, revenues from trading activities,
which includes the cost of natural gas purchased or sold for trading purposes,
were $28.6 million, which constituted 22% of the Company's consolidated
revenues and generated a gross margin of $943,000. For the nine months ended
September 30, 1996, revenues from trading activities were $30.5 million, which
constituted 22% of the Company's consolidated revenues and generated a gross
margin of $2.1 million. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations."

OIL AND CONDENSATE. Oil, including condensate production, is generally sold
from the leases at posted field prices, plus negotiated bonuses. Marketing
arrangements are made locally with various petroleum companies. The Company
sells its own oil production to numerous customers. No single customer's total
oil purchases represented more than 10% of total Company revenues in 1996. Oil
revenues totaled $26.0 million for the nine months ended September 30, 1996
and represented 19% of the Company's total revenues for that period. The
Company does not engage in oil trading activities.

PRODUCTION

The table below sets forth information with respect to the Company's net
interests in producing natural gas and oil properties for each of its last
three years and for the nine months ended September 30, 1996 and 1995,
respectively:

<TABLE>
<CAPTION>
NATURAL GAS AND OIL PRODUCTION
----------------------------------
NINE MONTHS
YEAR ENDED ENDED
DECEMBER 31, SEPTEMBER 30,
-------------------- -------------
1993 1994 1995 1995 1996
------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C>
Quantities Produced and Sold
Natural gas (Bcf).......................... 31.7 33.3 47.7 33.9 44.1
Oil and condensate (MMBbls)................ 1.3 1.3 1.7 1.3 1.4
Average Sales Price
Natural gas ($/Mcf)........................ $ 1.94 $ 1.83 $ 1.47 $ 1.48 $ 1.73
Oil and condensate ($/Bbl)................. 14.93 13.95 15.76 15.84 18.61
Average Production Costs/Mcfe............... $ 0.77 $ 0.69 $ 0.60 $ 0.61 $ 0.65
</TABLE>

<PAGE>

PRODUCTIVE WELLS AND DEVELOPED ACREAGE

The productive wells in which the Company owned a working interest as of
December 31, 1996 are described in the following table:

<TABLE>
<CAPTION>
PRODUCTIVE WELLS (1)
-------------------------
GAS WELLS OIL WELLS DEVELOPED ACREAGE
------------ ------------ -----------------
GROSS NET GROSS NET GROSS NET
----- ------ ----- ------ -----------------
<S> <C> <C> <C> <C> <C> <C>
Rocky Mountain Region
Wind River............. 462 23.24 0 0.00 5,115 3,411
Piceance............... 308 161.31 0 0.00 36,560 20,336
Powder River........... 39 3.25 335 80.74 42,848 26,319
Green River............ 45 22.64 3 1.80 22,055 7,038
Uinta.................. 1 .78 135 115.58 97,580 60,940
Mid-Continent Region
Arkoma................. 121 32.06 0 0.00 51,200 14,450
Anadarko............... 149 64.89 13 12.60 83,265 49,920
Hugoton Embayment...... 412 347.80 0 0.00 88,332 84,946
Permian................ 54 17.63 210 145.69 45,701 15,143
Gulf of Mexico Region... 21 5.86 3 1.00 34,765 9,255
Other................... 88 60.84 74 5.78 41,225 28,209
----- ------ --- ------ -------- --------
Total.................. 1,203 640.87 854 332.27 548,646 319,967
===== ====== === ====== ======== ========
</TABLE>
- --------
(1) Each well completed to more than one producing zone is counted as a single
well. The Company has royalty interests in certain wells that are not
included in this table.

DRILLING ACTIVITY

The following table summarizes the Company's natural gas and oil drilling
activities, all of which were located in the United States, during the last
three years:

<TABLE>
<CAPTION>
WELLS DRILLED
-----------------------------------
YEAR ENDED DECEMBER 31,
-----------------------------------
1994 1995 1996
----------- ----------- -----------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C>
Development
Natural gas............................... 100 36.51 88 39.03 94 46.24
Oil....................................... 19 12.62 22 11.68 43 30.48
Non-productive............................ 18 7.65 10 3.51 17 8.03
--- ----- --- ----- --- -----
Total................................... 137 56.78 120 54.22 154 84.75
=== ===== === ===== === =====
Exploratory
Natural gas............................... 1 0.50 0 0.00 8 4.05
Oil....................................... 5 .58 1 0.33 3 1.00
Non-productive............................ 8 1.84 8 2.65 6 3.66
--- ----- --- ----- --- -----
Total................................... 14 2.92 9 2.98 17 8.71
=== ===== === ===== === =====
</TABLE>

In addition, the Company was participating in 25 gross (10.82 net) wells,
which were in the process of being drilled, at December 31, 1996.

RESERVES

The table below sets forth the Company's estimated quantities of historical
proved reserves, all of which were located in the United States, and the
present values attributable to those reserves. These estimates were prepared
by the Company, with certain portions having been reviewed by Ryder Scott
Company, an independent reservoir engineer, and the other portions having been
reviewed or prepared by Netherland, Sewell & Associates, Inc., an independent
reservoir engineer. The estimates as of December 31, 1996 were reviewed solely
by Ryder Scott Company. The total proved net reserves estimated by the Company
were within 10% of those reviewed and estimated by the

32
<PAGE>

engineers; however, on a well by well basis, differences of greater than 10%
may exist. See "Risk Factors--Engineers' Estimates of Reserves and Future Net
Revenues."

<TABLE>
<CAPTION>
ESTIMATED PROVED RESERVES
------------------------------------------------
DECEMBER 31,
------------------------------------------------
1993 1994 1995 1996
----------- ----------- ----------- ------------
(DOLLARS IN MILLIONS EXCEPT SALES PRICE DATA)
<S> <C> <C> <C> <C>
Estimated Proved Reserves(1):
Natural gas (Bcf).......... 364.8 458.8 513.5 674.9
Oil and condensate
(MMBbls).................. 6.9 11.4 13.0 23.2
Total (Bcfe)............. 406.5 527.5 591.3 814.3
Proved developed reserves
(Bcfe)...................... 375.6 440.1 489.7 606.3
Natural gas price as of De-
cember 31 ($/Mcf)........... $ 1.95 $ 1.67 $ 1.77 $ 3.46
Oil price as of December 31
($/Bbl)..................... $ 11.05 $ 14.43 $ 17.35 $ 24.12
Present value of estimated
future net revenues
before future income taxes
discounted at 10%(2)...... $ 277.6 $ 322.7 $ 432.6 $ 1,121.5
Standardized measure of
discounted net cash
flows(3).................... $ 203.1 $ 242.6 $ 309.9 --
</TABLE>
- --------
(1) The Company's annual reserve reports were prepared by the Company. With
respect to the reserve estimates as of and prior to December 31, 1995,
certain portions of the reserve report were reviewed by Ryder Scott
Company, an independent reservoir engineer. The remaining portions of
these reports concerning the reserves that are held by the Company's
Plains subsidiary were reviewed or prepared by Netherland, Sewell &
Associates, Inc., an independent reservoir engineering firm that reviewed
Plains' reserve reports from 1988 through 1995.

(2) The Present value of estimated future net revenues on a non-escalated
basis is based on weighted average prices realized by the Company of $1.95
per Mcf of natural gas and $11.05 per Bbl of oil at December 31, 1993,
$1.67 per Mcf of natural gas and $14.43 per Bbl of oil at December 31,
1994, $1.77 per Mcf of natural gas and $17.35 per Bbl of oil at December
31, 1995 and $3.46 per Mcf of natural gas and $24.12 per Bbl of oil at
December 31, 1996.

(3) The Standardized measure of discounted net cash flows prepared by the
Company represents the Present value of estimated future net revenues
after income taxes discounted at 10%.

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

In general, the volume of production from natural gas and oil properties
owned by the Company declines as reserves are depleted. Except to the extent
the Company acquires additional properties

33
<PAGE>

containing proved reserves or conducts successful exploration and development
activities, or both, the proved reserves of the Company will decline as
reserves are produced. Volumes generated from future activities of the Company
are therefore highly dependent upon the level of success in acquiring or
finding additional reserves and the costs incurred in doing so.

Reference should be made to "Supplemental Gas and Oil Information" on pages
F-23 and F-24 following the Consolidated Financial Statements included in this
Prospectus for additional information pertaining to the Company's proved
natural gas and oil reserves as of the end of each of the last three fiscal
years. During the past year, the only report concerning the Company's
estimated proved reserves that was filed with a U.S. federal agency other than
the Commission was filed prior to the Company's merger with Plains, by Barrett
and Plains, respectively. This report was the Annual Survey of Domestic Oil
and Gas Reserves and was filed with the Energy Information Administration
("EIA") as required by law. Only minor differences of less than 5% in reserve
estimates, which were due to small variances in actual production versus year
end estimates, have occurred in certain classifications reported in this
Prospectus as compared to those in the EIA report.

UNDEVELOPED ACREAGE

The gross and net acres of undeveloped natural gas and oil leases held by
the Company as of December 31, 1996 are summarized in the following table.
"Undeveloped Acreage" includes leasehold interests that already may have been
classified as containing proved undeveloped reserves.

<TABLE>
<CAPTION>
UNDEVELOPED
ACREAGE(1)
-----------------
UNITED STATES
- ---------------------------------------------------------
GROSS NET
- --------------------------------------------------------- --------- -------
<S> <C> <C>
Colorado (Piceance and other basins)..................... 125,506 59,035
Oklahoma (Anadarko and Arkoma Basins).................... 75,429 65,706
Texas (Permian Basin).................................... 5,952 1,313
Utah (Uinta Basin)....................................... 57,168 44,346
Wyoming (Wind River, Greater Green River, Powder River
and other
basins)................................................. 228,257 157,244
Gulf of Mexico .......................................... 179,791 114,093
Other.................................................... 16,050 7,537
<CAPTION>
INTERNATIONAL
- ---------------------------------------------------------
<S> <C> <C>
Peru..................................................... 820,000 451,000
--------- -------
Total.................................................. 1,508,153 900,274
========= =======
</TABLE>
- --------
(1) Undeveloped acreage is leased acreage on which wells have not been drilled
or completed to a point that would permit the production of commercial
quantities of natural gas and oil regardless of whether such acreage
contains proved reserves. Of the aggregate of 1,508,153 gross and 900,274
net undeveloped acres, 165,896 gross and 75,250 net acres are held by
production from other leasehold acreage.

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

34
<PAGE>

<TABLE>
<CAPTION>
ACRES EXPIRING
-----------------
GROSS NET
--------- -------
<S> <C> <C>
Twelve Months Ending:
December 31, 1997........................................... 91,416 31,630
December 31, 1998........................................... 30,493 30,348
December 31, 1999........................................... 58,476 58,408
December 31, 2000 and later................................. 1,327,768 779,888
</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.

GOVERNMENT REGULATION OF THE OIL AND GAS INDUSTRY

GENERAL

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

Certain operations the Company conducts are on federal oil and gas leases,
which the MMS administers. The MMS issues such leases through competitive
bidding. These leases contain relatively standardized terms and require
compliance with detailed MMS regulations and orders pursuant to the Outer
Continental Shelf Lands Act ("OCSLA"), which are subject to change by the MMS.
For offshore operations, lessees must obtain MMS approval for exploration
plans and development and production plans prior to the commencement of such
operations. In addition to permits required from other agencies (such as the
Coast Guard, the Army Corps of Engineers and the Environmental Protection
Agency), lessees must obtain a permit from the MMS prior to the commencement
of drilling. The MMS has promulgated regulations requiring offshore production
facilities located on the OCS to meet stringent engineering and construction
specifications. The MMS proposed additional safety-related regulations
concerning the design and operating procedures for OCS production platforms
and pipelines. These proposed regulations were withdrawn pending further
discussions among interested federal agencies. The MMS also has issued
regulations restricting the flaring or venting of natural gas and liquid
hydrocarbons without prior authorization. Similarly, the MMS has promulgated
regulations governing the plugging and abandonment of wells located offshore
and the removal of all production facilities. To cover the various obligations
of lessees on the OCS, the MMS generally requires that lessees post
substantial bonds or other acceptable assurances that such obligations will be
met. The cost of such bonds or other surety can be substantial and there is no
assurance that bonds or other surety can be obtained in all cases. Under
certain circumstances, the MMS may require any Company operations on federal
leases to be suspended or terminated. Any such suspension or termination could
materially and adversely affect the Company's financial condition and
operations.

At the U.S. federal level, the FERC regulates interstate transportation of
natural gas under the Natural Gas Act and regulates the maximum selling prices
of certain categories of natural gas sold in "first sales" in interstate and
intrastate commerce under the Natural Gas Policy Act ("NGPA"). Effective
January 1, 1993, the Natural Gas Wellhead Decontrol Act deregulated natural
gas prices for all "first sales" of natural gas, which includes sales by
Barrett of its own production. As a result, all sales of the Company's natural
gas produced in the U.S. may be sold at market prices, unless otherwise
committed by contract. Congress could reenact price controls in the future.
See "--Natural Gas and Oil Marketing and Trading."

35
<PAGE>

The Company's natural gas sales are affected by regulation of intrastate and
interstate natural gas transportation. In an attempt to promote competition,
the FERC has issued a series of orders which have altered significantly the
marketing and transportation of natural gas. The effect of these orders has
been to enable the Company to market its natural gas production to purchasers
other than the interstate pipelines located in the vicinity of its producing
properties. The Company believes that these changes have generally improved
the Company's access to transportation and have enhanced the marketability of
its natural gas production. To date, Barrett has not experienced any material
adverse effect on natural gas marketing as a result of these FERC orders;
however, the Company cannot predict what new regulations may be adopted by the
FERC and other regulatory authorities, or what effect subsequent regulations
may have on its future natural gas marketing.

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

ENVIRONMENTAL MATTERS

The Company, as an owner or lessee and operator of natural gas and oil
properties, is subject to various federal, state and local laws and
regulations relating to discharge of materials into, and protection of, the
environment. These laws and regulations may, among other things, impose
liability and substantial penalties on the lessee under a natural gas and oil
lease for the cost of pollution clean-up resulting from operations, subject
the lessee to liability for pollution damages, require suspension or cessation
of operations in affected areas and impose restrictions on the injection of
liquid into subsurface aquifers that may contaminate groundwater. The Oil
Pollution Act of 1990, as recently amended by the Coast Guard Authorization
Act of 1996, requires operators of offshore facilities to provide financial
assurance in the amount of $35 million to cover potential environmental
cleanup and restoration costs. This amount is subject to upward regulatory
adjustment.

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

TITLE TO PROPERTIES

Title to properties is subject to royalty, overriding royalty, carried, net
profits, working and other similar interests and contractual arrangements
customary in the oil and gas industry, to liens for current taxes not yet due
and to other encumbrances. As is customary in the industry in the case of
undeveloped properties, little investigation of record title is made at the
time of acquisition (other than a preliminary review of local records). The
Company reviews information concerning federal and state offshore lease blocks
prior to acquisition. Drilling title opinions are always prepared before
commencement of drilling operations; however, as is customary in the industry,
the Company does not obtain drilling title opinions on offshore leases it has
received directly from the MMS.

EMPLOYEES AND OFFICES

The Company currently has 179 full time employees, including 12 officers
(five of whom are geologists and two of whom are petroleum engineers), 14
geologists, six geophysicists, 13 engineers,

36
<PAGE>

one environmental manager, 11 landmen, four district managers, one operations
superintendent, and administrative, clerical, accounting and field operations
personnel, none of whom is represented by organized labor unions.

The Company's executive offices are located at 1515 Arapahoe Street, Tower
3, Suite 1000, Denver, Colorado 80202, and its telephone number is (303) 572-
3900. In addition, the Company maintains regional offices in Tulsa, Oklahoma
and Houston, Texas.

MANAGEMENT

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

<TABLE>
<CAPTION>
DIRECTOR
AGE POSITION WITH THE COMPANY SINCE
--- ------------------------- --------
<S> <C> <C> <C>
William J. Barrett 68 Chief Executive Officer, Chairman of the 1983
(1)(2)(3).............. Board, and a Director
C. Robert Buford 63 1983
(4)(5)................. Director
Derrill Cody (4)(5)..... 58 Director 1995
James M. Fitzgibbons 62 1987
(4)(5)(6).............. Director
Hennie L.J.M. Gieskes 57 1985
(4)(5)................. Director
William W. Grant, III 64 1995
(4).................... Director
J. Frank Keller (1)..... 53 Chief Financial Officer, Executive Vice 1983
President, Secretary, and a Director
Paul M. Rady............ 43 President, Chief Operating Officer, and a 1994
Director
A. Ralph Reed........... 59 Executive Vice President--Operations and a 1990
Director
James T. Rodgers 62 1993
(4)(5)................. Director
Philippe S.E. Schreiber 56 1985
(4)(5)................. Director
Harry S. Welch (5)...... 73 Director 1995
Joseph P. Barrett (2)... 43 Vice President--Land --
Peter A. Dea............ 43 Senior Vice President--Exploration --
Clifford S. Foss, Jr.... 49 Vice President and General Manager--Gulf of --
Mexico Region
Bryan G. Hassler........ 37 Vice President--Marketing --
Robert W. Howard........ 42 Senior Vice President--Finance and --
Treasurer
Eugene A. Lang, Jr...... 43 Senior Vice President--General Counsel --
Donald H. Stevens....... 44 Vice President--Corporate Relations and --
Capital Markets
Maurice F. Storm........ 36 Vice President and General Manager--Mid- --
Continent Region
</TABLE>
- --------
(1) William J. Barrett and J. Frank Keller are brothers-in-law.
(2) Joseph P. Barrett is the son of William J. Barrett.
(3) William J. Barrett's retirement plans include remaining as Chairman of the
Board until January 1999 and remaining as Chief Executive Officer until
the Company's 1997 Annual Meeting of Stockholders.
(4) Member of the Audit Committee of the Board of Directors.
(5) Member of the Compensation Committee of the Board of Directors.
(6) James M. Fitzgibbons served as a director of the Company from July 1987
until October 1992. He was reelected to the Board of Directors in January
1994.

37
<PAGE>

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. 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's retirement
plans include remaining as Chairman of the Board until January 1999 and
remaining as Chief Executive Officer until the Company's 1997 Annual Meeting
of Stockholders.

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 3% 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.

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.

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.

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., a
Netherlands trading company engaged primarily in energy-related commodities.

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.

38
<PAGE>

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 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.

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.
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 ("Amoco"), the exploration and production subsidiary of
Amoco Corporation. While with Amoco, 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.

A. RALPH REED has been an Executive Vice President of the Company since
November 1989 and a director of the Company since September 1990. 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. From 1982 to 1986, Mr.
Reed was President and Chief Executive Officer of Cotton Petroleum
Corporation, a wholly owned exploration and production subsidiary of United
Energy Resources, Inc. Prior to joining Cotton Petroleum Corporation in 1980,
Mr. Reed was employed by Amoco from 1962, holding various positions including
Manager of International Production, Division Production Manager and Division
Engineer.

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. 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 advisor to Ural Petroleum Corporation, a privately held exploration and
production company operating exclusively in the former Soviet Union.

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.

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.

39
<PAGE>

JOSEPH P. BARRETT has been a Vice President since March 1995 and has been
with the Company in various positions in the Land Department since 1982.

PETER A. DEA has been Senior Vice President--Exploration of the Company
since June 1996. Mr. Dea served as Exploration Manager beginning August 1995.
Mr. Dea served as Chief Geologist from January 1995 to August 1995 and as
Senior Geologist from February 1994 to January 1995. Mr. Dea served as
President of Nautilus Oil and Gas Company in Denver, Colorado from 1992
through 1993. From 1982 until 1991, Mr. Dea served in various positions with
Exxon Company USA as a Geologist in the Production Department in Corpus
Christi, Texas and as a Senior Geologist and Supervisor in the Exploration
Department in Denver, Colorado. While with Exxon, Mr. Dea's areas of
responsibility included the Rocky Mountain Basins and South Texas Gulf Coast
and new ventures in the Special Trades Unit. Mr. Dea served as adjunct
Professor of Geology at Western State College, Gunnison, Colorado in the
spring semesters of 1980 and 1982.

CLIFFORD S. FOSS, JR. has been General Manager of the Gulf of Mexico Region
for the Company since January 1996 and Vice President-General Manager of the
Gulf of Mexico Region for the Company since June of 1996. Prior to joining the
Company, Mr. Foss served from January 1973 to 1996 in various positions with
Cockrell Oil Corporation as Geologist, District Geologist, Exploration Manager
and Vice President of Exploration and Exploitation. Mr. Foss's primary areas
of responsibility at Cockrell Oil Corporation included the Gulf Coast and Gulf
of Mexico. Prior to January 1973, Mr. Foss served as an exploration geologist
for Cities Services Oil Company in its Gulf of Mexico Division.

BRYAN G. HASSLER has been Vice-President--Marketing of the Company since
December 1996 and has been with the Company as Director of Marketing since
August 1994. Prior to joining the Company, Mr. Hassler held various positions
with Questar Corporation's exploration and production, pipeline and marketing
groups.

ROBERT W. HOWARD has been Senior Vice President of the Company since March
1992. 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.

EUGENE A. LANG, JR. has been Senior Vice President--General Counsel of the
Company since September 1995. Mr. Lang served as 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. From 1978 to 1984, he was an attorney for K N.

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.

MAURICE F. STORM has been Vice President and General Manager of the
Company's Mid-Continent Division since July 1996. From October 1991 to July
1996 Mr. Storm was retained by the Company as a consultant to develop drilling
opportunities in the Anadarko and Arkoma Basins. From September 1984 through
October 1991 Mr. Storm worked for other independent exploration and production
companies in various exploration geologist and management positions.

40
<PAGE>

BENEFICIAL OWNERS OF SECURITIES

The following table summarizes certain information as of January 28, 1997
with respect to the ownership by each director, 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 5% of the Common Stock:

<TABLE>
<CAPTION>
NUMBER OF SHARES
NAME OF BENEFICIAL OWNER BENEFICIALLY OWNED PERCENT OF CLASS
------------------------ ------------------ ----------------
<S> <C> <C>
William J. Barrett....................... 390,172(1) 1.2%
C. Robert Buford......................... 652,366(2) 2.1%
Derrill Cody............................. 12,560(3) *
James M. Fitzgibbons..................... 11,000(3) *
Hennie L.J.M. Gieskes.................... 898,714(3) 2.9%
William W. Grant, III.................... 25,650(3) *
J. Frank Keller.......................... 74,036(3) *
Eugene A. Lang, Jr....................... 49,852(3) *
Paul M. Rady............................. 78,122(3) *
A. Ralph Reed............................ 80,328(4) *
James T. Rodgers......................... 11,500(3) *
Philippe S.E. Schreiber.................. 19,507(3) *
Harry S. Welch........................... 19,300(3) *
All Directors and Executive Officers as a
Group (20 persons)...................... 2,410,993(5) 7.6%
Fidelity Management and Research
Corporation
82 Devonshire Street
Boston, MA 02109........................ 3,300,000(6) 10.5%
State Farm Mutual Automobile
Insurance Company and affiliates
One State Farm Plaza
Bloomington, IL 61710................... 2,278,233(6)(7) 7.3%
</TABLE>

- --------
* Less than 1% of the Common Stock outstanding.
(1) The number of shares indicated includes 36,292 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 62.9% of the
partnership interests, and 55,000 shares underlying options that currently
are exercisable or become exercisable within the next 60 days. Pursuant to
Rule 16a-1(a)(4) under the Exchange Act, Mr. Barrett disclaims ownership
of all but 144,723 shares held by the Barrett Family L.L.L.P., which
constitutes Mr. and Mrs. Barrett's proportionate share of the shares held
by the Barrett Family L.L.L.P.
(2) C. Robert Buford is considered a beneficial owner of the 598,210 shares of
which Zenith is the record owner. Mr. Buford owns approximately 89% of the
outstanding common stock of Zenith. The number of shares of the Company's
stock indicated for Mr. Buford also includes 10,000 shares that are owned
by Aguilla Corporation, which is owned by Mr. Buford's wife and adult
children. Mr. Buford disclaims beneficial ownership of the shares held by
Aguilla Corporation pursuant to Rule 16a-1(a)(4) under the Exchange Act.
The number of shares indicated also includes 10,500 shares underlying
options currently exercisable.

41
<PAGE>

(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, 12,300; James M. Fitzgibbons, 9,000;
Hennie L.J.M. Gieskes, 9,500; William W. Grant, III, 15,900; J. Frank
Keller, 32,300; Eugene A. Lang, Jr., 43,259; Paul M. Rady, 48,000; James
T. Rodgers, 11,500; Philippe S.E. Schreiber, 9,500; and Harry S. Welch,
16,700.
(4) The number of shares indicated includes 10,150 shares owned by Mary C.
Reed, Mr. Reed's wife and 45,048 shares underlying options that currently
are exercisable or that become exercisable within the next 60 days.
(5) The number of shares indicated includes the shares owned by Zenith that
are beneficially owned by Mr. Buford as described in note (2), the
aggregate of 318,507 shares underlying the options described in notes (1),
(2), (3) and (4), an aggregate of 25,086 shares owned by seven executive
officers not named in the above table, and an aggregate of 62,800 shares
underlying options that currently are exercisable or that are exercisable
within 60 days that are held by those seven executive officers.
(6) Based on information included in a Schedule 13G filed with the Commission
by the named stockholder and from information obtained from other sources.
(7) The number of shares indicated includes the shares owned by entities
affiliated with State Farm Mutual Automobile Insurance Company ("SFMAI").
Those entities and SFMAI may be deemed to constitute a "group" with regard
to the ownership of shares reported on a Schedule 13G under the Exchange
Act.

42
<PAGE>

DESCRIPTION OF NOTES

The Notes will be issued pursuant to an Indenture to be dated as of February
1, 1997 (the "Indenture") among the Company, and Bankers Trust Company, as
trustee (the "Trustee"), a copy of the form of which is filed as an exhibit to
the Registration Statement of which this Prospectus is a part. The following
summaries of certain provisions of the Notes and the Indenture do not purport
to be complete and are subject to, and are qualified in their entirety by
reference to, the Notes and the Indenture, including the definitions therein
of certain capitalized terms used but not defined herein.

GENERAL

Each Note will mature on February 1, 2007 and will bear interest at the rate
per annum stated on the cover page hereof from February 1, 1997 payable
semiannually on February 1 and August 1 of each year, commencing August 1,
1997, to the person in whose name the Note is registered at the close of
business on the January 15 or July 15 preceding such interest payment date.
Interest will be computed on the basis of a 360-day year of twelve 30-day
months. Principal and interest will be payable at the offices of the Trustee
and the Paying Agent. In addition, in the event the Notes do not remain in
book-entry form, at the option of the Company payment of interest will be made
by check mailed to the address of the person entitled thereto as it appears in
the register of the Notes (the "Note Register") maintained by the Registrar.
The aggregate principal amount of the Notes that may be issued will be limited
to $150,000,000. The Notes will be transferable and exchangeable at the office
of the Registrar and any co-registrar and will be issued in fully registered
form, without coupons, in denominations of $1,000 and any whole multiple
thereof. The Company may require payment of a sum sufficient to cover any tax
or other governmental charge payable in connection with certain transfers and
exchanges.

The Notes will be senior unsecured obligations of the Company and will rank
pari passu in right of payment with the Company's obligations under all
existing and future senior unsecured indebtedness of the Company (including
the bank credit facility) and senior in right of payment to all existing and
future indebtedness of the Company that is, by its terms, expressly
subordinated to the Notes.

OPTIONAL REDEMPTION

The Notes will be redeemable, at the option of the Company, at any time in
whole or from time to time in part, upon not less than 30 and not more than 60
days' notice mailed to each holder of Notes to be redeemed at the holder's
address appearing in the Note Register, on any date prior to maturity at a
price equal to 100% of the principal amount thereof plus accrued interest to
the Redemption Date (subject to the right of holders of record on the relevant
record date to receive interest due on an interest payment date that is on or
prior to the Redemption Date) plus a Make-Whole Premium, if any (the
"Redemption Price"). In no event will the Redemption Price ever be less than
100% of the principal amount of the Notes plus accrued interest to the
Redemption Date.

The amount of the Make-Whole Premium with respect to any Note (or portion
thereof) to be redeemed will be equal to the excess, if any, of:

(i) the sum of the present values, calculated as of the Redemption Date, of:

A. each interest payment that, but for such redemption, would have been
payable on the Note (or portion thereof) being redeemed on each
Interest Payment Date occurring after the Redemption Date (excluding
any accrued interest for the period prior to the Redemption Date); and
B. the principal amount that, but for such redemption, would have been
payable at the final maturity of the Note (or portion thereof) being
redeemed;

over

(ii)the principal amount of the Note (or portion thereof) being redeemed.

43
<PAGE>

The present values of interest and principal payments referred to in clause
(i) above will be determined in accordance with generally accepted principles
of financial analysis. Such present values will be calculated by discounting
the amount of each payment of interest or principal from the date that each
such payment would have been payable, but for the redemption, to the
Redemption Date at a discount rate equal to the Treasury Yield (as defined
below) plus 25 basis points.

The Make-Whole Premium will be calculated by an independent investment
banking institution of national standing appointed by the Company; provided,
that if the Company fails to make such appointment at least 45 business days
prior to the Redemption Date, or if the institution so appointed is unwilling
or unable to make such calculation, such calculation will be made by Goldman,
Sachs & Co. or, if such firm is unwilling or unable to make such calculation,
by an independent investment banking institution of national standing
appointed by the Trustee (in any such case, an "Independent Investment
Banker").

For purposes of determining the Make-Whole Premium, "Treasury Yield" means a
rate of interest per annum equal to the weekly average yield to maturity of
United States Treasury Notes that have a constant maturity that corresponds to
the remaining term to maturity of the Notes, calculated to the nearest 1/12th
of a year (the "Remaining Term"). The Treasury Yield will be determined as of
the third business day immediately preceding the applicable Redemption Date.

The weekly average yields of United States Treasury Notes will be determined
by reference to the most recent statistical release published by the Federal
Reserve Bank of New York and designated "H.15(519) Selected Interest Rates" or
any successor release (the "H.15 Statistical Release"). If the H.15
Statistical Release sets forth a weekly average yield for United States
Treasury Notes having a constant maturity that is the same as the Remaining
Term, then the Treasury Yield will be equal to such weekly average yield. In
all other cases, the Treasury Yield will be calculated by interpolation, on a
straight-line basis, between the weekly average yields on the United States
Treasury Notes that have a constant maturity closest to and greater than the
Remaining Term and the United States Treasury Notes that have a constant
maturity closest to and less than the Remaining Term (in each case as set
forth in the H.15 Statistical Release). Any weekly average yields so
calculated by interpolation will be rounded to the nearest 1/100th of 1%, with
any figure of 1/200% or above being rounded upward. If weekly average yields
for United States Treasury Notes are not available in the H.15 Statistical
Release or otherwise, then the Treasury Yield will be calculated by
interpolation of comparable rates selected by the Independent Investment
Banker.

If less than all of the Notes are to be redeemed, the Trustee will select
the Notes to be redeemed by such method as the Trustee shall deem fair and
appropriate. The Trustee may select for redemption Notes and portions of Notes
in amounts of $1,000 or whole multiples of $1,000.

The Notes will not be entitled to the benefit of any sinking fund or other
mandatory redemption provisions.

CERTAIN COVENANTS

LIMITATION ON LIENS. Nothing in the Indenture or the Notes will in any way
limit the amount of indebtedness or securities (other than the Notes) that the
Company or any of its Subsidiaries may incur or issue. The Indenture will
provide that the Company will not, and will not permit any Restricted
Subsidiary to, issue, assume or guarantee any Indebtedness for borrowed money
secured by any Lien on any property or asset now owned or hereafter acquired
by the Company or such Restricted Subsidiary without making effective
provision whereby any and all Notes then or thereafter outstanding will be
secured by a Lien equally and ratably with any and all other obligations
thereby secured for so long as any such obligations shall be so secured.

44
<PAGE>

The foregoing restriction will not, however, apply to:

(a) Liens existing on the date on which the Notes are originally issued
or provided for under the terms of agreements existing on such date;

(b) Liens on property securing (i) all or any portion of the cost of
exploration, drilling or development of such property, (ii) all or any
portion of the cost of acquiring, constructing, altering, improving or
repairing any property or assets, real or personal, or improvements used or
to be used in connection with such property or (iii) Indebtedness incurred
by the Company or any Restricted Subsidiary to provide funds for the
activities set forth in clauses (i) and (ii) above;

(d) Liens on property existing at the time of acquisition of such
property by the Company or a Subsidiary or Liens on the property of any
corporation or other entity existing at the time such corporation or other
entity becomes a Restricted Subsidiary of the Company or is merged with the
Company in compliance with the Indenture and in either case not incurred as
a result of (or in connection with or in anticipation of) the acquisition
of such property or such corporation or other entity becoming a Restricted
Subsidiary of the Company or being merged with the Company, provided that
such Liens do not extend to or cover any property or assets of the Company
or any of its Restricted Subsidiaries other than the property so acquired;

(e) Liens on any property securing (i) Indebtedness incurred in
connection with the construction, installation or financing of pollution
control or abatement facilities or other forms of industrial revenue bond
financing or (ii) Indebtedness issued or guaranteed by the United States or
any State thereof or any department, agency or instrumentality of either;

(f) any Lien extending, renewing or replacing (or successive extensions,
renewals or replacements of) any Lien of any type permitted under clauses
(a) through (e) above, provided that such Lien extends to or covers only
the property that is subject to the Lien being extended, renewed or
replaced;

(g) certain Liens arising in the ordinary course of business of the
Company and the Restricted Subsidiaries;

(h) any Lien resulting from the deposit of moneys or evidences of
indebtedness in trust for the purpose of defeasing Indebtedness of the
Company or any Subsidiary; or

(i) Liens (exclusive of any Lien of any type otherwise permitted under
clauses (a) through (h) above) securing Indebtedness of the Company or any
Restricted Subsidiary in an aggregate principal amount which, together with
the aggregate amount of Attributable Indebtedness deemed to be outstanding
in respect of all Sale/Leaseback Transactions entered into pursuant to
clause (a) of the covenant described under "Limitation on Sale/Leaseback
Transactions" below (exclusive of any such Sale/Leaseback Transactions
otherwise permitted under clauses (a) through (h) above), does not at the
time such Indebtedness is incurred exceed 5% of the Consolidated Net
Tangible Assets of the Company (as shown in the most recent audited
consolidated balance sheet of the Company and its Subsidiaries).

The following types of transactions will not be prohibited or otherwise
limited by the foregoing covenant: (i) the sale, granting of Liens with
respect to, or other transfer of, crude oil, natural gas or other petroleum
hydrocarbons in place for a period of time until, or in an amount such that,
the transferee will realize therefrom a specified amount (however determined)
of money or of such crude oil, natural gas or other petroleum hydrocarbons;
(ii) the sale or other transfer of any other interest in property of the
character commonly referred to as a production payment, overriding royalty,
forward sale or similar interest; (iii) the entering into of Currency Hedge
Obligations, Interest Rate Hedging Agreements or Oil and Gas Hedging Contracts
although Liens securing any Indebtedness for borrowed money that is the
subject of any such obligation shall not be permitted hereby unless permitted
under

45
<PAGE>

clauses (a) through (i) above; and (iv) the granting of Liens required by any
contract or statute in order to permit the Company or any Restricted
Subsidiary to perform any contract or subcontract made by it with or at the
request of the United States or any State thereof or any department, agency or
instrumentality of either, or to secure partial, progress, advance or other
payments to the Company or any Restricted Subsidiary by such governmental unit
pursuant to the provisions of any contract or statute.

LIMITATION ON SALE/LEASEBACK TRANSACTIONS. The Indenture will provide that
the Company will not, and will not permit any Restricted Subsidiary to, enter
into any Sale/Leaseback Transaction with any person (other than the Company or
a Restricted Subsidiary) unless:

(a) the Company or such Restricted Subsidiary would be entitled to incur
Indebtedness, in a principal amount equal to the Attributable Indebtedness
with respect to such Sale/Leaseback Transaction, secured by a Lien on the
property subject to such Sale/Leaseback Transaction pursuant to the
covenant described under "Limitation on Liens" above without equally and
ratably securing the Notes pursuant to such covenant;

(b) after the date on which the Notes are originally issued and within a
period commencing six months prior to the consummation of such
Sale/Leaseback Transaction and ending six months after the consummation
thereof, the Company or such Restricted Subsidiary shall have expended for
property used or to be used in the ordinary course of business of the
Company and the Restricted Subsidiaries (including amounts expended for the
exploration, drilling or development thereof, and for additions,
alterations, repairs and improvements thereto) an amount equal to all or a
portion of the net proceeds of such Sale/Leaseback Transaction and the
Company shall have elected to designate such amount as a credit against
such Sale/Leaseback Transaction (with any such amount not being so
designated to be applied as set forth in clause (c) below); or

(c) the Company, during the 12-month period after the effective date of
such Sale/Leaseback Transaction, shall have applied to the voluntary
defeasance or retirement of Notes or any Pari Passu Indebtedness an amount
equal to the greater of the net proceeds of the sale or transfer of the
property leased in such Sale/Leaseback Transaction and the fair value, as
determined by the Board of Directors of the Company, of such property at
the time of entering into such Sale/Leaseback Transaction (in either case
adjusted to reflect the remaining term of the lease and any amount expended
by the Company as set forth in clause (b) above), less an amount equal to
the principal amount of Notes and Pari Passu Indebtedness voluntarily
defeased or retired by the Company within such 12-month period and not
designated as a credit against any other Sale/ Leaseback Transaction
entered into by the Company or any Restricted Subsidiary during such
period.

SUBSIDIARY GUARANTORS. Upon issuance, the Notes will not be guaranteed by
any Subsidiary of the Company. The Indenture will provide that if any
Subsidiary of the Company guarantees any Funded Indebtedness of the Company at
any time in the future, then the Company will cause the Notes to be equally
and ratably guaranteed by such Subsidiary.

LIMITATIONS ON MERGERS AND CONSOLIDATIONS

The Indenture will provide that the Company will not consolidate or merge
with or into any Person, or sell, lease, convey or otherwise dispose of all or
substantially all of its assets, or assign any of its obligations under the
Indenture or under the Notes, to any Person, unless: (i) the Person formed by
or surviving such consolidation or merger (if other than the Company), or to
which such sale, lease, conveyance or other disposition or assignment shall be
made (collectively, the "Successor"), is a corporation organized and existing
under the laws of the United States or any State thereof or the District of
Columbia and the Successor assumes by supplemental indenture in a form
satisfactory to the Trustee all of the obligations of the Company under the
Indenture and under the Notes; and (ii) immediately after giving effect to
such transaction, no Default or Event of Default shall have occurred and be
continuing.

46
<PAGE>

CERTAIN DEFINITIONS

The following is a summary of certain defined terms to be used in the
Indenture. Reference is made to the Indenture for the full definition of all
such terms and for the definitions of other capitalized terms used herein and
not defined below.

"Attributable Indebtedness", when used with respect to any Sale/Leaseback
Transaction, means, as at the time of determination, the present value
(discounted at a rate equivalent to the Company's then current weighted
average cost of funds for borrowed money as at the time of determination,
compounded on a semi-annual basis) of the total obligations of the lessee for
rental payments during the remaining term of the lease included in such
Sale/Leaseback Transaction (including any period for which such lease can be
extended).

"Capitalized Lease Obligation" of any Person means any obligation of such
Person to pay rent or other amounts under a lease of property, real or
personal, that is required to be capitalized for financial reporting purposes
in accordance with generally accepted accounting principles; and the amount of
such obligation shall be the capitalized amount thereof determined in
accordance with generally accepted accounting principles.

"Consolidated Net Tangible Assets" means, for the Company and its Restricted
Subsidiaries on a consolidated basis determined in accordance with generally
accepted accounting principles, the aggregate amounts of assets (less
depreciation and valuation reserves and other reserves and items deductible
from gross book value of specific asset accounts under generally accepted
accounting principles) that would be included on a balance sheet after
deducting therefrom (a) all liability items except deferred income taxes,
commercial paper, short term bank indebtedness, Funded Indebtedness, other
long-term liabilities and shareholders' equity and (b) all goodwill, trade
names, trademarks, patents, unamortized debt discount and expense and other
like intangibles.

"Currency Hedge Obligations" means, at any time as to any Person, the
obligations of such Person at such time that were incurred in the ordinary
course of business pursuant to any foreign currency exchange agreement, option
or futures contract or other similar agreement or arrangement designed to
protect against or manage such Person's or any of its Subsidiaries' exposure
to fluctuations in foreign currency exchange rates.

"Funded Indebtedness" means all Indebtedness (including Indebtedness
incurred under any revolving credit, letter of credit or working capital
facility) that matures by its terms, or that is renewable at the option of any
obligor thereon to a date, more than one year after the date on which such
Indebtedness is originally incurred.

"Indebtedness" of any Person at any date means, without duplication, (i) all
indebtedness of such Person for borrowed money (whether or not the recourse of
the lender is to the whole of the assets of such Person or only to a portion
thereof), (ii) all obligations of such Person evidenced by bonds, debentures,
notes or other similar instruments, (iii) all obligations of such Person in
respect of letters of credit or other similar instruments (or reimbursement
obligations with respect thereto), other than standby letters of credit
incurred by such Person in the ordinary course of business, (iv) all
obligations of such Person to pay the deferred and unpaid purchase price of
property or services, except trade payables and accrued expenses incurred in
the ordinary course of business, (v) all Capitalized Lease Obligations of such
Person, (vi) all Indebtedness of others secured by a Lien on any asset of such
Person, whether or not such Indebtedness is assumed by such Person, (vii) all
Indebtedness of others guaranteed by such Person to the extent of such
guarantee and (viii) all obligations of such Person in respect of Currency
Hedge Obligations, Interest Rate Hedging Agreements and Oil and Gas Hedging
Contracts.

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<PAGE>

"Interest Rate Hedging Agreements" means, with respect to any Person, the
obligations of such Person under (i) interest rate swap agreements, interest
rate cap agreements and interest rate collar agreements and (ii) other
agreements or arrangements designed to protect such Person or any of its
Subsidiaries against fluctuations in interest rates.

"Lien" means, with respect to any asset, any mortgage, lien, pledge, charge,
security interest or encumbrance of any kind in respect of such asset
(including, without limitation, any production payment, advance payment or
similar arrangement with respect to minerals in place), whether or not filed,
recorded or otherwise perfected under applicable law. For the purposes of the
Indenture, the Company or any Restricted Subsidiary shall be deemed to own
subject to a Lien any asset which it has acquired or holds subject to the
interest of a vendor or lessor under any conditional sale agreement,
Capitalized Lease Obligation (other than any Capitalized Lease Obligation
relating to any building, structure, equipment or other property used or to be
used in the ordinary course of business of the Company and the Restricted
Subsidiaries) or other title retention agreement relating to such asset.

"Oil and Gas Hedging Contracts" means any oil and gas purchase or hedging
agreement, and other agreement or arrangement, in each case, that is designed
to provide protection against oil and gas price fluctuations.

"Pari Passu Indebtedness" means any Indebtedness of the Company, whether
outstanding on the date on which the Notes are originally issued or thereafter
created, incurred or assumed, unless, in the case of any particular
Indebtedness, the instrument creating or evidencing the same or pursuant to
which the same is outstanding expressly provides that such Indebtedness shall
be subordinated in right of payment to the Notes.

"Restricted Subsidiary" means each of the existing Subsidiaries of the
Company and any Subsidiary of the Company that is a successor corporation of
any of the existing Subsidiaries, except for BGP Inc. The status of any
Subsidiary of the Company as a Restricted Subsidiary shall continue so long as
it is a Subsidiary of the Company.

"Sale/Leaseback Transaction" means any arrangement with any Person providing
for the leasing by the Company or any Restricted Subsidiary, for a period of
more than three years, of any real or tangible personal property, which
property has been or is to be sold or transferred by the Company or such
Restricted Subsidiary to such Person in contemplation of such leasing.

EVENTS OF DEFAULT

An Event of Default will be defined in the Indenture as being: (i) default
by the Company for 30 days in payment of any interest on the Notes; (ii)
default by the Company in any payment of principal of or premium, if any, on
the Notes; (iii) default by the Company in performance of any other covenant
or agreement in the Notes, or the Indenture which shall not have been remedied
within 60 days after written notice by the Trustee or by the holders of at
least 25% in principal amount of the Notes then outstanding; (iv) the
acceleration of the maturity of any Indebtedness of the Company or any
Restricted Subsidiary (other than the Notes) having an outstanding principal
amount of $5 million or more individually or in the aggregate, or a default in
the payment of any principal or interest in respect of any Indebtedness of the
Company or any Restricted Subsidiary (other than the Notes) having an
outstanding principal amount of $5 million or more individually or in the
aggregate and such default shall be continuing for a period of 30 days without
the Company or such Restricted Subsidiary, as the case may be, effecting a
cure of such default; (v) failure by the Company or any Restricted Subsidiary
to pay final, non-appealable judgments aggregating in excess of $10 million,
which judgments are not paid, discharged or stayed for a period of 60 days; or
(vi) certain events involving bankruptcy, insolvency or reorganization of the
Company or any Restricted Subsidiary. The Indenture will provide

48
<PAGE>

that the Trustee may withhold notice to the holders of the Notes of any
default (except in payment of principal of, or premium, if any, or interest on
the Notes) if the Trustee considers it in the interest of the holders of the
Notes to do so.

The Indenture will provide that if an Event of Default occurs and is
continuing with respect to the Indenture, the Trustee or the holders of not
less than 25% in principal amount of the Notes outstanding may declare the
principal of and premium, if any, and accrued and unpaid interest on all the
Notes to be due and payable. Upon such a declaration, such principal, premium,
if any, and interest will be due and payable immediately. If an Event of
Default relating to certain events of bankruptcy, insolvency or reorganization
of the Company or any Restricted Subsidiary occurs and is continuing, the
principal of and premium, if any, and interest on all the Notes will become
and be immediately due and payable without any declaration or other act on the
part of the Trustee or any holders of the Notes. The amount due and payable on
the acceleration of any Note will be equal to 100% of the principal amount of
such Note, plus accrued interest to the date of payment. Under certain
circumstances, the holders of a majority in principal amount of the
outstanding Notes may rescind any such acceleration with respect to the Notes
and its consequences.

The Indenture will provide that no holder of a Note may pursue any remedy
under the Indenture unless (i) the Trustee shall have received written notice
of a continuing Event of Default, (ii) the Trustee shall have received a
request from holders of at least 25% in principal amount of the Notes to
pursue such remedy, (iii) the Trustee shall have been offered indemnity
satisfactory to it and (iv) the Trustee shall have failed to act for a period
of 60 days after receipt of such notice and offer of indemnity; however, such
provision does not affect the right of a holder of a Note to sue for
enforcement of any overdue payment thereon.

The holders of a majority in principal amount of the Notes then outstanding
will have the right to direct the time, method and place of conducting any
proceeding for exercising any remedy available to the Trustee under the
Indenture, subject to certain limitations specified in the Indenture. The
Indenture will require the annual filing by the Company with the Trustee of a
written statement as to compliance with the covenants contained in the
Indenture.

MODIFICATION AND WAIVER

The Indenture will provide that modifications and amendments to the
Indenture or the Notes may be made by the Company and the Trustee with the
consent of the holders of a majority in principal amount of the Notes then
outstanding; provided that no such modification or amendment may, without the
consent of the holder of each Note then outstanding affected thereby, (i)
reduce the percentage in principal amount of Notes whose holders must consent
to an amendment, supplement or waiver; (ii) reduce the rate of or change the
time for payment of interest, including default interest, on any Note; (iii)
reduce the principal of or change the fixed maturity of any Note or alter the
premium or other provisions with respect to redemption; (iv) make any Note
payable in money other than that stated in the Note; (v) impair the right to
institute suit for the enforcement of any payment of principal of, or premium,
if any, or interest on, any Note; (vi) make any change in the percentage of
principal amount of Notes necessary to waive compliance with certain
provisions of the Indenture; or (vii) waive a continuing Default or Event of
Default in the payment of principal of, or premium, if any, or interest on the
Notes. The Indenture will provide that modifications and amendments of the
Indenture may be made by the Company and the Trustee without the consent of
any holders of Notes in certain limited circumstances, including (a) to cure
any ambiguity, omission, defect or inconsistency, (b) to provide for
guarantees of the Notes or addition of any Subsidiary of the Company as a
guarantor of the Notes, (c) to provide for the assumption of the obligations
of the Company under the Indenture upon the merger, consolidation or sale or
other disposition of all or substantially all of the assets of the Company,
(d) to provide for uncertificated Notes in addition to or in place of
certificated Notes, (e) to comply with any requirement in order to effect or
maintain the qualification of the Indenture under the Trust Indenture Act of
1939 or (f) to make any change that does not adversely affect the rights of
any holder of Notes in any material respect.

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<PAGE>

The Indenture will provide that the holders of a majority in aggregate
principal amount of the Notes then outstanding may waive any past default
under the Indenture, except a default in the payment of principal, or premium,
if any, or interest.

DISCHARGE AND TERMINATION

DEFEASANCE OF CERTAIN OBLIGATIONS. The Indenture will provide that the
Company may terminate certain of its obligations under the Indenture,
including those described under the section "Certain Covenants," if (i) the
Company irrevocably deposits in trust with the Trustee money or U.S.
Government Obligations sufficient to pay principal of and interest on the
Notes to maturity, and to pay all other sums payable by it under the
Indenture, provided that the Trustee shall have been irrevocably instructed to
apply such money or the proceeds of such U.S. Government Obligations to the
payment of said principal and interest with respect to the Notes as the same
shall become due; (ii) the Company delivers to the Trustee an Officers'
Certificate stating that all conditions precedent to satisfaction and
discharge of the Indenture have been complied with, and an Opinion of Counsel
to the same effect; (iii) no Default or Event of Default shall have occurred
and be continuing on the date of such deposit; and (iv) the Company shall have
delivered to the Trustee an Opinion of Counsel from nationally recognized
counsel acceptable to the Trustee or a tax ruling to the effect that the
holders of the Notes will not recognize income, gain or loss for Federal
income tax purposes as a result of the Company's exercise of its option under
such section and will be subject to Federal income tax on the same amount and
in the same manner and at the same times as would have been the case if such
option had not been exercised. In order to have money available on a payment
date to pay principal of or interest on the Notes, the U.S. Government
Obligations shall be payable as to principal or interest on or before such
payment date in such amounts as will provide the necessary money. U.S.
Government Obligations shall not be callable at the issuer's option. The
Company's payment obligation shall survive until the Notes are no longer
outstanding.

DISCHARGE. The Indenture will provide that the Indenture shall cease to be
of further effect (subject to certain exceptions relating to compensation and
indemnity of the Trustee and repayment to the Company of excess money or
securities) when (i) either (A) all outstanding Notes theretofore
authenticated and issued (other than destroyed, lost or stolen Notes that have
been replaced or paid) have been delivered to the Trustee for cancellation; or
(B) all outstanding Notes not theretofore delivered to the Trustee for
cancellation: (x) have become due and payable, or (y) will become due and
payable at their stated maturity within one year or (z) are to be called for
redemption within one year under arrangements satisfactory to the Trustee for
the giving of notice of redemption by the Trustee in the name, and at the
expense, of the Company, and the Company, in the case of clause (x), (y) or
(z) above, has deposited or caused to be deposited with the Trustee as funds
(immediately available to the holders in the case of clause (x) ) in trust for
such purpose an amount which, together with earnings thereon, will be
sufficient to pay and discharge the entire indebtedness on such Notes for
principal, premium, if any, and interest to the date of such deposit (in the
case of Notes which have become due and payable) or to the stated maturity or
Redemption Date, as the case may be; (ii) the Company has paid or caused to be
paid all other sums payable by it under the Indenture; and (iii) the Company
has delivered to the Trustee an Officers' Certificate stating that all
conditions precedent to satisfaction and discharge of the Indenture have been
complied with, together with an Opinion of Counsel to the same effect.

GOVERNING LAW

The Indenture will provide that it will be governed by, and construed in
accordance with, the laws of the State of New York.

THE TRUSTEE

Bankers Trust Company will be the Trustee under the Indenture. Its address
is Four Albany Street, New York, New York 10006. The Company has also
appointed the Trustee as the initial Registrar and as the initial Paying Agent
under the Indenture.

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<PAGE>

The Indenture will contain certain limitations on the right of the Trustee,
should it become a creditor of the Company, to obtain payment of claims in
certain cases, or to realize on certain property received in respect of any
such claim as security or otherwise. In the event the Trustee acquires any
conflicting interest (as defined in the Trust Indenture Act of 1939), however,
it must eliminate such conflict or resign.

The Indenture will provide that in case an Event of Default shall occur (and
be continuing), the Trustee will be required to use the degree of care and
skill of a prudent man in the conduct of his own affairs. The Trustee will be
under no obligation to exercise any of its powers under the Indenture at the
request of any of the holders of the Notes, unless such holders shall have
offered the Trustee indemnity reasonably satisfactory to it.

BOOK-ENTRY, DELIVERY AND FORM

The Notes to be sold as set forth herein will be issued in the form of a
fully registered Global Certificate (the "Global Certificate"). The Global
Certificate will be deposited on the date of the closing of the sale of the
Notes offered hereby (the "Closing Date") with, or on behalf of, The
Depository Trust Company (the "Depositary") and registered in the name of its
nominee (such nominee being referred to herein as the "Global Certificate
Holder") or will remain in the custody of the Trustee pursuant to a FAST
Balance Certificate Agreement or similar agreement between the Depositary and
the Trustee.

Except as set forth below, the Global Certificate may be transferred, in
whole and not in part, only to another nominee of the Depositary or to a
successor of the Depositary or its nominee.

The Depositary has advised the Company and the Underwriters as follows: It
is a limited-purpose trust company which was created to hold securities for
its participating organizations (the "Participants") and to facilitate the
clearance and settlement of transactions in such securities between
Participants through electronic book-entry changes in accounts of its
Participants. Participants include securities brokers and dealers (including
the Underwriters), banks, trust companies, clearing corporations and certain
other organizations. Access to the Depositary's book-entry system is also
available to others, such as banks, brokers, dealers and trust companies that
clear through or maintain a custodial relationship with a Participant, either
directly or indirectly ("indirect participants"). Persons who are not
Participants may beneficially own securities held by the Depositary only
through Participants or indirect participants.

The Depositary has also advised that pursuant to procedures established by
it (i) upon the issuance by the Company of the Notes, the Depositary will
credit the accounts of Participants designated by the Underwriters with the
principal amount of the Notes purchased by the Underwriters, and (ii)
ownership of beneficial interests in the Global Certificate will be shown on,
and the transfer of that ownership will be effected only through, records
maintained by the Depositary (with respect to Participants' interests), the
Participants and the indirect participants. The laws of some states require
that certain persons take physical delivery in definitive form of securities
which they own. Consequently, the ability to transfer beneficial interests in
the Global Certificate is limited to such extent.

All payments on the Global Certificate registered in the name of the
Depositary's nominee will be made by the Company through the Paying Agent to
the Depositary's nominee as the registered owner of the Global Certificate.
Under the terms of the Indenture, the Company and the Trustee will treat the
persons in whose names the Notes are registered as the owners of such Notes
for the purpose of receiving payments of principal and interest on such Notes
and for all other purposes whatsoever. Therefore, neither the Company, the
Trustee nor the Paying Agent has any direct responsibility or liability for
the payment of principal or interest on the Notes to owners of beneficial
interests in the Global Certificate. The Depositary has advised the Company
and the Trustee that its present practice is, upon receipt of any payment of
principal or interest, to credit immediately the accounts of the

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<PAGE>

Participants with payment in amounts proportionate to their respective
holdings in principal amount of beneficial interests in the Global Certificate
as shown on the records of the Depositary. Payments by Participants and
indirect participants to owners of beneficial interests in the Global
Certificate will be governed by standing instructions and customary practices,
as is now the case with securities held for the accounts of customers in
bearer form or registered in "street name" and will be the responsibility of
such Participants or indirect participants.

The Company will issue Notes in definitive form in exchange for the Global
Certificate if, and only if, either (1) the Depositary is at any time
unwilling or unable to continue as depositary and a successor depositary is
not appointed by the Company within 90 days, (2) an Event of Default has
occurred and is continuing and the Registrar has received a request from the
Depositary to issue Notes in definitive form in lieu of all or a portion of
the Global Certificate (in which case the Company shall deliver Notes in
definitive form within 30 days of such request), or (3) the Company determines
not to have the Notes represented by a Global Certificate. In any instance, an
owner of a beneficial interest in the Global Certificate will be entitled to
have Notes equal in principal amount to such beneficial interest registered in
its name and will be entitled to physical delivery of such Notes in definitive
form. Notes so issued in definitive form will be issued in denominations of
$1,000 and integral whole multiples thereof and will be issued in registered
form only, without coupons.

So long as the Global Certificate Holder is the registered owner of the
Global Certificate, the Global Certificate Holder will be considered the sole
Holder under the Indenture of any Notes evidenced by the Global Certificates.
Beneficial owners of Notes evidenced by the Global Certificate will not be
considered the owners or Holders thereof under the Indenture for any purpose,
including with respect to the giving of any directions, instructions or
approvals to the Trustee thereunder. Neither the Company nor the Trustee will
have any responsibility or liability for any aspect of the records of the
Depositary or for maintaining, supervising or reviewing any records of the
Depositary relating to the Notes.

SETTLEMENT AND PAYMENT

Settlement for the Notes will be made by the Underwriters in immediately
available funds. If the total outstanding principal amount of the Notes is
represented by a Global Certificate, all payments of principal of and any
premium and interest on the Notes will be made by the Company in immediately
available funds; otherwise, payments on definitive physical certificates will
be made in U.S. Clearing House funds. Secondary market trading activity in the
Notes will also settle in immediately available funds.

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<PAGE>

UNDERWRITING

Subject to the terms and conditions of the Underwriting Agreement, the
Company has agreed to sell to each of the Underwriters named below, and each
of such Underwriters has severally agreed to purchase from the Company, the
aggregate principal amount of Notes set forth opposite its name below:

<TABLE>
<CAPTION>
PRINCIPAL AMOUNT
UNDERWRITER OF NOTES
----------- ----------------
<S> <C>
Goldman, Sachs & Co. ....................................... $ 82,500,000
Chase Securities Inc........................................ 30,000,000
Lehman Brothers Inc......................................... 30,000,000
Petrie Parkman & Co., Inc................................... 7,500,000
------------
Total..................................................... $150,000,000
============
</TABLE>

Under the terms and conditions of the Underwriting Agreement, the
Underwriters are committed to take and pay for all of the Notes, if any are
taken.

The Underwriters propose to offer the Notes in part directly to the public
at the initial public offering price set forth on the cover page of this
Prospectus and in part to certain securities dealers at such price less a
concession of 1.00% of the principal amount of the Notes. The Underwriters may
allow, and such dealers may reallow, a concession not to exceed 0.25% of the
principal amount of the Notes to certain brokers and dealers. After the Notes
are released for sale to the public, the offering price and other selling
terms may from time to time be varied by the Underwriters.

The Notes are a new issue of securities with no established trading market.
The Company has been advised by the Underwriters that the Underwriters intend
to make a market in the Notes but are not obligated to do so and may
discontinue market making at any time without notice. No assurance can be
given as to the liquidity of the trading market for the Notes.

The Company has agreed to indemnify the several Underwriters against certain
liabilities, including liabilities under the Securities Act.

Under Rule 2710(c)(8) of the National Association of Securities Dealers,
Inc. (the "NASD"), Chase Securities Inc. may be deemed to have a conflict of
interest with the Company because more than 10% of the net proceeds of the
sale of the Notes is expected to be paid to an affiliate of such Underwriter
in its capacity as a lender under the Company's bank credit facility. See "Use
of Proceeds." This Offering is being conducted in accordance with Rule
2710(c)(8), which provides that, among other things, when an NASD member
participates in the underwriting of debt securities of a company with which it
or its associated persons, parent or affiliates have a conflict of interest,
the yield to maturity can be no lower than that recommended by a "qualified
independent underwriter" meeting certain standards. In accordance with this
requirement, Goldman, Sachs & Co. will serve in such role and will recommend a
minimum yield to maturity in compliance with the requirements of Rule
2710(c)(8). Goldman, Sachs & Co. will receive compensation from the Company in
the amount of $10,000 for serving in such role. In connection with the
Offering, Goldman, Sachs & Co. in its role as qualified independent
underwriter has performed due diligence investigations and reviewed and
participated in the preparation of this Prospectus and the Registration
Statement of which this Prospectus forms a part.

Goldman, Sachs & Co. provided Plains, and Petrie Parkman & Co., Inc.
provided the Company with investment banking services in connection with the
merger of Plains and the Company. Goldman, Sachs & Co. and Petrie Parkman &
Co., Inc. each provided the Company with investment banking services in
connection with the public offering of 5.4 million shares of the Company's
common stock in June 1996.

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<PAGE>

LEGAL MATTERS

Certain legal matters regarding the Offering have been passed upon on behalf
of the Company by Bearman Talesnick & Clowdus Professional Corporation,
Denver, Colorado. Attorneys employed by that law firm beneficially own
approximately 14,700 shares of the Company's common stock. Vinson & Elkins
L.L.P., Houston, Texas, as special counsel to the Company, has passed upon the
validity of the issuance of the Notes. Certain legal matters in connection
with the Notes will be passed upon for the Underwriters by Andrews & Kurth
L.L.P., New York, New York.

EXPERTS

The consolidated financial statements and schedules of the Company as of
December 31, 1995 and 1994 and for each of the three years in the period ended
December 31, 1995 included in this Prospectus and elsewhere in the
Registration Statement of which this Prospectus forms a part have been audited
by Arthur Andersen LLP, independent public accountants, as indicated in their
reports with respect thereto, and are included herein in reliance upon the
authority of such firm as experts in giving such reports.

The information included and incorporated by reference herein regarding the
total proved reserves of the Company was prepared by the Company. With respect
to the reserve estimates as of and prior to December 31, 1995, a portion was
reviewed by Ryder Scott Company and the remaining portion was reviewed or
prepared by Netherland, Sewell & Associates, Inc., as stated in their
respective letter reports with respect thereto. The reserve estimates as of
December 31, 1996 were reviewed solely by Ryder Scott Company. The reserve
review letters of Ryder Scott Company and Netherland, Sewell & Associates,
Inc. are filed as exhibits to the Registration Statement of which this
Prospectus is a part, in reliance upon the authority of said firms as experts
with respect to the matters covered by their reports and the giving of their
reports.

AVAILABLE INFORMATION

This Prospectus constitutes a part of a Registration Statement on Form S-3
(herein together with all amendments thereto referred to as the "Registration
Statement") filed by the Company with the
Commission under the Securities Act. This Prospectus does not contain all the
information set forth in the Registration Statement and exhibits thereto, and
statements included in this Prospectus as to the content of any contract or
other document referred to are not necessarily complete. For further
information, reference is made to the Registration Statement and to the
exhibits and schedules filed therewith. All these documents may be inspected
at the Commission's principal office in Washington, D.C. without charge, and
copies of them may be obtained from the Commission upon payment of prescribed
fees. Statements contained in this Prospectus as to the contents of any
contract or other document filed as an exhibit to the Registration Statement
are not necessarily complete, and in each instance reference is hereby made to
the copy of such contract or other document filed as an exhibit to the
Registration Statement, each such statement being qualified in all respects by
such reference.

The Company is subject to the informational requirements of the Exchange
Act, and, in accordance therewith files reports, proxy statements and other
information with the Commission. Such reports, proxy statements and other
information can be inspected and copied at the public reference facilities
maintained by the Commission at 450 Fifth Street, N.W., Washington, D.C.
20549, Room 1024 and at the following Regional Offices of the Commission: 500
West Madison Street, Suite 1400, Chicago, Illinois 60661-2511, and 7 World
Trade Center, New York, New York 10048. Copies of such material also can be
obtained at prescribed rates by writing to the Commission, Public Reference
Section, 450 Fifth Street, N.W., Washington, D.C. 20549. In addition, such
material may also be

54
<PAGE>

inspected and copied at the offices of the New York Stock Exchange, Inc., 20
Broad Street, New York, New York 10005. In addition, such materials filed
electronically by the Company with the Commission are available at the
Commission's World Wide Web site at http://www.sec.gov.

INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE

The following documents that previously were, or are required in the future
to be, filed with the Commission (File No. 1-13446) pursuant to the Exchange
Act are incorporated herein by reference:

(i) the Company's Annual Report on Form 10-K for the year ended December
31, 1995;

(ii) the Company's Quarterly Reports on Form 10-Q for each of the
quarters ended March 31, 1996, June 30, 1996, and September 30, 1996;

(iii) the Company's Current Reports on Form 8-K dated each of June 20,
1996, November 4, 1996, January 8, 1997 and February 10, 1997;

(iv) the description of the Company's Common Stock contained in the
Company's registration statement on Form 8-A as filed with the Commission
on October 27, 1994;

(v) the Company's Proxy Statement dated April 11, 1996 concerning the
Company's Annual Meeting of Stockholders held June 5, 1996; and

(vi) all documents filed by the Company pursuant to Sections 13(a),
13(c), 14 or 15(d) of the Exchange Act subsequent to the date of this
Prospectus and prior to the termination of the offering made hereby.

Any statement contained in a document incorporated by reference herein shall
be deemed to be modified or superseded for purposes of this Prospectus to the
extent that such statement is modified or replaced by a statement contained in
this Prospectus or in any other subsequently filed document that also is or is
deemed to be incorporated by reference into this Prospectus. Any such
statement so modified or superseded shall not be deemed, except as so modified
or replaced, to constitute a part of this Prospectus. The Company will provide
without charge to each person to whom a copy of this Prospectus has been
delivered, upon the written or oral request of any such person, a copy of any
or all of the documents referred to above that have been or may be
incorporated in this Prospectus by reference, other than exhibits to such
documents. Written or oral requests for such copies should be directed to
Donald H. Stevens, Vice President, Barrett Resources Corporation, 1515
Arapahoe Street, Tower 3, Suite 1000, Denver, Colorado 80202, (303) 572-3900.

CERTAIN DEFINITIONS

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

As used in this Prospectus, the following terms have the following specific
meanings: "Mcf" means thousand cubic feet, "MMcf" means million cubic feet,
"Bcf" means billion cubic feet, "Bbl" means barrel, "MBbl" means thousand
barrels, "Mcfe" means thousand cubic feet equivalent, "MMcfe" means million
cubic feet equivalent, and "MMBtu" means million British thermal units.

With respect to information concerning the Company's working interests in
wells or drilling locations, "gross" natural gas and oil wells or "gross"
acres is the number of wells or acres in which the Company has an interest,
and "net" gas and oil wells or "net" acres are determined by multiplying
"gross" wells or acres by the Company's working interest in those wells or
acres. A working interest in

55
<PAGE>

an oil and natural gas lease is an interest that gives the owner the right to
drill, produce, and conduct operating activities on the property and to
receive a share of production of any hydrocarbons covered by the lease. A
working interest in an oil and gas lease also entitles its owner to a
proportionate interest in any well located on the lands covered by the lease,
subject to all royalties, overriding royalties and other burdens, to all costs
and expenses of exploration, development and operation of any well located on
the lease, and to all risks in connection therewith.

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

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

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

A "farmout" is an assignment to another party of an interest in a drilling
location and related acreage conditional upon the drilling of a well on that
location. A "farm-in" is an assignment by the owner of a working interest in
an oil and gas lease of the working interest or a portion thereof to another
party who desires to drill on the leased acreage. Generally, the assignee is
required to drill one or more wells in order to earn its interest in the
acreage. The assignor usually retains a royalty or reversionary working
interest in the lease. The assignee is said to have "farmed-in" the acreage.

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

"Reserves" means natural gas and crude oil, condensate and natural gas
liquids on a net revenue interest basis, found to be commercially recoverable.
"Proved developed reserves" includes proved developed producing reserves and
proved developed behind-pipe reserves. "Proved developed producing reserves"
includes only those reserves expected to be recovered from existing completion
intervals in existing wells. "Proved developed behind-pipe reserves" includes
those reserves that exist behind the casing of existing wells when the cost of
making such reserves available for production is relatively small compared to
the cost of a new well. "Proved undeveloped reserves" includes those reserves
expected to be recovered from new wells on proved undrilled acreage or from
existing wells where a relatively major expenditure is required for
recompletion.

56
<PAGE>

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<S> <C>
Report Of Independent Public Accountants................................. F-2
Consolidated Balance Sheets as of September 30, 1996 (unaudited) and at
December 31, 1995 and 1994.............................................. F-3
Consolidated Statements Of Income for the nine months ended September 30,
1996 and 1995 (unaudited) and each of the three years in the period
ended December 31, 1995................................................. F-4
Consolidated Statements Of Stockholders' Equity for the nine months ended
September 30, 1996 and 1995 (unaudited) and each of the three years in
the period ended December 31, 1995...................................... F-5
Consolidated Statements Of Cash Flows for the nine months ended September
30, 1996 and 1995 (unaudited) and each of the three years in the period
ended December 31, 1995................................................. F-6
Notes to the Consolidated Financial Statements........................... F-7
Supplemental Oil And Gas Information..................................... F-23
</TABLE>

F-1

<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-2
<PAGE>

BARRETT RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)

<TABLE>
<CAPTION>
DECEMBER 31,
------------------ SEPTEMBER 30,
1994 1995 1996
-------- -------- -------------
(UNAUDITED)
<S> <C> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents.................. $ 12,348 $ 7,529 $ 9,446
Receivables, net........................... 34,522 31,089 38,680
Inventory.................................. 643 554 962
Other current assets....................... 1,099 574 886
-------- -------- --------
Total current assets..................... 48,612 39,746 49,974
Net property and equipment (full cost
method)..................................... 261,424 300,666 422,168
Other assets................................. 916 -- --
-------- -------- --------
$310,952 $340,412 $472,142
======== ======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable........................... $ 24,587 $ 14,369 $ 14,860
Amounts payable to oil and gas property
owners.................................... 16,091 13,366 16,199
Accrued and other liabilities.............. 5,468 8,325 16,913
-------- -------- --------
Total current liabilities................ 46,146 36,060 47,972
Long term debt............................... 53,000 89,000 12,000
Deferred income taxes........................ 21,726 23,524 48,595
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, 31,319,193 outstanding
(25,092,246 and 24,694,669 at December 31,
1995 and 1994, respectively............... 247 251 313
Additional paid-in capital................... 78,628 86,154 241,407
Retained earnings............................ 109,304 105,890 122,849
Treasury stock, at cost...................... (43) (467) (994)
-------- -------- --------
Total stockholders' equity............... 188,136 191,828 363,575
-------- -------- --------
$310,952 $340,412 $472,142
======== ======== ========
</TABLE>

(See accompanying notes)

F-3
<PAGE>

BARRETT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS, EXCEPT PER SHARE DATA)

<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEARS ENDED DECEMBER 31, SEPTEMBER 30,
--------------------------- ------------------
1993 1994 1995 1995 1996
-------- -------- -------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Revenues:
Oil and gas production...... $ 80,911 $ 78,794 $ 96,996 $70,481 $102,412
Trading revenues............ 22,955 28,114 28,554 20,156 30,547
Revenue from gas gathering.. 216 353 1,074 917 1,996
Interest income............. 736 864 714 529 633
Other income................ 1,254 1,333 678 594 465
-------- -------- -------- -------- --------
106,072 109,458 128,016 92,677 136,053
Operating expenses:
Lease operating expenses.... 30,383 28,223 34,525 25,418 34,027
Depreciation, depletion and
amortization............... 20,185 22,760 33,480 23,625 31,859
Cost of trading............. 21,675 27,190 27,611 19,385 28,449
General and administrative.. 11,194 13,261 13,426 10,255 11,212
Interest expense............ 725 942 4,631 3,284 3,154
Other expenses, net......... 867 645 588 568 --
Merger and reorganization
expense.................... -- -- 14,161 13,207 --
-------- -------- -------- -------- --------
85,029 93,021 128,422 95,742 108,701
-------- -------- -------- -------- --------
Income (loss) before income
taxes and cumulative effect
of change in method of
accounting for postretirement
benefits..................... 21,043 16,437 (406) (3,065) 27,352
Provision for income taxes.... 6,721 5,138 1,834 2,812 10,393
-------- -------- -------- -------- --------
Income (loss) before
cumulative effect of change
in method of accounting for
postretirement benefits...... 14,322 11,299 (2,240) (5,877) 16,959
Cumulative effect of change in
accounting for postretirement
benefits, net of tax......... (656) -- -- -- --
-------- -------- -------- -------- --------
Net income (loss)............. $ 13,666 $ 11,299 $ (2,240) $ (5,877) $ 16,959
======== ======== ======== ======== ========
Net income (loss) per common
share and common share
equivalent before change in
method of accounting for
postretirement benefits...... $ 0.58 $ 0.46 $ (0.09) $ (0.23) $ 0.62
Net income (loss) per common
share and common share
equivalent--cumulative
effect....................... $ (0.03) $ -- $ -- $ -- $ --
-------- -------- -------- -------- --------
Net income (loss) per common
share and common share
equivalent................... $ 0.55 $ 0.46 $ (0.09) $ (0.23) $ 0.62
======== ======== ======== ======== ========
</TABLE>

(See accompanying notes)

F-4
<PAGE>

BARRETT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(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
Net income for the three
month period ending
December 31, 1992........ -- -- -- 1,333 1,333
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
Exercise of stock
options.................. 2 3,801 (527) -- 3,276
Issuance of common stock.. 60 151,452 -- -- 151,512
Net income for the nine
months ended September
30, 1996 (unaudited)..... -- -- -- 16,959 16,959
---- -------- ----- -------- --------
Balance, September 30,
1996....................... $313 $241,407 $(994) $122,849 $363,575
==== ======== ===== ======== ========
</TABLE>

(See accompanying notes)

F-5
<PAGE>

BARRETT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
---------------------------- -------------------
1993 1994 1995 1995 1996
-------- -------- -------- -------- ---------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Cash flows from operations:
Net income (loss)......... $ 13,666 $ 11,299 $ (2,240) $ (5,877) $ 16,959
Adjustments needed to
reconcile to net cash
flow provided by
operations:
Depreciation, depletion
and amortization....... 20,185 22,760 33,480 23,625 31,859
Unrealized (gain) loss
on trading............. (124) 58 1,139 -- (1,138)
Deferred income taxes... 5,975 4,788 1,798 2,543 9,778
Other................... 782 70 (787) (770) --
-------- -------- -------- -------- ---------
40,484 38,975 33,390 19,521 57,458
Change in current assets
and liabilities:
Accounts receivable... (4,304) (8,436) 3,433 9,505 (7,246)
Other current assets.. (209) (148) 525 432 (416)
Accounts payable...... (1,870) 6,803 (524) (15,305) 457
Amounts due oil and
gas property owners.. 5,640 623 (2,725) (942) 7,325
Accrued and other
liabilities.......... 1,839 (1,244) 1,439 3,242 5,132
-------- -------- -------- -------- ---------
Net cash flow provided by
operations................. 41,580 36,573 35,538 16,453 62,710
Cash flows from investing
activities:
Proceeds from sale of oil
and gas properties....... 16,210 458 504 209 1,992
Purchase of short-term in-
vestments................ (5,952) (11,322) -- -- --
Maturity of short-term in-
vestments................ 1,984 15,290 -- -- --
Acquisition of property
and equipment............ (45,488) (95,589) (82,758) (46,945) (124,054)
Other..................... 65 146 -- -- --
-------- -------- -------- -------- ---------
Net cash flow used in in-
vesting
activities................. (33,181) (91,017) (82,254) (46,736) (122,062)
Cash flows from financing
activities:
Proceeds from issuance of
common stock............. 19,212 301 7,071 6,413 138,269
Purchase of treasury
stock.................... -- (78) -- -- --
Borrowing under line of
credit................... 1,300 44,000 115,000 69,000 33,000
Payments on line of cred-
it....................... (7,800) (4,500) (79,000) (37,000) (110,000)
Dividends paid............ (2,352) (2,353) (1,174) (1,179) --
Other..................... 868 (147) -- (767) --
-------- -------- -------- -------- ---------
Net cash flow provided by
financing
activities................. 11,228 37,223 41,897 36,467 61,269
Increase (decrease) in cash
and cash equivalents....... 19,627 (17,221) (4,819) 6,184 1,917
Cash and cash equivalents at
beginning of period........ 9,942 29,569 12,348 12,348 7,529
-------- -------- -------- -------- ---------
Cash and cash equivalents at
end of period.............. $ 29,569 $ 12,348 $ 7,529 $ 18,532 $ 9,446
======== ======== ======== ======== =========
</TABLE>

(See accompanying notes)

F-6
<PAGE>

BARRETT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(INFORMATION FOR THE NINE MONTH PERIODS ENDED
SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED)

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.

F-7
<PAGE>

BARRETT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

(INFORMATION FOR THE NINE MONTH PERIODS ENDED
SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED)

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 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

F-8
<PAGE>

BARRETT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

(INFORMATION FOR THE NINE MONTH PERIODS ENDED
SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED)

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 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.

Unaudited financial statements:

In the opinion of management, the accompanying unaudited consolidated
condensed financial statements contain all adjustments necessary to present
fairly the financial position of the Company as of September 30, 1996 and the
results of operations and cash flows for the periods presented. All such
adjustments are of a normal recurring nature. Certain information and footnote
disclosures normally included in financial statements prepared in accordance
with generally accepted accounting principles have been condensed or omitted
pursuant to the SEC's rules and regulations. The results of operations for the
periods presented are not necessarily indicative of the results for the full
year.

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

F-9
<PAGE>

BARRETT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

(INFORMATION FOR THE NINE MONTH PERIODS ENDED
SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED)

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.

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>
SIX MONTH PERIOD ENDED
JUNE 30, 1995 BARRETT PLAINS(1) ADJUSTMENTS(2) COMBINED
---------------------- ------- --------- -------------- --------
(UNAUDITED)
<S> <C> <C> <C> <C>
Net revenues....................... $29,277 $35,823 -- $ 65,100
Net income......................... 2,200 3,771 -- 5,971
<CAPTION>
12 MONTH PERIOD ENDED 9/30/94 12/31/94 12/31/94
--------------------- ------- --------- --------
<S> <C> <C> <C> <C>
Net revenues....................... $41,252 $63,024 $ 5,182 $109,458
Net income......................... 4,439 7,768 (908) 11,299
<CAPTION>
12 MONTH PERIOD ENDED 9/30/93 12/31/93 12/31/93
--------------------- ------- --------- --------
<S> <C> <C> <C> <C>
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.

F-10
<PAGE>

BARRETT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

(INFORMATION FOR THE NINE MONTH PERIODS ENDED
SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED)

3. RECEIVABLES

<TABLE>
<CAPTION>
DECEMBER 31,
---------------
1994 1995
------- -------
(IN THOUSANDS)
<S> <C> <C>
Oil and gas revenue receivable.............................. $13,257 $15,535
Joint interest billings..................................... 14,542 7,652
Trading receivables......................................... 6,483 5,665
Other accounts receivable................................... 240 2,237
------- -------
$34,522 $31,089
======= =======
</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.

4. PROPERTY AND EQUIPMENT

<TABLE>
<CAPTION>
DECEMBER 31,
-----------------
1994 1995
-------- --------
(IN THOUSANDS)
<S> <C> <C>
Oil and gas properties, full cost method:
Unevaluated costs, not being amortized................. $ 12,611 $ 10,579
Evaluated costs........................................ 346,950 420,784
Gas gathering systems.................................. 8,388 8,815
Furniture, vehicles and equipment........................ 9,765 9,801
-------- --------
377,714 449,979
Less accumulated depreciation, depletion, amortization
and impairment.......................................... 116,290 149,313
-------- --------
$261,424 $300,666
======== ========
</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.

F-11
<PAGE>

BARRETT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

(INFORMATION FOR THE NINE MONTH PERIODS ENDED
SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED)

5. UNEVALUATED OIL AND GAS PROPERTY COSTS

Unevaluated oil and gas property costs consist of the following:

<TABLE>
<CAPTION>
COSTS INCURRED DURING
-------------------------------
1992 1993 1994 1995 TOTAL
---- ---- ------ ------ -------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Acquisition costs............................... $71 $-- $2,130 $5,623 $ 7,824
Exploration costs............................... 11 32 53 2,659 2,755
--- --- ------ ------ -------
$82 $32 $2,183 $8,282 $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 lenders increased the collateral value to
$205 million based on the June 30, 1996 reserve report. The lenders also
extended the maturity date to October 31, 2000. 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 0.5% to 1.0% (depending on the Company's indebtedness 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% and $6 million was accruing interest on a
prime based rate of 8.50%. The line of credit agreement restricts the payment
of dividends, borrowings, sale of assets, loans to others, investment and
merger 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. As of September 30, 1996, the
Company's outstanding balance under the line of credit was $12 million, all of
which was accruing interest at an average rate of six percent.

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

F-12
<PAGE>

BARRETT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

(INFORMATION FOR THE NINE MONTH PERIODS ENDED
SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED)

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 OPTION
OF SHARES 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, restat-
ed...................................... 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 was 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 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.

F-13
<PAGE>

BARRETT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

(INFORMATION FOR THE NINE MONTH PERIODS ENDED
SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED)

The following table sets forth the plan's funded status:

<TABLE>
<CAPTION>
1993 1994 1995
------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Actuarial present value of benefit obligations:
Accumulated benefit obligation, including
vested benefits of $1,290,000, $1,637,000 and
$2,961,000 respectively....................... $(1,383) $(1,666) $(2,961)
======= ======= =======
Projected benefit obligation................... $(2,321) $(2,396) $(2,961)
Plan assets at fair value...................... 1,977 2,205 2,709
------- ------- -------
Projected benefit obligation in excess of plan
assets........................................ (344) (191) (252)
Unrecognized net (gain) loss................... 16 (141) --
Prior service cost not yet recognized in net
periodic pension costs........................ 64 93 --
Unrecognized net obligation being recognized
over 9.5 and 10.5 years in 1994 and 1993,
respectively.................................. 146 132 --
------- ------- -------
Accrued pension cost........................... $ (118) $ (107) $ (252)
======= ======= =======
Net pension cost included the following compo-
nents:
Service cost--benefits earned.................. $ 346 $ 290 $ 140
Interest cost on projected benefit obligation.. 150 157 160
Actual loss (return) on plan assets............ (145) 70 (369)
Net amortization of unrecognized obligation and
deferral...................................... 28 (216) 347
Curtailment gain............................... -- -- (735)
------- ------- -------
Net periodic pension cost (benefit).............. $ 379 $ 301 $ (457)
======= ======= =======
</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 was 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

F-14
<PAGE>

BARRETT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

(INFORMATION FOR THE NINE MONTH PERIODS ENDED
SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED)

employees, directors and 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 polices, 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 fol-
lowing components:
Service cost of benefits earned......................... $ 41
Interest cost on accumulated post-retirement benefit ob-
ligation............................................... 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.

F-15
<PAGE>

BARRETT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

(INFORMATION FOR THE NINE MONTH PERIODS ENDED
SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED)

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.

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 the first nine months of 1996, the Company recognized net production
hedging expense of $1.5 million which was recorded in the consolidated
statements of income as adjustments of gas and

F-16
<PAGE>

BARRETT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

(INFORMATION FOR THE NINE MONTH PERIODS ENDED
SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED)

oil production revenue. As of September 30, 1996, the Company held positions
to hedge production of approximately 11.5 Bcf of gas through October 1997.

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."

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.

In March 1996, these two putative class actions were dismissed without
prejudice. No defendant paid any consideration for such dismissals.

F-17
<PAGE>

BARRETT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

(INFORMATION FOR THE NINE MONTH PERIODS ENDED
SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED)

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.

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>
1993 1994 1995
------ ------ ------
(IN THOUSANDS)
<S> <C> <C> <C>
Current:
Federal.............................................. $ 174 $ 233 $ 269
State................................................ 416 117 (233)
------ ------ ------
590 350 36
Deferred:
Federal.............................................. 5,138 4,511 2,039
State................................................ 993 277 (241)
------ ------ ------
6,131 4,788 1,798
------ ------ ------
$6,721 $5,138 $1,834
====== ====== ======
</TABLE>

F-18
<PAGE>

BARRETT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

(INFORMATION FOR THE NINE MONTH PERIODS ENDED
SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED)

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>
1993 1994 1995
------- ------- ------
(IN THOUSANDS)
<S> <C> <C> <C>
Tax by applying the statutory federal income tax
rate to pretax accounting income (loss)........ $ 7,365 $ 5,753 $ (138)
Increase (decrease) in tax from:
Change in valuation allowance................. (1,477) (2,148) 396
State income taxes............................ 1,409 394 (474)
Non-deductible merger costs................... -- -- 2,429
Other, net.................................... (576) 1,139 (379)
------- ------- ------
$ 6,721 $ 5,138 $1,834
======= ======= ======
</TABLE>

Long-term deferred tax assets (liabilities) are comprised of the following
at December 31, 1995 and 1994:

<TABLE>
<CAPTION>
1994 1995
-------- --------
(IN THOUSANDS)
<S> <C> <C>
Deferred tax assets:
Allowance for losses.................................. $ 624 $ 81
Loss carryforwards and other.......................... 30,221 26,520
-------- --------
Gross deferred tax assets........................... 30,845 26,601
Deferred tax liabilities:
Deferred revenue--partnership activities.............. (1,086) (466)
Depreciation, depletion and amortization.............. (50,650) (48,460)
Capitalized interest on other assets.................. (38) (6)
-------- --------
Gross deferred tax liabilities...................... (51,774) (48,932)
-------- --------
Net deferred tax liability........................ (20,929) (22,331)
Valuation allowance............................... (797) (1,193)
-------- --------
$(21,726) $(23,524)
======== ========
</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.

F-19
<PAGE>

BARRETT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

(INFORMATION FOR THE NINE MONTH PERIODS ENDED
SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED)

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 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") has examined the federal tax returns of
Plains Petroleum Company, a subsidiary of Barrett Resources Corporation, for
the pre-merger calendar years 1991, 1992 and 1993. The IRS issued a "Notice of
Deficiency" of $5.3 million together with penalties of $1.1 million, and an
undetermined amount of interest. The IRS notice of deficiency resulted
primarily from the IRS's disallowance of certain net operating loss deductions
claimed during the periods under examination. These net operating losses
originally had been incurred by a company that was acquired by Plains in 1986.
The Company currently has additional unused net operating loss carryforwards
of approximately $30 million related to the same acquisition.

Management disagrees with the IRS position. In management's opinion, the
federal tax returns of Plains reflect the proper federal income tax liability
and the existing net operating loss carryforwards are appropriate as supported
by relevant authority. The Company will vigorously contest these proposed
adjustments and believes it will prevail in its positions. It is anticipated
that the final

F-20
<PAGE>

BARRETT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

(INFORMATION FOR THE NINE MONTH PERIODS ENDED
SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED)

determination of this matter will involve a lengthy process. On November 29,
1996 the Company filed a petition with the United States Tax Court to request
the IRS notice of deficiency be redetermined by allowing the net operating
losses deductions as originally reported.

During the nine months ended September 30, 1996 the Company acquired oil and
gas properties in purchase transactions that qualify as tax-free exchanges for
tax purposes. The Company deferred income taxes payable of $10.1 million for
the estimated income tax effect of the difference between the financial and
tax basis of the properties acquired.

12. SUPPLEMENTAL CASH FLOW SCHEDULES AND INFORMATION

CASH PAID DURING YEARS:

<TABLE>
<CAPTION>
1994 1995 1996
---- ---- ------
(IN THOUSANDS)
<S> <C> <C> <C>
Income taxes................................................ $426 $338 $ 65
Interest.................................................... 792 711 5,129
</TABLE>

SUPPLEMENTAL INFORMATION OF NONCASH INVESTING AND FINANCING ACTIVITIES:

<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
----------------------- ------------------
1993 1994 1995 1995 1996
------- ------- ------- -------- ---------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Issuance of common stock for
property and related deferred
taxes......................... $ -- $ -- $ -- $ -- $ 31,603
Treasury shares purchased in
option transactions........... 204 313 545 157 527
</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.

F-21
<PAGE>

BARRETT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONCLUDED)

(INFORMATION FOR THE NINE MONTH PERIODS ENDED
SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED)

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 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-22
<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>
1993 1994 1995
-------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Acquisition of evaluated properties............... $ 6,119 $35,234 $ 7,429
Acquisition of unevaluated properties............. 1,013 8,446 8,383
Exploration costs................................. 12,593 36,232 23,272
Development costs................................. 21,538 20,190 33,029
Other, principally proceeds from mineral convey-
ances............................................ (15,680) (173) (426)
-------- ------- -------
Total additions to oil and gas properties....... $ 25,583 $99,929 $71,687
======== ======= =======
</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>
1993 1994 1995
--------------------- --------------------- ---------------------
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....... 10,553 370,621 6,947 364,791 11,444 458,820
Revisions of previous
estimates.............. (3,426) (5,418) 772 (5,640) 1,209 (3,805)
Purchase of minerals in
place.................. 217 6,794 2,533 38,717 831 3,983
Extensions and discover-
ies.................... 1,208 28,482 2,547 94,276 1,232 102,329
Production.............. (1,293) (31,712) (1,293) (33,282) (1,702) (47,692)
Sale of minerals in
place.................. (312) (3,976) (62) (42) (47) (104)
------ ------- ------ ------- ------ -------
End of year............. 6,947 364,791 11,444 458,820 12,967 513,531
====== ======= ====== ======= ====== =======
Proved developed re-
serves:
Beginning of year....... 7,398 350,131 5,548 342,287 7,848 393,051
====== ======= ====== ======= ====== =======
End of year............. 5,548 342,287 7,848 393,051 11,669 419,672
====== ======= ====== ======= ====== =======
</TABLE>

F-23
<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>
1993 1994 1995
--------- --------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows...................... $ 789,693 $ 931,404 $1,132,711
Future production costs.................. (266,920) (310,485) (355,756)
Future development costs................. (22,349) (41,972) (46,888)
Future income tax expenses............... (135,165) (152,890) (207,922)
--------- --------- ----------
Future net cash flows.................. 365,259 426,057 522,145
10% annual discount for estimated timing
of cash flows........................... (162,173) (183,436) (212,271)
--------- --------- ----------
Standardized measure of discounted future
net cash flows.......................... $ 203,086 $ 242,621 $ 309,874
========= ========= ==========
</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>
1993 1994 1995
-------- --------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Net change in sales price and production
costs...................................... $ 12,283 $ (22,409) $ 24,558
Changes in estimated future development
costs...................................... 11,160 14,492 10,301
Sales and transfers of oil and gas produced,
net of production costs.................... (53,594) (50,571) (62,294)
Net change due to extensions and discover-
ies........................................ 20,739 60,613 85,524
Net change due to purchases and sales of
minerals in place.......................... (1,210) 32,726 7,424
Net change due to revisions in quantities... (18,272) (588) (1,393)
Net change in income taxes.................. (4,711) (10,202) (33,172)
Accretion of discount....................... 26,965 27,589 23,112
Other, principally revisions in estimates of
timing of production....................... 5,859 (12,115) 13,193
-------- --------- --------
Net changes................................. (781) 39,535 67,253
Balance, beginning of year.................. 203,867 203,086 242,621
-------- --------- --------
Balance, end of year........................ $203,086 $ 242,621 $309,874
======== ========= ========
</TABLE>

F-24
<PAGE>

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NO PERSON HAS BEEN AUTHORIZED TO GIVE ANY INFORMATION OR TO MAKE ANY REPRE-
SENTATIONS OTHER THAN THOSE CONTAINED IN THIS PROSPECTUS, AND, IF GIVEN OR
MADE, SUCH INFORMATION OR REPRESENTATIONS MUST NOT BE RELIED UPON AS HAVING
BEEN AUTHORIZED. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL OR THE
SOLICITATION OF AN OFFER TO BUY ANY SECURITIES OTHER THAN THE SECURITIES TO
WHICH IT RELATES OR AN OFFER TO SELL OR THE SOLICITATION OF AN OFFER TO BUY
SUCH SECURITIES IN ANY CIRCUMSTANCES IN WHICH SUCH OFFER OR SOLICITATION IS
UNLAWFUL. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE HEREUNDER
SHALL, UNDER ANY CIRCUMSTANCES, CREATE ANY IMPLICATION THAT THERE HAS BEEN NO
CHANGE IN THE AFFAIRS OF THE COMPANY SINCE THE DATE HEREOF OR THAT THE INFOR-
MATION CONTAINED HEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT TO ITS DATE.

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

TABLE OF CONTENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Prospectus Summary....................................................... 3
Risk Factors............................................................. 9
Use of Proceeds.......................................................... 12
Capitalization........................................................... 13
Management's Discussion and Analysis of Financial Condition and Results
of Operations........................................................... 14
Disclosure Regarding Forward-Looking Statements.......................... 19
Business and Properties.................................................. 20
Management............................................................... 37
Beneficial Owners of Securities.......................................... 41
Description of Notes..................................................... 43
Underwriting............................................................. 53
Legal Matters............................................................ 54
Experts.................................................................. 54
Available Information.................................................... 54
Incorporation of Certain Documents by Reference.......................... 55
Certain Definitions...................................................... 55
Index to Consolidated Financial Statements............................... F-1
</TABLE>

$150,000,000

BARRETT RESOURCES CORPORATION

7.55% SENIOR NOTES
DUE 2007

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[LOGO OF BARRETT RESOURCES CORPORATION APPEARS HERE]

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

GOLDMAN, SACHS & CO.

CHASE SECURITIES INC.

LEHMAN BROTHERS

PETRIE PARKMAN & CO.

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