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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
[X]ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For Year Ended December 31, 1999
or
[_]TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the Transition Period from to
Commission File No. 1-13446
BARRETT RESOURCES CORPORATION
(Exact name of registrant as specified in its charter)
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Delaware 84-0832476
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1515 Arapahoe Street,
Tower 3, Suite 1000
Denver, Colorado 80202
(Address of principal executive offices) (Zip Code)
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(303) 572-3900
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
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Title of Each Class Name of Exchange on which registered:
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Common Stock ($.01 Par Value Per Share) New York Stock Exchange, Inc.
Preferred Stock Purchase Rights
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Securities registered pursuant to Section 12(g) of the Act:
(None)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes [X] No [_]
Indicate by check mark if there are no delinquent filers to disclose herein
pursuant to Item 405 of Regulation S-K, and there will not be any delinquent
filers to disclose, to the best of registrant's knowledge, in definitive proxy
or information statements incorporated by reference in Part III of this Form
10-K or any amendment to this Form 10-K. [X]
As of March 15, 2000, the Registrant had 32,601,589 common shares
outstanding, and the aggregate market value of the common shares held by non-
affiliates was approximately $735,082,680. This calculation is based upon the
closing sale price of $24.00 per share for the stock on March 15, 2000.
Without asserting that any director or executive officer of the issuer is an
affiliate, the shares of which they are the beneficial owners have been deemed
to be owned by affiliates solely for this calculation.
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TABLE OF CONTENTS
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Item Page
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PART I
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1 and 2. Business and Properties....................................... 1
3. Legal Proceedings............................................. 16
4. Submission of Matters to Vote of Security Holders............. 16
PART II
Market for Registrant's Common Stock and Related Security
5. Holders Matters............................................... 17
6. Selected Financial Data....................................... 17
Management's Discussion and Analysis of Financial Condition
7. and Results of Operations..................................... 17
8. Financial Statements and Supplementary Data................... 22
Changes in and Disagreements with Accountants on Accounting
9. and Financial Disclosure...................................... 22
PART III
10. Directors and Executive Officers of the Company............... 23
11. Executive Compensation........................................ 27
Security Ownership of Certain Beneficial Owners and
12. Management.................................................... 31
13. Certain Relationships and Related Transactions................ 32
PART IV
Exhibits, Financial Statement Schedules, and Reports on Form
14. 8-K........................................................... 33
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PART I
Items 1. and 2. Business and Properties
Barrett Resources Corporation (the "Company" or "Barrett", which reference
shall include the Company's wholly owned subsidiaries) was incorporated in
December 1980 as an oil and gas company under the name AIMEXCO Inc. and became
publicly owned with a $5.8 million common stock offering in May 1981. In
December 1983, AIMEXCO acquired all the common stock of Barrett Energy
Company, which owned a number of oil and gas properties, in exchange for 71.5
percent of the common stock of AIMEXCO that was outstanding after the
transaction. In January 1984, the Company changed its name to Barrett
Resources Corporation.
In November 1985, the Company acquired Excel Energy Corporation, a Utah
corporation that owned oil and gas interests, in exchange for approximately
1,425,000 shares of the Company's common stock. In June 1987, the Company
acquired all the outstanding stock of Finance For Energy, Ltd., whose assets
consisted primarily of cash and mortgages, in exchange for 1,174,100 shares of
the Company's common stock.
In September 1987, the Company effected a one-for-twenty reverse stock
split of the Company's common shares and changed the par value of its common
stock to $.01 per share. All prior references in this Item to numbers of
shares of the Company's common stock have been adjusted for the effect of this
one-for-twenty reverse stock split.
In May 1990, the Company completed the public offering of 3,565,000 shares
of its common stock for $21.3 million, net of the underwriting discount. In
March 1993, the Company completed the public offering of an additional two
million shares of its common stock for $19.2 million, net of the underwriting
discount.
In July 1995, the Company completed the merger of the Company and Plains
Petroleum Company ("Plains") pursuant to which Plains became a wholly owned
subsidiary of the Company. The Company issued 12.8 million shares of common
stock in exchange for all the outstanding shares of Plains.
In June 1996, the Company completed the public offering of 5.4 million
shares of its common stock for $135 million, net of the underwriting discount.
In February 1997, the Company completed the public offering of $150 million
of its 7.55% Senior Notes due 2007.
Oil and Gas Exploration and Development
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 and the Mid-Continent Region of Kansas and
Oklahoma. At December 31, 1999, the Company's estimated proved reserves were
1,133.8 Bcfe (95% natural gas and 5% crude oil) with an implied reserve life
of 11.0 years based on 1999 total production of 103.5 Bcfe. The Company's net
daily production averaged 284 MMcfe for the year ended December 31, 1999.
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 Wind River Basin in central Wyoming, and
the Powder River Basin of northeastern Wyoming. The Company also has
significant interests in the Hugoton Embayment in southwestern Kansas, the
Niobrara play in northeastern Colorado, and the Anadarko Basin in Oklahoma. At
December 31, 1999, these principal areas of focus represented approximately
90% of the Company's estimated proved reserves.
As of December 31, 1999, the Company owned an interest in 3,448 wells, of
which 2,600 were producing. Of these producing wells, 1,774 were operated by
the Company. These operated wells contributed approximately 81% of the
Company's natural gas and oil production for the year ended December 31, 1999.
The Company also owns and operates a natural gas gathering system, a 27-mile
pipeline and a natural gas processing plant in the Piceance Basin.
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Barrett markets all of its own natural gas and oil production from wells
that it operates. In addition, the Company engages in natural gas marketing
and 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 marketing and 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."
Employees and Offices
As of February 15, 2000, the Company had 202 full time employees, including
nine officers (two of whom are geologists and three of whom are petroleum
engineers), 11 geologists, four geophysicists, 14 engineers, an environmental
manager, eight landmen, four district managers, an 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.
Core Areas of Activity
The following table sets forth reserve and production concerning the
Company's core areas of activity:
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Average Daily
Production for Estimated Proved Estimated Proved
Year Ended Reserves at Reserves at
Basin or Field December 31, 1999 December 31, 1999 December 31, 1998
-------------- ----------------- ----------------- -----------------
(MMcfe) (Bcfe) (Bcfe)
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Rocky Mountain Region
Wind River............ 54.2 126.3 137.3
Piceance.............. 58.7 461.1 315.3
Powder River-Oil...... 12.0 17.7 11.9
Powder River-CBM...... 37.1 231.0 142.6
Green River........... 2.8 11.9 15.2
Uinta................. 6.1 41.0 42.2
Niobrara.............. 5.5 25.4 24.6
Mid-Continent Region
Arkoma................ 10.2 19.7 26.0
Anadarko.............. 21.0 17.0 25.4
Hugoton Embayment..... 37.1 142.3 172.1
Permian (1)........... 7.3 11.9 11.7
Gulf of Mexico Region... 29.6 23.5 39.0
Other Natural Gas and
Oil Activities (2)..... 2.1 5.0 7.0
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Total................... 283.7 1,133.8 970.3
===== ======= =====
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(1) The Permian Basin properties were divested in two transactions completed
in February and March 2000 for a total sale price of $16.3 million.
(2) The only significant property in this category is the Meeteetse Field in
the Big Horn Basin, Wyoming.
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 and development
program in the Wind River Basin of central Wyoming, particularly along the Owl
Creek Thrust fault. The Company has continued to acquire additional acreage in
this core area and currently owns working interests ranging from 25% to 100%
in 12,650 gross (9,617 net) leasehold acres in the Cave Gulch area, including
a 94% working interest in the Cave Gulch Federal Unit covering the Fort Union
and Lance Sandstones.
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Cave Gulch Area. In 1999, the Company continued its shallow development
program by drilling seven shallow Ft. Union wells (six have been completed and
one is waiting on completion), and one Mesaverde well. The Company's working
interest in the shallow Ft. Union play ranges from 70% to 100%. Through
December 1999, the Company has operated and completed a total of 23 Lance
wells, seven shallow Ft. Union wells and one Mesaverde well. In October 1999,
the Company returned the Cave Gulch 1-29, a well that blew out in August 1998,
to sales. The Company owns a 70% working interest in this well.
The Company's sixth Cave Gulch area deep test, the Cave Gulch 11-28,
reached total depth of 19,575 and was placed on production in November 1999.
The Company owns a 94.8% working interest in this well.
The Cave Gulch 3-29 was completed in the Muddy Formation in October 1998.
In March 1999, the Wyoming Oil and Gas Conservation Commission approved a 160-
acre statutory unit allowing for continuous production from the 3-29 Muddy
Formation. However, the Commission established production limits commensurate
with the unit size: Muddy (9.75 Bcf), Lakota (5.00 Bcf), Frontier (6.25 Bcf).
The Muddy Formation has produced 8.5 Bcf to date. It is anticipated that late
in the first quarter 2000, the Muddy Formation will have to be shut in and
production will move uphole to the Frontier Formation. Barrett's working
interest in this well is 79.3%.
On the east flank of the Cave Gulch Field, the Moncrief Cave Gulch Federal
28-1 reached total depth of 18,919 feet in the Lakota Formation in October
1999. The Lakota was fracture stimulated and comingled with the Muddy
Formation. The Frontier sands will be tested at a future date. The Company
owns a 34% working interest in this well.
Waltman Area. During early 1999, the Company completed its interpretation
of a 62 square mile 3-D seismic survey covering lands south of Cave Gulch in
the Waltman area. As a result of that 3-D seismic effort, the Company drilled
a deep exploratory Frontier-Muddy-Lakota test, the Bullfrog 5-12,
approximately four miles south of the Cave Gulch Field in the Federal Bullfrog
unit. The well reached a total depth of 19,550 feet in December 1999. The pay
horizons were encountered over 900 feet high to the nearest offsetting well.
Structural position, mud, gas, and electric log shows were encouraging; but
testing results of the lower formation sands proved to be discouraging as
excessive water rates and tight sands were encountered. However, the Company
plans on testing the remaining sand interval in late March. Following analysis
of the testing results, the Company will determine future plans for the deep
Waltman area. The Company owns a 82.1% working interest in this well.
Utilizing the 3-D survey, the Company defined an exploratory Mesaverde
target location west of the Bullfrog 5-12. The Bullfrog 4-14 well was drilled
to a depth of 12,375 feet in the Cody Formation during December 1999. Testing
of the target sands proved the formation to be non-productive. The Company
owns a 93.6% working interest in this well.
Owl Creek Thrust. During 1999, the Company entered into an agreement with a
third party to acquire, at third party's sole cost, a 100 square mile 3-D
seismic survey (the Cedar Ridge 3-D) covering the East Madden Prospect in
exchange for certain leasehold along the Owl Creek Thrust. The Company
retained a 33.3% working interest in the East Madden Field in the event an
exploratory test is proposed. The Company will continue to evaluate additional
exploration prospects along the Owl Creek Thrust.
During 1999, the Company upgraded its field production facilities in Cave
Gulch to give it the ability to maintain its present production volumes while
preparing to transport increased gas volumes from on-going field development
projects.
At December 31, 1999, the Wind River Basin represented 11% of the Company's
estimated proven reserves and 19% of the Company's total 1999 production. The
Company intends to spend 10% of its estimated $166 million 2000 capital budget
in the Wind River Basin for development, leasehold acquisition, seismic
surveys and exploration. The Company plans to drill one deep Frontier-Muddy-
Lakota test and two shallow Fort Union-Lance wells in 2000.
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Piceance Basin. The Piceance Basin of northwestern Colorado is a core
operating area for the Company. 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. The Company drilled its first well in the Piceance Basin in 1984, and
at December 31, 1999, owned interests in 479 wells, 439 of which it operates.
The Company's 2000 plans call for drilling or participating in 61 Williams
Fork wells and one horizontal Corcoran well. Four drilling rigs will be in
continuous operation in the Basin during 2000.
In May 1999, the Company acquired approximately 8,400 net acres from the
Naval Oil Shale Reserve for $7.1MM. The acreage included an estimated 20 Bcf
of gas reserves from 59 operated and non-operated wells and development
locations.
In December 1999, the Company acquired 140 Bcf of gas reserves (43% proved
developed), most of which represented additional interests in wells operated
by the Company. In January 2000, the Company acquired an additional 32 Bcf of
gas reserves (46% proved developed), virtually all of which were additional
interests in wells operated by the Company. Also in January 2000, the Company
acquired the remaining interests in the Grand Valley Gathering System (see
below). The total purchase price for these acquisitions was $83.0 million.
At December 31, 1999, the Piceance Basin represented 41% of the Company's
estimated proved reserves, and 21% of the Company's total 1999 production.
Year-end 1999 production from the basin was 100 MMcfd gross. The Company
intends to spend 54% of its 2000 capital expenditure budget in the Piceance
Basin for development and exploration and will participate in the drilling of
62 wells.
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. Through a series
of acquisitions culminating in January 2000, the Company has acquired all the
outstanding interests in this system. As of December 31, 1999, the Grand
Valley Gathering System was connected to 352 producing wells. The system now
has the flexibility to deliver natural gas to four interstate pipelines as
well as Public Service of Colorado's ("PSCo") western Colorado distribution
system. Subject to the take-away capacity of the four interstate pipelines and
the PSCo line, this system has the capability of delivering over 150 MMcfd gas
per day.
Powder River Basin. In the Powder River Basin of northeastern Wyoming, the
Company is active in a coal bed methane ("CBM") program and an oil exploration
and development program.
Coal Bed Methane. In October 1997, the Company entered into a joint
development agreement to participate, with a 50% working interest, in a CBM
project covering a 2.1 million acre area of mutual interest ("AMI") located
north and south of Gillette, Wyoming. In 1999, the Company continued expansion
of its CBM leasehold position with its joint development partner to over
940,000 gross acres (435,000 net). The coal seams lie 300 to 2,000 feet below
the surface, making drilling and completion of the wells highly economic. In
1999, the Company participated in the drilling of 586 wells. Of this total,
193 were producing and 391 wells are waiting on pipeline connection. A total
of 667 CBM wells were producing at year-end 1999.
The Bureau of Land Management ("BLM") required an Environmental Impact
Study ("EIS") prior to approving additional drilling on Federal leases in the
Powder River Basin. Approximately half of the Company's acreage in the Powder
River Basin is on Federal leases. The Record of Decision ("ROD") for the
Wyodak EIS was issued in November 1999. Due to a greater than expected
development on fee and State lands, industry development on Federal lands is
limited to approximately 890 additional wells. In the case where Federal
acreage is being drained from adjoining fee and State locations, the BLM may
in the future decide to permit the drilling of additional "drainage protection
wells" on Federal lands. The joint venture anticipates approval of three
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applications for permitting which will allow the drilling of approximately 100
wells on Federal lands during 2000. In addition, Barrett has recently
submitted 245 additional "drainage" locations needed to prevent drainage of
reserves from beneath Federal lands. A new basin-wide EIS is contemplated and
is expected to be completed by January 2002. The Company, along with its joint
venture partner, have a sufficient inventory of fee and State lease locations
to permit the drilling of approximately 800 wells per year in 2000 and 2001.
Additionally, the Company has a 10% working interest in the new 90-mile
Fort Union Gas Gathering System that was completed in September 1999.
At December 31, 1999, the Powder River Basin CBM play represented 20% of
the Company's proved reserves and 13% of the Company's total 1999 production
The Company intends to spend 23% of its 2000 capital expenditure budget in the
CBM project by participating in approximately 800 wells.
Minnelusa Play--North Halverson Area. The Company has initiated a multi-
well drilling program targeting the oil producing Minnelusa Formation. The
Company has drilled two wells and plans to drill up to four wells to an
average depth of 8,700 feet. The first well is producing 200 barrels of oil
per day. The Company owns a 100% working interest in this well. The second
well, in which the Company also owns a 100% working interest, was unsuccessful
and has been plugged. The Company's working interest in the four remaining
locations averages 72%. The locations are based on a 3-D seismic survey
acquired by the Company in 1997.
On December 31, 1999, the Powder River Basin conventional oil operations
represented 2% of the Company's proved reserves, and 4% of the Company's total
1999 production (Minnelusa production contributed approximately 39% of the
Company's 1999 daily oil production). The Company intends to spend 1% of its
2000 capital budget in the Minnelusa play.
Hanna Basin. During 1999, the Company assembled over 42,000 net acres in
the Hanna Basin, which is located just east of the Greater Green River Basin
in Carbon County, Wyoming. The Hanna Formation (Ft.Union-age equivalent)
contains over 130 net feet of coal in four separate coal seams at depths
ranging from 1,000 feet to 4,500 feet. Excellent permeability was demonstrated
at the deeper depths in 1993 during a short-term de-watering attempt by
another operator. Water quality was found to be potable during this test. The
target coal seams appear to contain higher gas contents than the Powder River
coal beds, and this gas appears to be of good quality.
During December 1999, the Company sold 49% of its working interest to an
industry partner. During the first half 2000, the Company intends to drill and
operate the 3,600 foot Hanna Draw Unit #1 well, an exploratory coal bed
methane core test. If the results of this core test are encouraging, the
Company anticipates drilling a six-well pilot during 2000. The Company intends
to spend 1% of its 2000 capital budget in the Hanna Basin for the drilling of
seven wells.
Uinta Basin. As an extension of its Piceance Basin operations, the Company
entered the Uinta Basin of Duchesne and Uintah Counties, in northeastern Utah,
in 1995. The Douglas Creek Arch separates the Uinta Basin from the Piceance
Basin.
Brundage Canyon Field. Beginning in December 1995, the Company began
acquiring interests in the Brundage Canyon Field. As a result of these
acquisitions and new drilling, the Company currently owns working interests
ranging from 75% to 100% in 35 producing wells, a gathering and transmission
system, and 54,605 gross and 53,409 net acres. Wells in this field produce oil
and associated natural gas from multiple sandstone reservoirs of the lower
Green River Formation at depths averaging 5,500 feet. The Company has
initiated a plan to develop its leasehold position in the Brundage Canyon
Field. The plan includes both testing the feasibility of horizontal drilling
and, separately, the application of secondary waterflood technology to improve
recovery efficiencies from the Lower Green River reservoirs.
On December 31, 1999, the Brundage Canyon Field represented 4% of the
Company's estimated proved reserves, and 2% of the Company's total 1999
production. The Company intends to spend 3% of its 2000 capital
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budget on Brundage Canyon field development, including the drilling of 29
wells and construction of related facilities and infrastructure.
Northeastern Colorado--Niobrara. During 1999, the Company continued its
Niobrara exploration and development program in northeastern Colorado. This is
a shallow natural gas play targeting a 20 to 50 foot thick chalk reservoir in
the Upper Cretaceous Niobrara Formation. During 1999, the Company acquired 40
miles of proprietary seismic data and 685 miles of trade seismic data. The
Company drilled 20 wells during 1999, of which 17 were successful.
At December 31, 1999, the Niobrara represented 2% of the Company's
estimated proved reserves, and 2% of the Company's total 1999 production. The
Company intends to spend 1% of its 2000 capital budget in the play for the
drilling of 10 wells, and to acquire additional leases and seismic data.
Mid-Continent Region
Hugoton Embayment. The Hugoton Embayment is the third largest producing
area for the Company and is one of the largest natural gas producing areas in
the United States. It is located in southwest Kansas, the Oklahoma panhandle
and the Texas panhandle. The Company produces natural gas from two fields in
the Hugoton Embayment: the Hugoton and Panoma Fields.
Hugoton Field. In the Hugoton Field, the Company has a working interest in
342 gross wells and operates 293 of these wells, that produce from the Chase
Formation. Three wells were drilled and placed on production during 1999.
Panoma Field. Panoma is the field designation for natural gas produced from
the Council Grove Formation, located beneath the Chase Formation. The Council
Grove Formation has similar reservoir rocks as the Chase Formation. However,
the productive limits are not as extensive. Presently, the Company has a
working interest in 55 gross Panoma wells and operates 51 of those wells.
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 KN Energy, Inc. ("KN") on October 1, 1984, subject to
a payment of $0.06 per Mcf for natural gas produced from the acreage.
Quarterly payments are made by the Company to the Hugoton Gas Trust, a
publicly held trust created in 1955. Payments terminate when the estimated
gross recoverable natural gas reserves decline to 50 Bcf or less. As of
December 31, 1999, the gross proved natural gas reserves attributable to the
leases burdened by this agreement were estimated to be 101 Bcf. The natural
gas payments are treated as lease operating expenses by the Company. At
December 31, 1999, the Company had working interests in 196 wells that were
subject to these payments.
At December 31, 1999, the Hugoton Embayment represented 13% of the
Company's estimated proved reserves and 13% of the Company's total 1999
production. The Company intends to spend less than 1% of its 2000 capital
expenditure budget in the Hugoton Embayment.
Anadarko Basin. During 1999, the Company participated in the drilling of 14
wells in the Anadarko Basin with working interests ranging from 3% to 48%. Of
the 14 gas wells drilled, 13 were completed as producers and one was
unsuccessful. The Company remains active in the Mountain Front Springer play.
At December 31, 1999, the Anadarko Basin represented 2% of the Company's
estimated proved reserves, and 7% of the Company's total 1999 production. The
Company intends to spend 1% of its 2000 capital expenditure budget for the
drilling of five wells, leasehold acquisitions and seismic surveys.
Arkoma Basin. During 1999, the Company participated in the drilling of two
wells in the Arkoma Basin. One was completed as a gas well and one was
unsuccessful.
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At December 31, 1999, the Arkoma Basin represented 2% of the Company's
estimated proved reserves, and 4% of the Company's total 1999 production. The
Company does not intend to spend any of its 2000 capital budget in the Arkoma
Basin.
Permian Basin. The Permian Basin, located in west Texas and southeast New
Mexico, is primarily an oil province. At December 31, 1999, the Permian Basin
represented 1% of the Company's estimated proved reserves, and 3% of the
Company's total 1999 production. In two transactions that closed in February
and March 2000, the Company sold all of its Permian Basin properties for a
total of $16.3 million.
Gulf of Mexico Region
During 1999, the Company did not participate in the drilling of any wells.
In April, the Company sold its interest in Ship Shoal Block 45 Field for $4.0
million. In October, the Company entered into an agreement with HTK
Consultants to manage its Gulf of Mexico production, which is currently at 22
MMcfed net to the Company's interests. In November 1999, Barrett sold its
undeveloped lease inventory, which consisted of 30 blocks and 81,800 net
acres, for $7.0 million. The Company has identified three low risk projects
for possible drilling in 2000 and will participate in the sidetracking or re-
completion of eight wells.
At December 31, 1999, the Gulf of Mexico represented 2% of the Company's
estimated proved reserves, and 10% of the Company's total 1999 production. The
Company intends to spend 1% of its 2000 capital budget in the Gulf of Mexico.
International Operations
In January 1997, the Company entered into an agreement with industry
partners that provided the Company with a 45% working interest in Block 67,
covering two million gross acres in the Maranon Basin of northeastern Peru. In
March 1998, the Company acquired an additional working interest totaling 25%.
During 1998, the Company drilled and temporarily abandoned three exploratory
wells, each of which resulted in a significant oil discovery in Cretaceous and
basal Tertiary Sandstone reservoirs. The Dorado 67-35-1X encountered 71 feet
of net pay containing 14-16 degree API oil; the Pirana 67-42-1X encountered 84
feet of net pay containing 12-21 degree API oil; the Paiche 67-20-1X
encountered 179 feet of net pay containing 12-13 degree API oil and
inflammable gas. Analysis of drillstem tests through production casing
indicates that each of these wells are capable of production rates of 1,000 to
5,000 barrels of oil per day on pump. The Company has completed a feasibility
study identifying potential pipeline routes, upgrading processes, and
development plans needed to initiate production from Block 67, and is
currently seeking an industry partner with heavy oil expertise to assist in
carrying the project forward through continued seismic acquisition and
exploratory/exploitation drilling. In May, 1999, as required under the license
agreement, Barrett relinquished 30% of the acreage within Block 67, reducing
the acreage within Block 67 to 1.4 million acres. The area relinquished was
considered non-prospective. Current oil prices make it economic to further
pursue exploration and development of Block 67. All contractual work
obligations associated with the Block 67 license have been satisfied through
June 2000. During May 2000, Barrett must commit to the drilling of a fourth
exploratory well or relinquish that portion of Block 67 outside of the three
fields discovered to date.
During September 1999, the Company entered into a contract to acquire Block
39, a new license area covering approximately 1.0 million acres, located
immediately to the south and east of Block 67. During the first year of the
contract, Barrett is obligated to reprocess 1200 kilometers of existing 2-D
seismic data. By August 2001, the Company must commit to the acquisition of an
additional 350 kilometers of 2-D seismic or relinquish Block 39. The Company
is offering this acreage to a potential partner as part of its sell-down
efforts in Block 67.
Certain Definitions
Unless otherwise indicated in this document, natural gas volumes are stated
at the legal pressure base of the state or area in which the reserves are
located at 60 Fahrenheit. Natural gas equivalents are determined using the
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ratio of six Mcf of natural gas to one barrel of crude oil, condensate or
natural gas liquids so that one barrel of oil is referred to as six Mcf of
natural gas equivalent or "Mcfe."
As used in this document, the following terms have the following specific
meanings: "Mcf" means thousand cubic feet of gas, "Mcfe" means thousand cubic
feet of gas equivalent, "Mcfed" means thousand cubic feet of gas equivalent
per day, "MMcf" means million cubic feet of gas, "MMcfd" means million cubic
feet of gas per day, "MMcfe" means million cubic feet of gas equivalent,
"MMcfed" means million cubic feet of gas equivalent per day, "Bbl" means
barrel of oil, "MBbl" means thousand barrels of oil, "BOPD" means barrels of
oil per day, "MMBtu" means million British thermal units, "Bcf" means billion
cubic feet of gas and "Bcfe" means billion cubic feet of gas equivalent.
With respect to information concerning the Company's working interests in
wells or drilling locations, "gross" natural gas and oil wells or "gross"
acres is the number of wells or acres in which the Company has an interest,
and "net" gas and oil wells or "net" acres are determined by multiplying
"gross" wells or acres by the Company's working interest in those wells or
acres. A working interest in an oil and natural gas lease is an interest that
gives the owner the right to drill, produce, and conduct operating activities
on the property and to receive a share of production of any hydrocarbons
covered by the lease. A working interest in an oil and gas lease also entitles
its owner to a proportionate interest in any well located on the lands covered
by the lease, subject to all royalties, overriding royalties and other
burdens, to all costs and expenses of exploration, development and operation
of any well located on the lease, and to all risks in connection therewith.
"Capital expenditures" means costs associated with exploratory and
development drilling (including exploratory dry holes); leasehold
acquisitions; seismic data acquisitions; geological, geophysical and land
related overhead expenditures; delay rentals; producing property acquisitions;
and other miscellaneous capital expenditures. "Capital expenditure budget"
means an estimate prepared by management for the total expenditures
anticipated to be incurred during the subject time period. This amount can
deviate or fluctuate due to the timing of drilling of wells, environmental
considerations, acquisition of important fee, state and federal leases, and
natural gas and oil prices.
A "development well" is a well drilled as an additional well to the same
horizon or horizons as other producing wells on a prospect, or a well drilled
on a spacing unit adjacent to a spacing unit with an existing well capable of
commercial production and which is intended to extend the proven limits of a
prospect. An "exploratory well" is a well drilled to find commercially
productive hydrocarbons in an unproved area, or to significantly extend a
known prospect.
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 the Securities and Exchange Commission
guidelines, net of estimated production and future development costs, using
prices and costs as of the date of estimation without future escalation,
without giving effect to non-property related expenses such as general and
administrative expenses, debt service, future income tax expense and
depreciation, depletion and amortization, and discounted using an annual
discount rate of 10%.
A "recompletion" is the completion of an existing well for production from
a formation that exists behind the casing of the well.
"Reserves" means natural gas and crude oil, condensate and natural gas
liquids on a net revenue interest basis, found to be commercially recoverable.
"Proved developed reserves" includes proved developed producing
8
<PAGE>
reserves and proved developed behind-pipe reserves. "Proved developed
producing reserves" includes only those reserves expected to be recovered from
existing completion intervals in existing wells. "Proved undeveloped reserves"
includes those reserves expected to be recovered from new wells on proved
undrilled acreage or from existing wells where a relatively major expenditure
is required for recompletion.
Production
The table below sets forth information with respect to the Company's net
interests in producing natural gas and oil properties for each of its last
three years, respectively:
<TABLE>
<CAPTION>
Natural Gas and Oil Production
--------------------------------
Year Ended December 31,
--------------------------------
1999 1998 1997
---------- ---------- ----------
<S> <C> <C> <C>
Quantities Produced and Sold
Natural gas (Bcf)........................... 95.0 94.9 76.6
Oil and condensate (MMBbls)................. 1.4 2.0 2.2
Average Sales Price
Natural gas ($/Mcf)......................... $ 1.99 $ 1.92 $ 2.18
Oil and condensate ($/Bbl).................. $ 12.71 $ 11.42 $ 17.69
Average Production Costs ($/Mcfe)............. $ 0.60 $ 0.55 $ 0.64
</TABLE>
Productive Wells
The productive wells in which the Company owned a working interest as of
December 31, 1999 are described in the following table:
<TABLE>
<CAPTION>
Productive Wells(1)
---------------------------
Gas Wells Oil Wells
-------------- ------------
Gross Net Gross Net
----- -------- ----- ------
<S> <C> <C> <C> <C>
Rocky Mountain Region
Wind River........................................ 36 29.24 22 5.56
Piceance.......................................... 455 393.96 0 0.00
Niobrara.......................................... 138 95.62 0 0.00
Powder River-Oil.................................. 19 2.00 260 69.00
Powder River-CBM.................................. 703 338.00 0 0.00
Green River....................................... 17 10.64 0 0.00
Uinta............................................. 0 0.00 37 35.75
Mid-Continent Region
Arkoma............................................ 145 31.92 0 0.00
Anadarko.......................................... 177 39.68 15 1.95
Hugoton Embayment................................. 397 343.20 0 0.00
Permian (2)....................................... 13 9.24 88 75.41
Gulf of Mexico Region............................... 35 11.37 5 0.51
Other............................................... 12 9.00 26 0.22
----- -------- --- ------
Total........................................... 2,147 1,313.87 453 188.40
===== ======== === ======
</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.
(2) The Permian Basin properties were divested in two transactions completed
in February and March 2000 for a total sale price of $16.3 million.
9
<PAGE>
Drilling Activity
The following table summarizes the Company's natural gas and oil drilling
activities, all of which were located in the United States, with the exception
of 3 gross (2.1 net) exploratory wells drilled in the Republic of Peru during
1998:
<TABLE>
<CAPTION>
Wells Drilled
--------------------------------------
Year Ended December 31,
--------------------------------------
1999 1998 1997
------------ ------------ ------------
Gross Net Gross Net Gross Net
----- ------ ----- ------ ----- ------
<S> <C> <C> <C> <C> <C> <C>
Development
Natural gas............................ 660 351.15 372 191.49 224 117.76
Oil.................................... 0 0.00 8 .14 37 25.04
Non-productive......................... 7 4.26 17 8.58 20 11.28
--- ------ --- ------ --- ------
Total................................ 667 355.41 397 200.1 281 154.08
=== ====== === ====== === ======
Exploratory
Natural gas............................ 11 8.94 13 8.52 9 4.19
Oil.................................... 0 0.00 8 3.78 1 0.33
Non-productive......................... 2 0.63 6 3.6 8 5.09
--- ------ --- ------ --- ------
Total................................ 13 9.57 27 15.9 18 9.61
=== ====== === ====== === ======
</TABLE>
In addition, the Company was participating in 13 gross (7.91 net) wells,
which were in the process of being drilled, at December 31, 1999.
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. Approximately 85% of the Company's reserve information as of
December 31, 1999, and all of the Company's reserve information as of December
31, 1998, and December 31, 1997, were reviewed by independent reservoir
engineers. Ryder Scott, an independent reservoir engineer, reviewed the
Company's Hugoton Embayment, Wind River Basin and Piceance Basin year-end 1999
reserve information and all but the Company's coal bed methane reserves in
Wyoming for year-end 1998 and all of the Company's reserves for year-end 1997.
The Powder River Basin coal bed methane reserves were reviewed by Netherland,
Sewell & Associates, Inc., an independent reservoir engineer, as of December
31, 1999 and 1998. The total proved net reserves estimated by the Company as
of December 31, 1999, 1998 and 1997 were within 10% of those reviewed and
estimated by the engineers; however, on a well by well basis, differences of
greater than 10% may exist.
<TABLE>
<CAPTION>
Estimated Proved
Reserves
---------------------
December 31,
---------------------
1999 1998 1997
------- ------ ------
(dollars in millions,
except sales price
data)
<S> <C> <C> <C>
Estimated Proved Reserves
Natural gas (Bcf)...................................... 1,075.9 912.4 851.2
Oil and condensate (MMBbls)............................ 9.7 9.7 18.7
Total (Bcfe)......................................... 1,133.8 970.3 963.2
Proved developed reserves (Bcfe)......................... 698.1 580.4 618.3
Natural gas price as of December 31 ($/Mcf).............. $ 2.06 $ 2.01 $ 2.19
Oil price as of December 31 ($/Bbl)...................... $ 22.01 $19.35 $15.52
Present value of estimated future net revenues
before future income taxes discounted at 10%(1)........ $ 815.0 $627.8 $745.0
Standardized measure of discounted net cash flows(2)..... $ 661.3 $530.6 $564.1
</TABLE>
10
<PAGE>
- --------
(1) The present value of estimated future net revenues on a non-escalated
basis is based on weighted average prices realized by the Company of $2.06
per Mcf of natural gas and $22.01 per Bbl of oil at December 31, 1999, and
$2.01 per Mcf of natural gas and $9.35 per Bbl of oil at December 31, 1998
and $2.19 per Mcf of natural gas and $15.52 per Bbl of oil at December 31,
1997.
(2) The standardized measure of discounted net cash flows prepared by the
Company represents the present value of estimated future net revenues
after income taxes discounted at 10%.
In accordance with applicable requirements of the Securities and Exchange
Commission (the "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 document represents only estimates. Reservoir engineering is
a subjective process of estimating underground accumulations of natural gas
and oil that cannot be measured in an exact manner. The accuracy of any
reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment. As a result, estimates
of different engineers, including those used by the Company, may vary. In
addition, estimates of reserves are subject to revision based upon actual
production, results of future development and exploration activities,
prevailing natural gas and oil prices, operating costs and other factors,
which revisions may be material. Accordingly, reserve estimates are often
different from the quantities of natural gas and oil that are ultimately
recovered and are highly dependent upon the accuracy of the assumptions upon
which they are based.
In general, the volume of production from natural gas and oil properties
owned by the Company declines as reserves are depleted. Except to the extent
the Company acquires additional properties containing proved reserves or
conducts successful exploration and development activities, or both, the
proved reserves of the Company will decline as reserves are produced. Volumes
generated from future activities of the Company are therefore highly dependent
upon the level of success in acquiring or finding additional reserves and the
costs incurred in doing so.
Reference should be made to "Supplemental Oil and Gas Information" on pages
F-21 through F-23 following the Consolidated Financial Statements included in
this document for additional information pertaining to the Company's proved
natural gas and oil reserves as of the end of each of the last three years.
During the past year, the only report concerning the Company's estimated
proved reserves that was filed with a U.S. federal agency other than the
Commission is the Annual Survey of Domestic Oil and Gas Reserves and was filed
with the Energy Information Administration ("EIA") as required by law. Only
minor differences of less than 5% in reserve estimates, which were due to
small variances in actual production versus year end estimates, have occurred
in certain classifications reported in this document as compared to those in
the EIA report.
11
<PAGE>
Developed and Undeveloped Acreage
The gross and net acres of developed and undeveloped natural gas and oil
leases held by the Company as of December 31, 1999 are summarized in the
following table. "Undeveloped Acreage" includes leasehold interests that
already may have been classified as containing proved undeveloped reserves.
<TABLE>
<CAPTION>
Developed Undeveloped Acreage
Acreage (1)
--------------- -------------------
Gross Net Gross Net
------- ------- --------- ---------
<S> <C> <C> <C> <C>
Rocky Mountain Region
Wind River................................ 15,693 10,164 108,332 26,013
Piceance.................................. 57,151 51,325 104,779 74,882
Powder River.............................. 184,332 79,586 849,302 391,739
Green River............................... 15,915 5,880 21,762 15,400
Uinta..................................... 4,222 3,681 53,085 52,007
Mid-Continent Region
Arkoma.................................... 44,198 33,118 14,123 7,370
Anadarko.................................. 123,199 53,431 79,810 39,795
Hugoton Embayment......................... 89,399 86,013 160 160
Permian (2)............................... 14,469 9,389 1,970 927
Gulf of Mexico Region....................... 147,261 53,338 246 154
International............................... 0 0 2,428,000 2,003,800
Other....................................... 34,033 27,180 69,187 48,204
------- ------- --------- ---------
Total................................... 729,872 413,105 3,730,756 2,660,451
======= ======= ========= =========
</TABLE>
- --------
(1) Undeveloped acreage is leased acreage on which wells have not been drilled
or completed to a point that would permit the production of commercial
quantities of natural gas and oil regardless of whether such acreage
contains proved reserves. Of the aggregate 3,730,756 gross and 2,660,451
net undeveloped acres, 262,575 gross and 113,495 net acres are held by
production from other leasehold acreage.
(2) The Permian Basin properties were divested in two transactions completed
in February and March 2000 for a total sale price of $16.3 million.
Substantially all the leases summarized in the preceding table will expire
at the end of their respective primary terms unless the existing leases are
renewed or production has been obtained from the acreage subject to the lease
prior to that date, in which event the lease will remain in effect until the
cessation of production. The following table sets forth the gross and net
acres subject to leases summarized in the preceding table that will expire
during the periods indicated:
<TABLE>
<CAPTION>
Acres Expiring
-------------------
Gross Net
--------- ---------
<S> <C> <C>
Twelve Months Ending:
December 31, 2000......................................... 158,570 78,587
December 31, 2001......................................... 72,600 44,041
December 31, 2002......................................... 1,841,629 1,380,408
December 31, 2003 and later............................... 1,353,036 1,053,347
</TABLE>
Overriding Royalty Interests
The Company owns overriding royalty interests covering in excess of 175,342
gross acres. The majority of these overriding royalty interests are within a
range of approximately .25 to 5.0 percent.
12
<PAGE>
Natural Gas and Oil Marketing and Trading
The Company 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.
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, 1999, less than 4% 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 11,000 MMcfd of natural gas production from the Piceance Basin
through 2011, none of the contracts provides for fixed prices or price
ceilings. The Company believes that it has sufficient production from its
properties to meet the Company's delivery obligations under its existing
natural gas sales contracts.
The Company has entered into a series of firm transportation and storage
agreements with various Rocky Mountain pipeline companies. At January 1, 2000,
these transportation arrangements had terms ranging from one month to ten
years. These transportation agreements provide the Company the opportunity to
transport a portion of its Rocky Mountain natural gas production into the Mid-
Continent area. These agreements, in total, provide transportation of
approximately 210 MMcfd. The primary purpose of this transportation is to move
Company production. The Company's trading group subscribes to roughly 50% of
this capacity. As Company production increases, trading capacity can be
utilized to move Company production.
The Company has established a Risk Management Committee to oversee its
production hedging. The Risk Management Committee consists of the Chief
Executive Officer, the President and Chief Operating Officer, the Chief
Financial Officer and the Senior Vice President and Treasurer. With respect to
production hedge transactions, it is the policy of the Company that the Risk
Management Committee reviews and approves 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.
As of December 31, 1999, the Company had entered into financial
transactions to hedge approximately 55 MMcfd of natural gas production on a
short term for the period from February 2000 through March 2000. In an effort
to eliminate price volatility from its Piceance Basin development program, the
Company entered into a series of hedges throughout 1997 to hedge an aggregate
of 123.5 Bcf of natural gas production from the Rocky Mountain Region for the
five-year period from March 1998 through February 2003. At year-end 1999, 69.1
Bcf of these hedges remained in place.
For the year ended December 31, 1999, revenues from trading activities,
which includes the cost of natural gas purchased or sold for trading purposes,
were $792.0 million, which constituted 79% of the Company's consolidated
revenues and generated a gross margin of $18.9 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 1999. Oil
revenues totaled $18.2 million for the year ended December 31, 1999 and
represented 2% of the Company's total revenues for that period. The Company
does not engage in oil trading activities.
13
<PAGE>
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 Minerals Management Service ("MMS") administers. The MMS issues such
leases through competitive bidding. These leases contain relatively
standardized terms and require compliance with detailed MMS regulations and
orders pursuant to the Outer Continental Shelf Lands Act ("OCSLA"), which are
subject to change by the MMS. For offshore operations, lessees must obtain MMS
approval for exploration plans and development and production plans prior to
the commencement of such operations. In addition to permits required from
other agencies (such as the Coast Guard, the Army Corps of Engineers and the
Environmental Protection Agency), lessees must obtain a permit from the MMS
prior to the commencement of drilling. The MMS 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.
The Federal Energy Regulatory Commission ("FERC") regulates interstate
transportation of natural gas under the Natural Gas Act. Effective January 1,
1993, the Natural Gas Wellhead Decontrol Act deregulated natural gas prices
for all "first sales" of natural gas, which includes sales by the Company of
its own production. As a result, all sales of the Company's natural gas
produced in the U.S. may be sold at market prices, unless otherwise committed
by contract. Congress could reenact price controls in the future. See "--
Natural Gas and Oil Marketing and Trading".
The Company's natural gas sales are affected by regulation of intrastate
and interstate natural gas transportation. In an attempt to promote
competition, the FERC has issued a series of orders that have altered
significantly the marketing and transportation of natural gas. The effect of
these orders has been to enable the Company to market its natural gas
production to purchasers other than the interstate pipelines located in the
vicinity of its producing properties. The Company believes that these changes
have generally improved the Company's access to transportation and have
enhanced the marketability of its natural gas production. To date, the Company
has not experienced any material adverse effect on natural gas marketing as a
result of these FERC orders; however, the Company cannot predict what new
regulations may be adopted by the FERC and other regulatory authorities, or
what effect subsequent regulations may have on its future natural gas
marketing.
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.
14
<PAGE>
Environmental Matters
The Company, as an owner or lessee and operator of natural gas and oil
properties, is subject to various federal, state and local laws and
regulations relating to discharge of materials into, and protection of, the
environment. These laws and regulations may, among other things, impose
liability and substantial penalties on the lessee under a natural gas and oil
lease for the cost of pollution clean-up resulting from operations, subject
the lessee to liability for pollution damages, require suspension or cessation
of operations in affected areas, and impose restrictions on the injection of
liquid into subsurface aquifers that may contaminate groundwater. The Oil
Pollution Act of 1990, as amended, requires operators of offshore facilities
to provide financial assurance in the minimum amount of $35 million to cover
potential environmental cleanup and restoration costs. This amount is subject
to adjustment up to $150 million if the MMS determines such an amount is
justified by the risks from potential oil spills from covered offshore
facilities.
The Company has made, and will continue to make, expenditures in its
efforts to comply with these requirements, which it believes are necessary
business costs in the oil and gas industry. The Company believes it is in
substantial compliance with applicable environmental laws and requirements and
to date such compliance has not had a material adverse effect on the earnings
or competitive position of the Company, although there can be no assurance
that significant costs for compliance will not be incurred in the future. The
Company maintains insurance coverages which it believes are customary in the
industry, although it is not fully insured against many environmental risks.
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.
Disclosure Regarding Forward-Looking Statements
This Annual Report on Form 10-K includes "forward-looking statements"
within the meaning of Section 27A of the Securities Act of 1933, as amended
(the "Securities Act"), and Section 21E of the Securities Exchange Act of
1934, as amended (the "Exchange Act"). All statements other than statements of
historical facts included in this Annual Report on Form 10-K, including
without limitation statements under "Items 1 and 2. Business and Properties--
Core Areas of Activity", "--Reserves", "--Natural Gas and Oil Marketing and
Trading", and "--Government Regulation of the Oil and Gas Industry", "Item 3.
Legal Proceedings", and "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations", regarding the Company's
financial position, reserve quantities and net present values, business
strategy, plans and objectives of management of the Company for future
operations and capital expenditures, are forward-looking statements. Although
the Company believes that the expectations reflected in the forward-looking
statements and the assumptions upon which such forward-looking statements are
based are reasonable, it can give no assurance that such expectations and
assumptions will prove to have been correct. Reserve estimates are generally
different from the quantities of oil and natural gas that are ultimately
recovered. Additional statements concerning important factors that could cause
actual results to differ materially from the Company's expectations
("Cautionary Statements") are disclosed in this Annual Report on Form 10-K and
in the "Risk Factors" section of the Company's Preliminary Prospectus dated
August 24, 1999 included in the Company's Registration Statement on Form S-3
(File Number 333-85809). All written and oral forward-looking statements
attributable to the Company or persons acting on its behalf subsequent to the
date of this Annual Report on Form 10-K are expressly qualified in their
entirety by the Cautionary Statements.
15
<PAGE>
Item 3. Legal Proceedings
Plains Petroleum Company Tax Case
On July 23, 1999, Plains received a favorable ruling on all contested
issues in a case filed in United States Tax Court arising from the Internal
Revenue Service examination of Plains' 1991, 1992 and 1993 income tax returns.
The IRS also examined the federal tax returns of the Company for the
periods ended July 1995, December 1995 and December 1996. Pursuant to a
January 18, 2000 settlement agreement, the Company paid $77,259 to resolve
this matter.
Kansas Ad Valorem Tax Refund
Pursuant to an August 1996 decision of the United States Court of Appeals
for the District of Columbia Circuit and subsequent orders of the FERC,
natural gas producers who received reimbursement for Kansas ad valorem taxes
paid in the mid-1980's on top of the then maximum lawful price for natural gas
have been ordered to refund these tax reimbursements plus interest. In 1998,
in compliance with these decisions, Plains refunded a total of $4.25 million.
This amount reflects the entire refund obligation (principal and interest)
that has been billed to Plains' working interest. In addition, in 1998 Plains
placed in escrow $1.21 million. This escrowed amount represents the refund
amount attributable to Plains' royalty interest owners. On July 28, 1999,
Plains filed a class action lawsuit in Kansas state court to recover from its
royalty owners the amount placed in escrow. Only to the extent Plains is
unsuccessful in this litigation or is unable to obtain FERC relief for the
royalty-related refunds not so recovered in the litigation will Plains have
any financial obligation for any part of this royalty owner refund obligation.
Other Legal Proceedings
At December 31, 1999, the Company was a party to certain other legal
proceedings, which have arisen in the ordinary course of business. Based on
the facts currently available, in management's opinion, the liability,
individually or in the aggregate, if any, to the Company resulting from such
actions will not have a material adverse effect on the Company's consolidated
financial position or results of operations.
Item 4. Submission of Matters to Vote of Security Holders
No matters were submitted to a vote of the Company's security holders
during the fourth quarter of the year ended December 31, 1999.
16
<PAGE>
PART II
Item 5. Market for the Registrant's Common Stock and Related Security Holders
Matters.
(a) Market Information. The Company's common stock is listed on the New
York Stock Exchange under the symbol BRR. The range of high and low sales
prices for each quarterly period during the two most recent years, as reported
by the New York Stock Exchange, is as follows:
<TABLE>
<CAPTION>
Quarter Ended
-------------
High Low
------ ------
<S> <C> <C>
March 31, 1998................................................. $34.94 $24.06
June 30, 1998.................................................. $39.37 $31.06
September 30, 1998............................................. $38.00 $18.87
December 31, 1998.............................................. $28.94 $16.69
March 31, 1999................................................. $28.00 $15.44
June 30, 1999.................................................. $39.81 $24.31
September 30, 1999............................................. $41.25 $32.25
December 31, 1999.............................................. $37.31 $23.06
</TABLE>
On March 15, 2000, the closing price for the Company's common stock was
$24.00 per share.
(b) Holders. The number of record holders of the Company's common stock as
of March 15, 2000 was 3,307.
(c) Dividends. The Company has not paid any cash dividends since its
inception. The Company's credit agreement restricts payment of dividends to
amounts that are less than 50 percent of net income. The Company anticipates
that all earnings will be retained for the development of its business and
that no cash dividends on its common stock will be declared in the foreseeable
future.
Item 6. Selected Financial Data
The following table sets forth certain selected financial data of the
Company for each of the last five years ended December 31:
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------------
1999 1998 1997 1996 1995
---------- -------- -------- -------- --------
(in thousands, except per share data)
<S> <C> <C> <C> <C> <C>
Revenues..................... $1,004,781 $625,399 $382,600 $202,572 $128,016
Net income (loss)............ 20,828 (93,743) 29,261 29,526 (2,240)
Net income (loss) per share.. 0.64 (2.95) 0.92 1.02 (0.09)
Total assets at the end of
each period................. 884,301 838,879 872,701 576,945 340,412
Long-term debt at the end of
each period................. 355,250 334,067 266,437 70,000 89,000
</TABLE>
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
The following discussion should be read in conjunction with the
Consolidated Financial Statements and Notes thereto referred to in "Item 8.
Financial Statements and Supplemental Data", and "Items 1 and 2. Business and
Properties--Disclosure Regarding Forward-Looking Statements" of this Form 10-
K.
Liquidity and Capital Resources
At December 31, 1999, the Company had cash and cash equivalents of $20.6
million, working capital of $14.8 million, property and equipment of $726.5
million and total assets of $884.3 million. Compared to December 31, 1998,
cash and cash equivalents increased $6.3 million, working capital increased
$19.9 million, net property and equipment increased $44.3 million, and total
assets increased $45.4 million.
17
<PAGE>
During 1999, the Company generated operating cash flow of $122.2 million
before working capital changes compared with $119.3 million in 1998. After
working capital changes, cash flow provided by operations was $112.2 million,
a decrease of $4.7 million from 1998.
As of December 31, 1999 and 1998, respectively, the outstanding balance
under the Company's bank credit facility was $200 million and $175 million.
The Company's debt has increased primarily because of capital requirements
related to its exploration, development and acquisition activities. The
Company's bank credit facility is an unsecured $250 million facility with a
consortium of six banks. As of December 31, 1999, the Company's borrowing base
was $236 million. On January 7, 2000, in conjunction with the funding of an
acquisition of certain oil and gas property interests located in northwestern
Colorado on the same date, the borrowing base was increased to $250 million
and the outstanding balance increased to $225 million. The amount of the
borrowing base under the bank credit facility is determined by the lenders
with reference to the Company's proved reserves and the Company's projected
cash requirements. The lenders are currently reviewing the December 31, 1999
reserve report together with changes in reserves resulting from acquisitions
and divestitures of property interests subsequent to December 31, 1999 to
determine current collateral. At the conclusion of this review, the borrowing
base could change. At the time of borrowing funds under the bank credit
facility, interest begins to accrue on those funds, at the Company's election,
at either the London Interbank Eurodollar Rate (LIBOR) plus a spread ranging
from 0.185 percent to 0.625 percent (depending on the Company's senior debt
rating and the ratio of the Company's outstanding indebtedness to its earnings
before interest, taxes and depreciation, depletion and amortization) or at the
United States prime rate of interest. The Company is required to pay interest
on a quarterly basis until the entire outstanding balance matures on September
30, 2002.
Capital Expenditures
During 1999 the Company invested $136.2 million, net of divestitures, in
oil and gas properties and other equipment, including acquisitions and
exploration and development programs. The 1999 acquisition program consisted
principally of purchasing additional producing property interests in the
Piceance Basin and acquiring leases in the Powder River Basin Coal Bed Methane
project. Exploration and development programs were concentrated in the
Anadarko, Piceance, Powder River (Coal Bed Methane project) and Wind River
Basins.
As part of the Company's 1999 and 2000 capital expenditures programs, the
Company acquired additional working interests in the Piceance Basin gas
properties located in northwestern Colorado and all of the outstanding joint
venture interest in a related gas gathering system, processing plant and
pipeline from several industry partners for a total purchase price of
approximately $83 million. Approximately $47.3 million of the total purchase
price was included in the 1999 capital expenditures program. The balance of
$35.7 million is included in the 2000 program.
The Company expects its capital expenditures for 2000 to be approximately
$145 million. The Company plans to continue capital expenditure programs
designed to develop proved undeveloped reserves on existing properties. The
Company's 2000 exploration and development program will be focused in the
Rocky Mountain Region. The Company's exploration and development programs are
discussed in "Business and Properties" under Items 1 and 2 of this Form 10-K.
Reserves and Pricing
Proved reserves at year-end 1999 were 1,133.8 billion cubic feet of natural
gas equivalents (Bcfe), approximately a 17 percent increase over the Company's
December 31, 1998 proved reserves. Approximately 52 percent of the reserve
additions were provided by property acquisitions, 44 percent of the reserve
additions were generated through exploration and development projects, and 4
percent of the reserve additions were generated through upward revisions of
previous estimates. Proved reserves were reduced by production of
approximately 103.5 Bcfe and sales of properties with reserves of 39.8 Bcfe.
During 1999, as a result of its drilling and acquisition activities net of
sales and revisions, the Company's reserve replacement was 258 percent of
total production.
18
<PAGE>
As of year-end 1999, the standardized measure of discounted future net cash
flows increased $130.7 million, or 25 percent, from 1998 primarily due to
reserve revisions, increases in oil and gas prices and reserve quantity
additions. Reserve extensions and discoveries and purchases of proved
reserves, net of sales, added $76.5 and $117.7 million, respectively, to the
standardized measure. The changes in year-end sales prices and production
costs from 1998 to 1999 increased the standardized measure of discounted
future net cash flows by $45.5 million. Reserves produced during the year
reduced the standardized measure by $157.8 million. The Company's standardized
measure of discounted future net cash flows is sensitive to gas prices in the
current volatile commodities market.
Oil and natural gas prices fluctuate throughout the year. As of December
31, 1999, the Company was receiving weighted average prices of $22.01 per
barrel of oil and $2.06 per Mcf of gas. A decline in prices would have a
material effect on the discounted future net cash flows which, in turn, could
impact the "ceiling test" for the Company's oil and gas properties accounted
for under the full cost method in subsequent periods.
From time to time the Company uses swaps to hedge the sales price of its
natural gas and oil. The intent of hedging activities is to reduce the
volatility associated with the sales prices of the Company's natural gas and
oil production. Although hedging transactions associated with the Company's
production reduce the Company's exposure to declines in production revenue as
a result of unfavorable price changes, these transactions also limit the
Company's ability to benefit from favorable price changes. As of December 31,
1999, the Company held positions to hedge 69.1 Bcf of the Company's future
natural gas production at varying volumes per month through February 2003. The
Company currently has no derivatives in place for its oil production.
As part of the Company's trading activities, it enters into a variety of
contracts to purchase and sell natural gas and oil at both fixed prices and at
index based prices. In addition, the Company enters into financial instruments
that seek to reduce sensitivity to price movements or to create guaranteed
margins on certain delivery and purchase commitments. As of December 31, 1999,
the absolute notional contract quantity of natural gas commodity derivatives
held for trading purposes was 1,279.8 Bcf including financial purchases, sales
and basis positions.
The Company's drilling and acquisition activities have increased its
reserve base and its productive capacity and, therefore, its potential cash
flow. Lower gas prices may adversely affect cash flow. Due to current higher
than expected market prices for natural gas and the Company's derivative
positions for its natural gas production (see Item 7A. Quantitative and
Qualitative Disclosures About Risk, Commodity Price Risk), the derivative
counterparties have required margin call deposits which may adversely affect
available cash flow. If natural gas prices decline, such margin call deposits
will be refunded to the Company. The Company intends to continue to acquire
and develop oil and gas properties in its areas of activity as dictated by
market conditions and financial ability. The Company retains flexibility to
participate in oil and gas activities at a level that is supported by its cash
flow and financial ability. Management believes that the Company's cash flows
or available credit facilities are sufficient to fund its currently
anticipated capital activities and operating requirements. Additional funding
alternatives, including sales of non-core area properties, will be considered
to secure other funds for capital development. The Company intends to continue
to use financial leverage to fund its operations as investment opportunities
become available on terms that management believes warrant investment of the
Company's capital resources.
Year 2000
The Company did not experience nor does it anticipate any difficulties or
disruptions of its operations with its systems or with third parties relative
to the year 2000 issues. The Company relied upon its internal staff to assess
its Year 2000 readiness. Outside consultants were used for limited projects.
Costs incurred through December 31, 1999 were minimal.
19
<PAGE>
Results of Operations
1999 vs. 1998
In 1999, the Company earned net income of $20.8 million ($.64 per share),
compared to a net loss of $93.7 million ($2.95 per share) in 1998. Excluding
the effects of the oil and gas impairment and related income tax effect
recognized in 1998, the Company's net income in 1998 after taxes would have
been $11.7 million ($.36 per share).
Revenues increased $379.4 million (61 percent) to $1,004.8 million in 1999.
Operating expenses increased 25 percent to $971.4 million. In 1999, oil and
gas production revenue increased one percent to $206.9 million and trading
revenues increased 92 percent to $792 million. Lease operating expenses
increased $3.5 million, and depreciation, depletion and amortization decreased
$11.5 million.
Production revenues increased $1.4 million to $206.9 million primarily due
to a 3.5 percent increase in gas revenues. This increase in gas revenues is
the result of a 3 percent increase in average gas prices from $1.92 in 1998 to
$1.99 in 1999. Gas production remained unchanged at 94.9 Bcf in 1999. Oil
production decreased 30% which was partially offset by an 11% increase in
average oil prices from $11.42 per Bbl in 1998 to $12.71 per Bbl in 1999. Gas
production accounted for 92 percent of total production on an energy
equivalent basis. The Piceance, Wind River, Powder River--Coal Bed Methane and
Hugoton Embayment Basin properties accounted for 22 percent, 20 percent, 14
percent, and 14 percent, respectively, of total gas production. The Powder
River and Uinta Basin properties accounted for 39 percent and 21 percent,
respectively, of total oil production.
Lease operating expenses of $62.1 million averaged $.60 per Mcfe ($3.60 per
BOE) compared to $.55 per Mcfe ($3.28 per BOE) in 1998. Depreciation,
depletion and amortization decreased $11.5 million primarily due to a decrease
in the depletion rate. During 1999, depletion and amortization on oil and gas
production was provided for at an average rate of $.83 per Mcfe ($4.99 per
BOE) compared to an average rate of $.91 per Mcfe ($5.49 per BOE) in 1998.
The gross margin on trading activities increased $3.9 million to $18.8
million in 1999. Gas trading volumes increased 76 percent to 383.5 Bcf in
1999.
The Company enters into hedging arrangements to reduce its exposure to
price risks associated with commodities markets. Although hedging transactions
associated with its production reduce the Company's exposure to losses as a
result of unfavorable price changes, the transactions also limit the Company's
ability to benefit from favorable price changes. During 1999, the Company
hedged 37.2 Bcf (39 percent) of its gas production for a net cost of $8.3
million and 825 MBbls (58 percent) of its oil production for a net cost of
$4.6 million.
General and administrative expenses of $23.8 million reflect a 3 percent
decrease compared to 1998. The 1999 amount is net of $5.1 million of operating
fee recoveries compared to a $6.3 million recovery in 1998.
Interest expense increased from $20.9 million in 1998 to $21.5 million in
1999 primarily as a result of the increase in long-term debt.
Income tax expense increased by $68.3 million to $12.5 million as a result
of the Company's net loss for 1998. The Company's effective financial
statement tax rate in 1999 was 37.5%.
1998 vs. 1997
In 1998, the Company had a net loss of $93.7 million ($2.95 per share),
which includes a pre-tax impairment of $168.3 million, compared to net income
of $29.3 million ($.92 per share) in 1997. Excluding the effects of the
impairment, the Company's net income in 1998 after taxes would have been $11.7
million ($.36 per share).
20
<PAGE>
Revenues increased $242.8 million (63 percent) to $625.4 million in 1998.
Operating expenses, which includes the impairment of $168.3 million, increased
131 percent to $774.9 million. Excluding the effects of the impairment,
operating expenses increased 81 percent. In 1998, oil and gas production
revenue decreased one percent to $205.5 million and trading revenues increased
141 percent to $413 million. Lease operating expenses increased $0.7 million
and depreciation, depletion and amortization increased $29.7 million.
Production revenues decreased $1.4 million to $205.5 million primarily due
to a 41 percent decrease in oil revenues. This decrease in oil revenues is the
result of a 35 percent decline in average oil price from $17.69 per Bbl in
1997 to $11.42 per Bbl in 1998 and a nine percent decrease in oil production.
Gas production increased 24 percent from 76.6 Bcf in 1997 to 94.9 Bcf in 1998
which was partially offset by a 12 percent decline in average gas prices which
dropped from $2.18 in 1997 to $1.92 in 1998. Gas production accounted for 89
percent of total production on an energy equivalent basis. The Wind River and
Piceance Basin properties accounted for 24 percent and 21 percent,
respectively, of total gas production. The Powder River and Uinta Basin
properties accounted for 35 percent and 23 percent, respectively, of total oil
production.
Lease operating expenses of $58.6 million averaged $.55 per Mcfe ($3.28 per
BOE) compared to $.64 per Mcfe ($3.86 per BOE) in 1997. Depreciation,
depletion and amortization increased $29.7 million primarily due to production
increases. During 1998, depletion and amortization on oil and gas production
was provided for at an average rate of $.91 per Mcfe ($5.49 per BOE) compared
to an average rate of $.77 per Mcfe ($4.60 per BOE) in 1997. As a result of
the required full cost ceiling test, the Company recognized a pre-tax
impairment of the net book value of its United States oil and gas properties
of $129 million, and a pre-tax impairment of the Company's investment in its
international oil and gas exploration project, located in the Republic of
Peru, of $39 million. The impairment was caused principally by low year-end
oil and gas prices.
The gross margin on trading activities increased $9.0 million to $14.9
million in 1998. Gas trading volumes increased 157 percent to 217.5 Bcf in
1998.
The Company enters into hedging arrangements to reduce its exposure to
price risks associated with commodities markets. Although hedging transactions
associated with its production reduce the Company's exposure to losses as a
result of unfavorable price changes, the transactions also limit the Company's
ability to benefit from favorable price changes. During 1998, the Company
hedged 31.3 Bcf (33 percent) of its gas production for a net cost of $0.7
million. Oil production was not hedged during 1998.
General and administrative expenses of $24.5 million reflect a one percent
decrease compared to 1997. The 1998 amount is net of $6.3 million of operating
fee recoveries compared to a $5.0 million recovery in 1997.
Interest expense increased significantly from $13.2 million in 1997 to
$20.9 million in 1998 primarily as a result of the increase in long-term debt.
Income tax expense decreased by $73.7 million as a result of the Company's
net loss for the year.
Item 7a. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Commodity financial instruments are intended to reduce the Company's
exposure to declines in the market price of natural gas and oil. Such
instruments may also limit the Company's gain from increases in the market
price of natural gas and oil. Fluctuations or changes in the settlement values
of commodity financial instruments are generally offset by similar changes in
the realized price of natural gas and oil.
The Company uses commodity derivative financial instruments, including
futures and swaps, to reduce the effect of natural gas price volatility on a
portion of its natural gas production. Commodity swap agreements are generally
used to fix a price at the natural gas market location or to fix a price
differential between the price of natural gas at Henry Hub and the price of
gas at its market location. Settlements are based on the difference between a
fixed and a variable price as specified in the agreement. The following table
summarizes the
21
<PAGE>
Company's derivative financial instrument position on its natural gas
production as of December 31, 1999. The Company does not have in place as of
December 31, 1999 any hedging position for its future oil production. The fair
value of these instruments reflected in the table below is the estimated
amount that the Company would receive or (pay) to settle the contracts as of
December 31, 1999. Actual settlement of these instruments when they mature
will differ from these estimates reflected in the table. Gains or losses
realized from these instruments hedging the Company's production are expected
to be offset by changes in the actual sales price received by the Company for
its natural gas production.
<TABLE>
<CAPTION>
For the year Bcf Price Range Per MMBru Fair Value
------------- ---- --------------------- --------------
<S> <C> <C> <C>
2000 23.0 $1.71 - $2.83 $(8.6) million
2001 21.2 $1.71 - $1.79 $(9.0) million
2002 22.9 $1.71 - $1.79 $(9.7) million
2003 2.0 $1.71 - $1.79 $(2.0) million
</TABLE>
The Company also uses commodity derivative financial instruments and
contracts for the purchase and sale of natural gas at both fixed and indexed
based prices in its trading activities. The financial instruments seek to
reduce sensitivity to price movements, to lock in margins on all of its fixed-
price trading positions and to hedge the value of stored gas. The following
table summarizes the Company's derivative positions on its natural gas trading
activities as of December 31, 1999. The fair value of these instruments
reflects the estimated amounts that the Company would receive or (pay) to
settle the contracts as of December 31, 1999. Actual settlement of these
instruments as they mature will differ from these estimates
<TABLE>
<CAPTION>
For the year Bcf Price Range Per MMBru Fair Value
------------- ----- --------------------- -------------
<S> <C> <C> <C>
2000 828.3 $1.60 - $3.24 $19.4 million
2001 191.8 $1.86 - $3.10 $ 4.0 million
2002 115.5 $2.00 - $3.10 $ 2.8 million
2003 67.1 $2.38 - $2.47 $ 2.1 million
2004 54.4 $2.38 - $2.47 $ 2.2 million
Thereafter 22.7 $2.47 $ 2.0 million
</TABLE>
Interest Rate Risk
The Company's use of fixed and variable rate long-term debt to partially
finance capital expenditures exposes the Company to market risk related
changes in interest rates. The following table presents principal and related
average interest rates by year of maturity for the Company's debt obligations
and their indicated fair market value at December 31, 1999.
<TABLE>
<CAPTION>
Expected Maturity/Redemption
----------------------------------------
Fair
2000 2001 2002 2003 2004 Thereafter Value
---- ---- ------ ---- ---- ---------- ------
Dollars in millions
<S> <C> <C> <C> <C> <C> <C> <C>
Long-term debt:
Fixed rate.................... $4.1 $3.4 $ 1.8 -- -- $150.0 $153.9
Average Interest Rate......... 7.72% 7.72% 7.72% -- -- 7.55% --
Variable rate................. -- -- $200.0 -- -- -- $200.0
Average Interest Rate......... -- -- 6.501% -- -- -- --
</TABLE>
Item 8. Financial Statements and Supplemental Data
The Consolidated Financial Statements and schedules that constitute Item 8
are attached at the end of this Annual Report on Form 10-K. An index to these
Consolidated Financial Statements and Schedules also is included in Item 14(a)
of this Annual Report on Form 10-K.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosures
Not applicable.
22
<PAGE>
PART III
Item 10. Directors and Executive Officers of the Company
The directors and executive officers of the Company, their respective ages
and positions, and the year in which each director was first elected, are set
forth in the following table. Additional information concerning each of these
individuals follows the table:
<TABLE>
<CAPTION>
Director
Age Position With the Company Since
--- ------------------------------------ --------
<S> <C> <C> <C>
William J. Barrett(1)(6)(8)......... 71 Chairman of the Board, and a 1983
Director
C. Robert Buford(1)(2)(3)(4)(5)..... 66 Director 1983
Derrill Cody(1)(2)(3)(4)(5)......... 61 Director 1995
Peter A. Dea........................ 46 Vice-Chairman and Chief Executive 1999
Officer, and a Director
James M. Fitzgibbons(3)(4)(5)(7).... 65 Director 1987
William W. Grant, III(3)(4)(5)...... 67 Director 1995
J. Frank Keller(6).................. 56 Chief Financial Officer, Executive 1983
Vice President, and a Director
A. Ralph Reed....................... 62 Chief Operating Officer, President 1990
and a Director
James T. Rodgers(3)(4)(5)........... 65 Director 1993
Philippe S.E. Schrei- 59 Director 1985
ber(1)(2)(3)(4)(5).................
Joseph P. Barrett(8)................ 46 Senior Vice President--Land --
Bryan G. Hassler.................... 41 Senior Vice President--Marketing --
Robert W. Howard.................... 45 Senior Vice President--Investor --
Relations, Corporate Development
and Treasurer
Eugene A. Lang, Jr.................. 46 Executive Vice President and General --
Counsel; and Secretary
Logan Magruder, III................. 43 Vice President--Operations --
Steven G. Natali.................... 45 Vice President--Exploration --
</TABLE>
- --------
(1) Member of the Executive Committee of the Board of Directors. Mr. Barrett
will retire on March 31, 2000.
(2) Member of the Board Planning and Nominating Committee of the Board of
Directors.
(3) Member of the Audit Committee of the Board of Directors.
(4) Member of the Compensation Committee of the Board of Directors.
(5) Member of the Succession Planning Committee of the Board of Directors
(6) Mr. Keller and Mr. Barrett are brothers-in-law.
(7) Mr. Fitzgibbons served as a Director of the Company from July 1987 until
October 1992. He was re-elected to the Board of Directors in January 1994.
(8) Joseph P. Barrett is the son of William J. Barrett.
William J. Barrett stepped down as the Chief Executive Officer on November
18, 1999 in connection with the election of Mr. Dea as Chief Executive
Officer. Mr. Barrett will retire on March 31, 2000. At that time he will also
resign from the Board of Directors. Mr. Barrett had served as Chief Executive
Officer of the Company since December 1983, except for the period from July 1,
1997 through March 23, 1998. He has served as Chairman of the Board since
September 1994, and Mr. Barrett served as President 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
23
<PAGE>
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 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.
C. Robert Buford has been a director of the Company since December 1983 and
served as Chairman of the Board of Directors from December 1983 through March
1994. Mr. Buford has been President, Chairman of the Board and controlling
shareholder of Zenith Drilling Corporation ("Zenith"), Wichita, Kansas, since
February 1966. Zenith owns approximately 1.7 percent of the Company's common
stock. Since 1993, Mr. Buford has served as a director of Encore Energy, Inc.,
a wholly-owned subsidiary of Zenith engaged in the marketing of natural gas.
Mr. Buford is also a member of the Board of Directors of Intrust Financial
Corporation, a bank holding company.
Derrill Cody has been a director of the Company since July 1995. From May
1990 until July 1995, Mr. Cody served as a director of Plains Petroleum
Company ("Plains"), which merged with a subsidiary of the Company on July 18,
1995. Since January 1990, Mr. Cody has been an attorney in private practice in
Oklahoma City, Oklahoma. From 1986 to 1990, he was Executive Vice President of
Texas Eastern Corporation, and from 1987 to 1990 he was the Chief Executive
Officer of Texas Eastern Pipeline Company. He has been a director of the
General Partner of TEPPCO Partners, L.P. since January 1990.
Peter A. Dea was elected as Chief Executive Officer, Vice Chairman and a
director in November 1999. (Effective April 1, 2000, Mr. Dea will become
Chairman of the Board and Chief Executive Officer.) He previously served as
Executive Vice President--Exploration from December 1998 until November 1999.
He served as Senior Vice President--Exploration of the Company from June 1996
until December 1998. He held various exploration geologist positions with the
Company from February 1994 through June 1996. Mr. Dea served as President of
Nautilus Oil and Gas Company from 1992 through 1993. From 1982 until 1991, Mr.
Dea served in various positions with Exxon Company USA.
James M. Fitzgibbons has been a director of the Company since January 1994,
and previously served as a director of the Company from July 1987 until
October 1992. Since January 1998, Mr. Fitzgibbons has been the Chairman of the
Board of Davidson Cotton Company. From October 1990 through December 1997, Mr.
Fitzgibbons was Chairman and Chief Executive Officer of Fieldcrest Cannon,
Inc. From January 1986 until October 1990, Mr. Fitzgibbons was President of
Amoskeag Company. Prior to 1986, he was President of Howes Leather Company.
Mr. Fitzgibbons is also a member of the Board of Directors of Lumber Mutual
Insurance Company, and he is a Trustee of Dreyfus Laurel Funds, a series of
mutual funds.
William W. Grant, III has served as a director of the Company since July
1995. From May 1987 until July 1995, Mr. Grant served as a director of Plains.
He was an advisory director of Colorado National Bank from 1993 through 1999.
He was a director of Colorado National Bankshares, Inc. from 1982 to 1993 and
the Chairman of the Board of Colorado National Bank of Denver from 1986 to
1993. He served as the Chairman of the Board of Colorado Capital Advisors from
1989 through 1994.
J. Frank Keller has been an Executive Vice President, and a director of the
Company since December 1983 and Chief Financial Officer of the Company since
July 1995. From December 1983 through June 1997, he also served as Secretary.
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.
A. Ralph Reed was elected President and Chief Operating Officer of the
Company on March 23, 1998. He was an Executive Vice President of the Company
from November 1989 through March 23, 1998 and he has been a director since
September 1990. From 1986 to 1989, Mr. Reed was an independent oil and natural
gas
24
<PAGE>
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 ("Cotton"), a wholly owned exploration and
production subsidiary of United Energy Resources, Inc. Prior to joining Cotton
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 November 1993.
Mr. Rodgers served as the President, Chief Operating Officer and a director of
Anadarko Petroleum Corporation ("Anadarko") from 1986 through 1992. 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
served as a Director of Louis Dreyfus Natural Gas Corporation until October
1997, and he currently serves as a director of Khanty Mansysk Oil Corporation,
a privately held exploration and production company operating 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. From
August 1985 through December 1998, he was a partner of, or of counsel to, the
law firm of Walter, Conston, Alexander & Green, P.C. in New York, New York.
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. Mr. Schreiber has served as a director of the United States
principal affiliate of The Mayflower Corporation plc. since 1999. Mr.
Schreiber also serves as a director of other private companies.
Joseph P. Barrett has been Senior Vice President--Land since March 1999. He
had served as Vice President--Land from March 1995 through February 1999, and
he has held various positions in the Company's Land Department since 1982.
Bryan G. Hassler was elected Senior Vice President--Marketing in May 1999.
He had been Vice-President--Marketing of the Company from December 1996
through May 1999. He joined the Company as Director of Marketing in August
1994. Prior to joining the Company, Mr. Hassler was Marketing Coordinator for
Questar Corporation's Marketing Group and Mr. Hassler held various engineering
positions with Questar Corporation's exploration and production and pipeline
groups.
Robert W. Howard was elected Senior Vice President--Investor Relations,
Corporate Development and Treasurer on February 25, 1999. He had been Senior
Vice President of the Company from March 1992 through February 25, 1999. 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 served as Executive Vice President--General Counsel
of the Company since May 1999. Prior to that, he was Senior Vice President--
General Counsel of the Company from September 1995 to May 1999. In June 1997,
Mr. Lang was also elected Secretary. 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 September 1986 to September 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 KN. From 1978 to 1984, he was an
attorney with KN.
Logan Magruder III was elected Vice President--Operations in April 1998.
From October 1997 through April 1998 he was Vice President--Corporate
Relations and Business Development. From December 1996 through October 1997 he
served as Manager of Operations in the Company's Gulf of Mexico Division. From
November 1995 to December 1996, Mr. Magruder served as Director of Engineering
and Operations for Scana Petroleum and from 1991 to 1993, Mr. Magruder served
as a Vice President of Torch Energy. From 1980 to
25
<PAGE>
1991, Mr. Magruder held petroleum engineering and corporate relations
positions with other exploration and production companies.
Steven G. Natali was elected the Company's Vice President--Exploration on
December 16, 1999. He had served as the Company's Exploration Manager from
March 1, 1999 to December 18, 1999. He served as the Company's Chief
Geophysicist from January 1995 to March 1999. From March 1992 to December 1994
he served as a Geophysicist with Advance Geophysical in Denver, Colorado. From
June 1980 to February 1992, Mr. Natali worked in the Denver office of Amoco
Production Company as an exploration geophysicist.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934, as amended (the
"Exchange Act"), requires the Company's directors, executive officers and
holders of more than 10% of the Company's common stock to file with the
Securities and Exchange Commission initial reports of ownership and reports of
changes in ownership of common stock and other equity securities of the
Company. The Company believes that during the fiscal year ended December 31,
1999, its officers, directors and holders of more than 10% of the Company's
common stock complied with all Section 16(a) filing requirements except as
follows: A. Ralph Reed, President, Chief Operating Officer and a director, was
late in filing two reports concerning two gifts of shares to charities and a
bequest of Company common stock received by his spouse; Bryan G. Hassler,
Senior Vice President--Marketing, was late in filing a report covering the
exercise of a stock option; and C. Robert Buford, a director, was late in
filing a report concerning the contribution of shares of the Company's common
stock owned by Zenith Drilling Company to a limited partnership in exchange
for interests in that limited partnership. In making these statements, the
Company has relied upon the written representations of its directors and
officers.
26
<PAGE>
Item 11. Executive Compensation
Summary Compensation Table
The following table sets forth in summary form the compensation earned
during each of the Company's last three completed years by the Chief Executive
Officer and former Chief Executive Officer of the Company and by the four
other most highly compensated executive officers whose compensation exceeded
$100,000 during the year ended December 31, 1999 (the "Named Executive
Officers"). The figures in the following table are for fiscal years ended
December 31, 1999, 1998, and 1997:
Summary Compensation Table
<TABLE>
<CAPTION>
Long Term Compensation
-------------------------------
Awards Payouts
Other ----------------------- -------
Annual Restricted Securities
Compen- Stock Underlying LTIP All Other
Name and Principal Fiscal Salary Bonus sation Award(s) Options/SARs Payouts Compensation
Position Year ($) ($)(1) ($)(2) ($)(3) (#)(4) ($)(5) ($)(6)
------------------ ------ -------- -------- ------- ---------- ------------ ------- ------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
William J. Barrett (7).. 1999 $350,016 $200,000 -0- -0- 100,000 -0- $623,100(7)
Chairman of the Board 1998 $306,512 -0- -0- -0- 110,000 -0- $ 9,600
and a director 1997 $215,000 $145,000 -0- -0- 50,000 -0- $ 9,500
Peter A. Dea (8)........ 1999 $218,752 $175,000 -0- -0- 100,000 -0- $ 9,600
Chief Executive Offi-
cer, 1998 $167,708 -0- -0- -0- 142,000 -0- $ 9,600
Vice Chairman, and a 1997 $153,750 $ 35,000 -0- -0- 7,500 -0- $ 8,838
director -0- -0- -0-
A. Ralph Reed (9)....... 1999 $285,000 $130,000 -0- -0- 52,500 -0- $ 9,600
President, Chief Oper-
ating 1998 $272,250 -0- -0- -0- 60,000 -0- $ 9,600
Officer, and a director 1997 $217,500 $ 70,000 -0- -0- -0- -0- $ 9,500
J. Frank Keller (10).... 1999 $180,000 $ 85,000 -0- -0- 34,350 -0- $ 9,600
Executive Vice Presi-
dent, 1998 $177,131 -0- -0- -0- 35,000 -0- $ 9,600
Chief Financial Offi-
cer, 1997 $165,768 $ 90,000 -0- -0- 26,700 -0- $ 9,500
and a director
Bryan G. Hassler........ 1999 $150,000 $208,507 -0- -0- 15,000 -0- $ 8,625
Senior Vice President-- 1998 $143,950 $121,000 -0- -0- 16,000 -0- $ 8,636
Marketing 1997 $135,000 $ 50,000 -0- -0- -0- -0- $ 9,500
</TABLE>
- --------
(1) The dollar value of bonus (cash) earned during the year indicated. The
cash bonuses earned for 1999 were determined by the Compensation Committee
on February 25, 2000. See "Compensation Committee Report on Executive
Compensation-Cash Bonus Awards".
(2) During the period covered by the Table, the Company did not pay any other
annual compensation not properly categorized as salary or bonus, including
perquisites and other personal benefits, securities or property.
(3) During the period covered by the Table, the Company did not make any award
of restricted stock, including share units.
(4) The sum of the number of shares of common stock to be received upon the
exercise of all stock options granted.
(5) Except for stock option plans, the Company does not have in effect any
plan that is intended to serve as incentive for performance to occur over
a period longer than one fiscal year.
(6) Represents the Company's matching contribution under the Company's 401(k)
Plan for each Named Executive Officer, except in the case of Mr. Barrett
who received additional cash compensation described in Note (7) below.
(7) Mr. Barrett was elected as Chief Executive Officer on March 23, 1998, and
served in that office until November 18, 1999. He will retire as Chairman
of the Board and as a director on March 31, 2000. The amount shown under
"All Other Compensation" for Mr. Barrett for 1999 includes $612,500
payable to Mr.
27
<PAGE>
Barrett upon his March 31, 2000 retirement for his contribution to the
overall performance of the Company since returning from retirement in March
1998.
(8) Mr. Dea was elected as Chief Executive Officer, Vice Chairman and a
director on November 18, 1999. Mr. Dea has been elected as Chairman of the
Board beginning on April 1, 2000.
(9) Mr. Reed's membership on the Board will end on May 4, 2000.
(10) Mr. Keller's membership on the Board will end on May 4, 2000.
Option Grants in Last Fiscal Year
No stock appreciation rights were granted to any executive officers or
employees in the year ended December 31, 1999. The following table provides
information on stock option grants in the year ended December 31, 1999 to the
Named Executive Officers.
Option Grants In Last Fiscal Year
<TABLE>
<CAPTION>
Potential Realizable
Value at Assumed
Number of % of Total Annual Rates of Stock
Securities Options Price Appreciation
Underlying Granted to Exercise for Option Term
Options Employees in Price ---------------------
Name Granted (#) Fiscal Year ($/Share) Expiration Date 5% 10%
---- ----------- ------------ --------- --------------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
William J. Barrett...... 100,000(1) 13.62% $16.4375 3-31-2003 $2,498,250 $4,093,250
Peter A. Dea............ 100,000(2) 13.62% $31.6875 11-18-2006 $ 973,250 $2,568,250
A. Ralph Reed........... 52,500(3) 7.15% $16.4375 2-26-2006 $1,311,581 $2,148,956
J. Frank Keller......... 34,350(3) 4.68% $16.4375 2-26-2006 $ 858,148 $1,406,031
Bryan G. Hassler........ 15,000(3) 2.04% $16.4375 2-26-2006 $ 374,737 $ 613,987
</TABLE>
- --------
(1) These option shares become exercisable on March 31, 2000.
(2) One-fourth of these option shares become exercisable on each of November
18, 2000, November 18, 2001, November 18, 2002, and November 18, 2003.
(3) One-fourth of these option shares become exercisable on each of February
26, 2000, February 26, 2001, February 26, 2002, and February 26, 2003.
Aggregated Option Exercises And Fiscal Year-End Option Value Table
The following table sets forth information concerning each exercise of stock
options during the fiscal year ended December 31, 1999 by the Named Executive
Officers and the year-end value of unexercised options held by these persons:
Aggregated Option Exercises
For Fiscal Year Ended December 31, 1999
And Year-End Option Values(/1/)
<TABLE>
<CAPTION>
Number of
Securities Underlying Value of Unexercised
Unexercised Options In-the-Money Options
Shares Value at Fiscal Year-End(4) at Fiscal Year-End($)(5)
Acquired on Realized ------------------------- -------------------------
Name Exercise(2) ($) (3) Exercisable Unexercisable Exercisable Unexercisable
---- ----------- -------- ----------- ------------- ----------- -------------
<S> <C> <C> <C> <C> <C> <C>
William J. Barrett...... 28,400 $347,125 210,000 150,000 $681,875 $1,300,000
Peter A. Dea............ 34,811 $285,979 46,782 217,282 $231,327 $ 590,796
A. Ralph Reed........... 28,400 $408,250 52,500 100,000 $240,000 $ 745,625
J. Frank Keller......... 55,000 $508,674 40,250 75,000 $116,212 $ 476,850
Bryan G. Hassler........ 8,969 $ 52,937 24,012 42,000 $ 22,705 $ 18,984
</TABLE>
- --------
(1) No stock appreciation rights are held by any of the Named Executive
Officers.
(2) The number of shares received upon exercise of options during the year
ended December 31, 1999.
28
<PAGE>
(3) With respect to options exercised during the Company's year ended December
31, 1999, the dollar value of the difference between the option exercise
price and the market value of the option shares purchased on the date of
the exercise of the options.
(4) The total number of unexercised options held as of December 31, 1999,
separated between those options that were exercisable and those options
that were not exercisable.
(5) For all unexercised options held as of December 31, 1999, the aggregate
dollar value of the excess of the market value of the stock underlying
those options over the exercise price of those unexercised options. These
values are shown separately for those options that were exercisable, and
those options that were not yet exercisable, on December 31, 1999. As
required, the price used to calculate these figures was the closing sale
price of the common stock at year's end, which was $29.44 per share on
December 31, 1999. On March 15, 2000, the closing sale price was $24.00
per share.
Employee Retirement Plans, Long-Term Incentive Plans, and Pension Plans
The Company has an employee retirement plan (the "401(k) Plan") that
qualifies under Section 401(k) of the Internal Revenue Code of 1986, as
amended. Employees of the Company are entitled to contribute to the 401(k)
Plan up to 15 percent of their respective salaries. In addition, the Company
currently contributes on behalf of each participating employee 100 percent of
that employee's contribution, up to a maximum contribution by the Company of
six percent of that employee's gross salary for that pay period, with one-half
of the matching contribution paid in cash and one-half paid in the Company's
common stock. The Company's matching contribution is subject to a vesting
schedule. Benefits payable to employees upon retirement are based on the
contributions made by the employee under the 401(k) Plan, the Company's
matching contributions, and the performance of the 401(k) Plan's investments.
Therefore, the Company cannot estimate the annual benefits that will be
payable to participants in the 401(k) Plan upon retirement at normal
retirement age. Excluding the 401(k) Plan, the Company has no defined benefit
or actuarial or pension plans or other retirement plans.
Excluding the Company's stock option plans, the Company has no long-term
incentive plan to serve as incentive for performance to occur over a period
longer than one fiscal year.
Compensation of Directors
Standard Arrangements. Pursuant to the Company's standard arrangement for
compensating directors, no compensation for serving as a director is paid to
directors who also are employees of the Company, and those directors who are
not also employees of the Company ("Outside Directors") receive an annual
retainer of $20,000 paid in equal quarterly installments. In addition, for
each Board of Directors or committee meeting attended, each Outside Director
receives a $1,000 meeting attendance fee for each Board or Committee meeting
attended. Each Outside Director also receives $300 for each telephone meeting
lasting more than 15 minutes. The Chairmen of the Compensation and Audit
Committees receive, however, a $1,500 meeting attendance fee for each
committee meeting. Beginning on April 1, 2000, the meeting attendance fee will
increase to $1,100, the Chairman's fees for Committee Meetings will increase
to $1,600, and the fee for telephone meetings will increase to $500. All
directors are reimbursed for out-of-pocket expenses incurred in connection
with attending Board and Committee meetings.
For each Board of Directors or committee meeting attended, each Outside
Director will have options to purchase 1,000 shares of common stock become
exercisable. Although these options become exercisable only at the rate of
1,000 for each meeting attended, each director will be granted options to
purchase 10,000 shares at the time the individual initially becomes a
director. Any options that have not become exercisable at the time of
termination of a director's service will expire at that time. At such time
that the options to purchase all 10,000 shares have become exercisable,
options to purchase an additional 10,000 shares will be granted to the
director and will be subject to the same restrictions on exercise as the
previously received options. The options are granted to the Outside Directors
pursuant to the Company's Non-Discretionary Stock Option Plan, and the
exercise price for those options is equal to the closing sales price for the
Company's common stock on the date
29
<PAGE>
of grant. The options expire upon the later to occur of five years after the
date of grant and two years after the date those options first became
exercisable.
Other Arrangements. During the year ended December 31, 1999, no
compensation was paid to directors of the Company other than pursuant to the
standard compensation arrangements described in the previous section.
Employment Contracts and Termination of Employment and Change-in-Control
Arrangements
The Company has entered into severance agreements with Messrs. Barrett,
Reed, Keller, Dea and Hassler. Generally, the Agreements of Messrs. Reed,
Keller, Dea and Hassler provide, among other things, that if, within three
years after a Change-in-Control (as defined in the severance agreement) the
employee's employment is terminated by the employee for "Good Reason" or by
the Company other than for "Cause" (as such terms are defined in the severance
agreement), the employee will be entitled to a lump sum cash payment equal to
three times (two times in the case of Mr. Hassler) the employee's annual
compensation (based on annual salary and past annual bonus) in addition to
continuation of certain benefits for three years (two years in the case of Mr.
Hassler) from the date of termination. Mr. Barrett's agreement, which expires
on March 31, 2000, provides that, if his employment is terminated by him for
Good Reason or by the Company other than for Cause prior to March 31, 2000, he
will receive a lump sum cash amount equal to the compensation that would have
been paid from his termination date through March 31, 2000, in addition to
continued benefits through March 31, 2000.
In addition, the Company's stock option plans and option agreements under
the plans provide for the acceleration of option exercisability in the event
of a change-in-control.
Compensation Committee Interlocks and Insider Participation
During the year ended December 31, 1999, each of Messrs. Buford, Cody,
Fitzgibbons, Grant, Rodgers and Schreiber served as members of the
Compensation Committee of the Board of Directors. Mr. Schreiber served as the
President of Excel Energy Corporation ("Excel") prior to the 1985 merger of
Excel with and into the Company. No other person who served as a member of the
Compensation Committee during the year ended December 31, 1999 was, during
that year, an officer or employee of the Company or of any of its
subsidiaries, or was formerly an officer of the Company or of any of its
subsidiaries, except Mr. Buford who served as the Chairman of the Board from
December 1983 through March 1984. However, Mr. Buford was never a salaried
employee of the Company.
30
<PAGE>
Item 12. Security Ownership of Certain Beneficial Owners and Management
The following table summarizes certain information as of March 15, 2000
with respect to the ownership by each director, by each executive officer
named in the "Executive Compensation" section above, by all executive officers
and directors as a group, and by each other person known by the Company to be
the beneficial owner of more than five percent of the common stock:
<TABLE>
<CAPTION>
Name of Amount/Nature
Beneficial of Beneficial Percent of Class
Owner Ownership Beneficially Owned
---------- ------------- ------------------
<S> <C> <C>
William J. Barrett................. 595,199 (1) 1.8%
C. Robert Buford................... 642,866 (2) 2.0%
Derrill Cody....................... 31,560 (3) *
Peter A. Dea....................... 65,740 (3) *
James M. Fitzgibbons............... 28,500 (3) *
William W. Grant, III.............. 39,250 (3) *
Bryan G. Hassler................... 34,741 (3) *
J. Frank Keller.................... 139,197 (3) *
A. Ralph Reed...................... 141,666 (4) *
James T. Rodgers................... 28,000 (3) *
Philippe S.E. Schreiber............ 27,507 (3) *
All Directors and Executive
Officers as a Group (16 Persons).. 1,998,036 (5) 6.0%
Franklin Resources, Inc............ 3,627,021 Shares(6) 11.1%
777 Mariners Island
San Mateo, CA 94403
State Farm Mutual Automobile
Insurance Company and affiliates.. 2,936,938 Shares(6)(7) 9.0%
One State Farm Plaza
Bloomington, IL 61710
</TABLE>
- --------
* Less than 1% of the common stock outstanding.
(1) The number of shares indicated includes 90,412 shares owned by Mr.
Barrett's wife, 230,000 shares owned by the Barrett Family L.L.L.P., a
Colorado limited liability limited partnership for which Mr. Barrett and
his wife are general partners and owners of an aggregate of 48.626622
percent of the partnership interests, and 360,000 shares underlying
options that currently are exercisable or become exercisable within 60
days following March 15, 2000. Pursuant to Rule 16a-1(a)(4) under the
Exchange Act, Mr. Barrett disclaims ownership of all but 111,841 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 548,210 shares of
which Zenith is the record owner. Mr. Buford owns approximately 89 percent
of the outstanding common stock of Zenith. The number of shares of the
Company's stock indicated for Mr. Buford also includes 10,000 shares that
are owned by Aguilla Corporation, which is owned by Mr. Buford's wife and
adult children. Mr. Buford disclaims beneficial ownership of the shares
held by Aguilla Corporation pursuant to Rule 16a-1(a)(4) under the
Exchange Act. The number of shares indicated also includes 20,500 shares
underlying stock options that currently are exercisable or that become
exercisable within 60 days following March 15, 2000.
(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 60 days following March 15, 2000 that are held
by each of the following persons: Derrill Cody, 31,300; Peter A. Dea,
56,157; James M. Fitzgibbons, 16,500; William W. Grant, III, 26,900; Bryan
G. Hassler, 31,512; J. Frank Keller, 67,812; James T. Rodgers, 18,000; and
Philippe S.E. Schreiber, 20,500.
(4) The number of shares indicated includes 6,700 shares owned by Mary C.
Reed, Mr. Reed's wife, and 88,125 shares underlying options that currently
are exercisable or that become exercisable within 60 days following March
15, 2000.
31
<PAGE>
(5) The number of shares indicated includes the shares owned by Zenith that
are beneficially owned by Mr. Buford as described in note (2) and the
aggregate of 737,306 shares underlying the options described in notes (1),
(2), (3) and (4), an aggregate of 38,010 shares owned by six executive
officers not named in the above table, and an aggregate of 185,800 shares
underlying options that currently are exercisable or that are exercisable
within 60 days following March 15, 2000 that are held by those six
executive officers.
(6) Based on information included in a Schedule 13G filed with the Securities
and Exchange Commission by the named stockholders.
(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.
Item 13. Certain Relationships and Related Transactions
During 1999, there were no transactions between the Company and its
directors, executive officers or known holders of greater than five percent of
the Company's Common Stock in which the amount involved exceeded $60,000 and
in which any of the foregoing persons had or will have a material interest.
32
<PAGE>
PART IV
Item 14. Exhibits, Financial Schedules, and Reports on Form 8-K
(a)(1) and (a)(2) Financial Statements And Financial Statement Schedules
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
<TABLE>
<S> <C>
Report of Independent Public Accountants.............................. F-1
Consolidated Balance Sheets at December 31, 1999 and 1998............. F-2
Consolidated Statements of Income for each of the three years in the
period ended
December 31, 1999.................................................... F-3
Consolidated Statements of Stockholders' Equity for each of the three
years in the period ended December 31, 1999.......................... F-4
Consolidated Statements of Cash Flows for each of the three years in
the period ended
December 31, 1999.................................................... F-5
Notes to the Consolidated Financial Statements........................ F-6
Supplemental Oil And Gas Information.................................. F-21
</TABLE>
All other schedules are omitted because the required information is not
present in amounts sufficient to require submission of the schedule or because
the information required is included in the Consolidated Financial Statements
and Notes thereto.
(a)(3) Exhibits
See "EXHIBIT INDEX" on page 34.
(b) Reports on Form 8-K. No Current Reports on Form 8-K were filed during
the fourth quarter of the year ended December 31, 1999.
33
<PAGE>
BARRETT RESOURCES CORPORATION
ANNUAL REPORT ON FORM 10-K
For The Year Ended December 31, 1999
EXHIBIT INDEX
<TABLE>
<CAPTION>
Exhibit Description
------- -----------
<C> <S>
2.1 Agreement And Plan of Merger, dated as of May 2, 1995, among Barrett
Resources Corporation ("Barrett" or "Registrant"), Barrett Energy Inc.
(formerly known as Vanilla Corporation), and Plains Petroleum Company
("Plains") is incorporated by reference from Annex I to the Joint
Proxy Statement/Prospectus of Barrett and Plains dated June 13, 1995.
3.1 Restated Certificate Of Incorporation of Barrett Resources
Corporation, a Delaware corporation, is Incorporated herein by
reference from Exhibit 3.2 of Registrant's Registration Statement on
Form S-4 dated June 9, 1995.
3.2 Certificate of Amendment to Certificate of Incorporation of Barrett
dated June 17, 1997 is Incorporated by reference from Exhibit 3.2 of
Registrant's Annual Report on Form 10-K for the Year ended December
31, 1997.
3.3 Bylaws of Barrett, as amended through February 25, 1999, is
incorporated by reference from Exhibit 3.3 of Registrant's Annual
Report on Form 10-K for the year ended December 31, 1998.
4.1A Form of Rights Agreement dated as of August 5, 1997 between Barrett
and BankBoston, N.A., Which includes, as Exhibit A thereto, the form
of Certificate of Designations specifying the terms of The Series A
Junior Participating Preferred Stock, and as Exhibit B thereto, the
form of Rights Certificate, is incorporated by reference from Exhibit
1 to the Company's Registration Statement on Form 8-A filed August 11,
1997.
4.1B Amendment to Rights Agreement dated August 5, 1997 between Barrett and
BankBoston, N.A. is incorporated by reference from Exhibit 4.1B of
Registrant's Annual Report on Form 10-K for the year ended December
31, 1998.
4.2 Revised Form of Indenture between the Company and Bankers Trust
Company, as trustee, with Respect to Senior Notes including specimen
of 7.55% Senior Notes is incorporated by reference from Exhibit 4.1 to
the Company's Amendment No. 1 to Registration Statement on Form S-3
filed February 10, 1997 (File No. 333-19363).
4.3 Form of Indenture between the Registrant and Bankers Trust Company, as
trustee, with respect to Debt Securities is incorporated by reference
from Exhibit 4.2 of Registrant's Registration Statement on Form S-3
filed May 6, 1998 (File No. 333-51985).
10.1 Non-Qualified Stock Option Plan Of Barrett Resources Corporation is
incorporated by reference from Registrant's Registration Statement on
Form S-8 dated November 15, 1989.
10.2 Registrant's 1990 Stock Option Plan, as amended, is incorporated by
reference from the Registrant's Registration Statement on Form S-8
dated March 15, 1995.
10.3 Registrant's Non-Discretionary Stock Option, as amended, is
incorporated by reference from Exhibit 99.2 of the Registrant's Proxy
Statement dated April 24, 1997.
10.4 Registrant's 1994 Stock Option Plan, as amended, is incorporated by
reference from the Registrant's Registration Statement on Form S-8
dated March 15, 1995.
10.5 Registrant's 1997 Stock Option Plan is incorporated by reference from
Exhibit 99.1 of the Registrant's Proxy Statement dated April 24, 1997.
</TABLE>
34
<PAGE>
<TABLE>
<CAPTION>
Exhibit Description
------- -----------
<C> <S>
10.6A Revolving Credit Agreement dated as of July 19, 1995 among Barrett and
Texas Commerce Bank National Association, as Agent, and Texas Commerce
Bank National Association, Nations Bank of Texas, N.A., Bank of
Montreal, Houston Agency, Colorado National Bank, and The First
National Bank of Boston, as the "Banks", is incorporated by reference
from Exhibit 10.6 to Barrett's Annual Report on Form 10-K for the year
ended December 31, 1995.
10.6B First Amendment to Revolving Credit Agreement dated October 31, 1996
between and among Barrett, Agent and the Banks is incorporated by
reference from Exhibit 10.1 to Amendment No. 2 to Barrett's
Registration Statement on Form S-3 (File No. 333-19363) dated February
10, 1997.
10.6C Second Amendment to Revolving Credit Agreement dated February 10, 1997
between and among Barrett, the Agent, and the Banks is incorporated by
reference from Exhibit 10.2 to Amendment No. 2 to Barrett's
Registration Statement on Form S-3 (File No. 333-19363) dated February
10, 1997.
10.6D Amended and Restated Credit Agreement dated November 12, 1997 between
and among Barrett, the Agent, the Banks, and The Chase Manhattan Bank
as the "Competitive Bid Auction Agent" is Incorporated by reference
from Exhibit 10.7D to Registrant's Annual Report on Form 10-K for the
Year ended December 31, 1997.
10.6E First Amendment to Amended and Restated Credit Agreement dated
December 19, 1997 between and among Barrett, the Agent, the Banks, and
the Competitive Bid Auction Agent is incorporated by reference from
Exhibit 10.7E to Registrant's Annual Report on Form 10-K for the year
ended December 31, 1997.
10.7A Severance Protection Agreement dated February 6, 1998 between
Registrant and William J. Barrett is incorporated by reference from
Exhibit 10.8 to Registrant's Annual Report on Form 10-K for the year
ended December 31, 1997.
10.7B Amendment No. 1 to Severance Protection Agreement dated November 19,
1998 between Registrant and William J. Barrett is incorporated by
reference from Exhibit 10.8B of Registrant's Annual Report on Form 10-
K for the year ended December 31, 1998.
10.8A Form of Severance Protection Agreement between Barrett and each of A.
Ralph Reed, J. Frank Keller, Peter A. Dea and Bryan G. Hassler is
incorporated by reference from Exhibit 10.9A to Registrant's Annual
Report on Form 10-K for the year ended December 31, 1997.
10.8B Schedule Identifying Material Differences Among Severance Protection
Agreements between Barrett and each of A. Ralph Reed, J. Frank Keller,
Peter A. Dea, and Bryan G. Hassler is incorporated by reference from
Exhibit 10.9B of Registrant's Annual Report on Form 10-K for the year
ended December 31, 1998.
10.8C Amendment No. 1 dated November 18, 1999 to Severance Protection
Agreement dated February 9, 1998 between Registrant and Peter A. Dea.
21 List of Subsidiaries.
23.1 Consent of Arthur Andersen LLP.
23.2 Consent of Ryder Scott Company.
23.3 Consent of Netherland, Sewell & Associates, Inc.
27 Financial Data Schedule.
</TABLE>
35
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of Barrett Resources Corporation
We have audited the accompanying consolidated balance sheets of Barrett
Resources Corporation (a Delaware corporation) and subsidiaries as of December
31, 1999 and 1998, and the related consolidated statements of income,
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 1999. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on
a test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used
and significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Barrett Resources
Corporation and subsidiaries as of December 31, 1999 and 1998, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 1999, in conformity with accounting principles
generally accepted in the United States.
Arthur Andersen LLP
Denver, Colorado
March 1, 2000
F-1
<PAGE>
BARRETT RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
December 31, 1999 and 1998
(in thousands)
<TABLE>
<CAPTION>
1999 1998
-------- --------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents.................................. $ 20,634 $ 14,339
Receivables, net........................................... 99,906 127,798
Inventory.................................................. 22,934 8,968
Other current assets....................................... 11,048 2,053
-------- --------
Total current assets..................................... 154,522 153,158
Net property and equipment (full cost method)................ 726,489 682,168
Other assets, net............................................ 3,290 3,553
-------- --------
$884,301 $838,879
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable........................................... $ 94,293 $104,799
Amounts payable to oil and gas property owners............. 5,879 16,020
Production taxes payable................................... 22,981 20,400
Accrued and other liabilities.............................. 16,610 17,047
-------- --------
Total current liabilities................................ 139,763 158,266
Long term debt............................................... 355,250 334,067
Deferred income taxes........................................ 25,640 13,294
Commitments and contingencies--Note 10
Stockholders' equity:
Preferred stock, $.001 par value: 1,000,000 shares autho-
rized, none outstanding................................... -- --
Common stock, $.01 par value: 45,000,000 shares authorized,
32,589,774 and 32,002,304 shares issued and outstanding,
respectively.............................................. 326 320
Additional paid-in capital................................. 271,560 261,998
Retained earnings.......................................... 91,762 70,934
-------- --------
Total stockholders' equity............................... 363,648 333,252
-------- --------
$884,301 $838,879
======== ========
</TABLE>
See accompanying notes.
F-2
<PAGE>
BARRETT RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
Years ended December 31, 1999, 1998 and 1997
(in thousands, except per share data)
<TABLE>
<CAPTION>
1999 1998 1997
--------- --------- --------
<S> <C> <C> <C>
Revenues:
Oil and gas production.......................... $ 206,916 $ 205,501 $206,907
Trading revenues................................ 792,016 412,982 171,140
Interest income................................. 826 649 1,573
Other income.................................... 5,023 6,267 2,980
--------- --------- --------
1,004,781 625,399 382,600
Operating expenses:
Lease operating expenses........................ 62,076 58,626 57,904
Depreciation, depletion and amortization........ 90,668 102,123 72,389
Impairment...................................... -- 168,304 --
Cost of trading................................. 773,171 398,041 165,218
General and administrative...................... 23,849 24,546 24,890
Interest expense................................ 21,521 20,858 13,243
Other expenses, net............................. 158 2,412 1,770
--------- --------- --------
971,443 774,910 335,414
--------- --------- --------
Income (loss) before income taxes................. 33,338 (149,511) 47,186
Provision (benefit) for income taxes.............. 12,510 (55,768) 17,925
--------- --------- --------
Net income (loss)................................. $ 20,828 $ (93,743) $ 29,261
========= ========= ========
Earnings (loss) per common share
Basic........................................... $ .64 $ (2.95) $ .93
Assuming dilution............................... $ .64 $ (2.95) $ .92
</TABLE>
See accompanying notes.
F-3
<PAGE>
BARRETT RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Years ended December 31, 1999, 1998 and 1997
(in thousands)
<TABLE>
<CAPTION>
Additional Total
Common Paid-In Treasury Retained Stockholders'
Stock Capital Stock Earnings Equity
------ ---------- -------- -------- -------------
<S> <C> <C> <C> <C> <C>
Balance, January 1, 1997.... $313 $241,991 $-- $135,416 $377,720
Exercise of stock
options.................. 1 1,389 (207) -- 1,183
Purchase of treasury
stock.................... -- -- (2) -- (2)
Retirement of 5,684 shares
of treasury stock........ -- (209) 209 -- --
Fair value of put option
issued in connection with
property acquisitions.... -- 4,219 -- -- 4,219
Net income for the year
ended
December 31, 1997........ -- -- -- 29,261 29,261
---- -------- ---- -------- --------
Balance, December 31, 1997.. 314 247,390 -- 164,677 412,381
Exercise of stock
options.................. 3 5,728 (233) -- 5,498
Retirement of 8,280 shares
of treasury stock........ -- (233) 233 -- --
Stock issued in connection
with property
acquisitions............. 3 9,113 -- -- 9,116
Net loss for the year
ended December 31, 1998.. -- -- -- (93,743) (93,743)
---- -------- ---- -------- --------
Balance, December 31, 1998.. 320 261,998 -- 70,934 333,252
Exercise of stock
options.................. 4 10,353 (789) -- 9,568
Exercise of put option.... 2 (2) -- -- --
Retirement of 28,217
shares of treasury
stock.................... -- (789) 789 -- --
Net income for the year
ended
December 31, 1999........ -- -- -- 20,828 20,828
---- -------- ---- -------- --------
Balance, December 31, 1999.. $326 $271,560 $-- $ 91,762 $363,648
==== ======== ==== ======== ========
</TABLE>
See accompanying notes.
F-4
<PAGE>
BARRETT RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years ended December 31, 1999, 1998 and 1997
(in thousands)
<TABLE>
<CAPTION>
1999 1998 1997
--------- ---------- ---------
<S> <C> <C> <C>
Cash flows from operations:
Net income (loss).......................... $ 20,828 $ (93,743) $ 29,261
Adjustments needed to reconcile to net cash
flow provided by operations:
Depreciation, depletion and amortization
and impairment.......................... 91,193 270,858 72,743
Unrealized gain on trading............... (1,379) -- --
Deferred income taxes.................... 12,347 (55,683) 18,069
Other.................................... (770) (2,168) --
--------- ---------- ---------
122,219 119,264 120,073
Change in current assets and liabilities:
Receivables................................ 27,892 (24,864) (29,889)
Other current assets....................... (20,591) (6,383) (1,697)
Accounts payable........................... (10,506) 42,929 20,253
Amounts due oil and gas property owners.... (10,141) (11,154) 8,678
Production taxes payable................... 2,581 2,455 4,115
Accrued and other liabilities.............. 776 (5,277) 12,749
--------- ---------- ---------
Net cash flow provided by operations......... 112,230 116,970 134,282
--------- ---------- ---------
Cash flows from investing activities:
Proceeds from sales of oil and gas
properties................................ 24, 685 6,393 14,233
Acquisitions of property and equipment..... (160,928) (203,056) (340,015)
--------- ---------- ---------
Net cash flow used in investing activities... (136,243) (196,663) (325,782)
--------- ---------- ---------
Cash flows from financing activities:
Proceeds from issuance of common stock..... 9,568 5,498 1,183
Purchase of treasury stock................. -- -- (2)
Proceeds from long-term borrowing.......... 100,000 119,000 130,577
Payments on long-term debt................. (79,260) (44,794) (86,131)
Proceeds from Senior Notes, net of offering
costs..................................... -- -- 145,963
Other...................................... -- (151) (150)
--------- ---------- ---------
Net cash flow provided by financing
activities.................................. 30,308 79,553 191,440
--------- ---------- ---------
Increase (decrease) in cash and cash
equivalents................................. 6,295 (140) (60)
Cash and cash equivalents at beginning of
year........................................ 14,339 14,479 14,539
--------- ---------- ---------
Cash and cash equivalents at end of year..... $ 20,634 $ 14,339 $ 14,479
========= ========== =========
</TABLE>
See accompanying notes.
F-5
<PAGE>
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
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
principally in the Rocky Mountain and Mid-Continent regions. The Company also
operates gas gathering systems and related facilities in certain areas in
which the Company owns production. In addition, the Company engages in natural
gas trading activities, which involve purchasing natural gas from third
parties and selling natural gas to other parties. The Company also has
exploration activities in the Republic of Peru.
Principles of consolidation
The consolidated financial statements include the accounts of the Company
and its subsidiaries, all of which are wholly owned. All significant
intercompany transactions have been eliminated in consolidation.
Reclassifications
Certain reclassifications have been made to 1998 and 1997 amounts to
conform to the 1999 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.
Credit Risk
Financial instruments which potentially subject the Company to
concentrations of credit risk consist principally of temporary cash
investments, receivables and derivative instruments. The Company places its
temporary cash investments with high credit quality financial institutions.
The Company's receivables result from operation and trading activities and are
primarily due from many customers including amounts due from oil and gas
entities in the Rocky Mountain region and from industrial end-users and local
distribution companies. The Company routinely assesses the financial strength
of its customers. As a result, concentrations of credit risk are
F-6
<PAGE>
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
limited. There are no significant concentrations of credit risk with any
counterparties related to the Company's derivatives. The Company analyzes the
financial condition of each counterparty prior to entering into a transaction,
establishes credit limits and monitors the appropriateness of these limits on
an ongoing basis. Based on these assessments, the Company may require a
standby letter of credit or a financial guarantee. Traded futures and option
contracts entered into with the New York Mercantile Exchange ("Exchange") are
guaranteed by the Exchange and have nominal credit risk.
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 involving the transfer of
significant amounts of oil and gas reserves.
Capitalized costs are accumulated on a country-by-country basis subject to
a cost center ceiling and amortized using the units-of-production method. The
Company presently has two cost centers: the United States and the Republic of
Peru. Amortizable costs include estimated future development costs of proved
reserves and estimated dismantlement costs, but exclude the costs of
unevaluated oil and gas properties. Accumulated depreciation is written off as
assets are retired. Depletion and amortization equaled approximately $.83,
$.92 and $.77 per Mcfe ($4.99, $5.49 and $4.60 per BOE) during the years ended
December 31, 1999, 1998 and 1997, respectively. Included in accumulated
depletion, depreciation and amortization is the Company's accrual for future
abandonment costs. Total abandonment costs of approximately $3.2 million are
included in the depletable base. In 1998, the ceiling test limitation resulted
in the Company recognizing a pre-tax impairment expense of $129 million and
$39 million on its oil and gas properties located in the United States and
Peru, respectively.
The Company leases non-producing acreage for its exploration and
development activities. The cost of these leases is included in unevaluated
oil and gas property costs recorded at the lower of cost or fair market value.
The Company operates many of the wells in which it owns an economic
interest. The operating agreements for these activities provide for a fee
structure to allow the Company to recover a portion of its direct and overhead
charges related to its operating activities. The fees collected under the
operating agreements are recorded as a reduction of general and administrative
expenses. Any amounts collected from a sale of oil and gas interests or earned
as a result of assembling oil and gas drilling activities are applied to
reduce the book value of oil and gas properties.
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.
Unamortized debt discount and expense
Discounts and expenses incurred in connection with the issuance of
presently outstanding long-term debt are amortized on a straight-line basis
over the terms of the respective issue.
F-7
<PAGE>
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Amounts payable to oil and gas property owners
Amounts payable to oil and gas property owners consist of cash calls from
working interest owners to pay for development costs of properties being
currently developed and production revenue that the Company, as operator, is
collecting and distributing to revenue interest owners.
Trading and hedging activities
The Company's business activities include the buying and selling of natural
gas. The Company currently recognizes revenue and costs on gas trading
transactions at the point in time when gas is delivered to the purchaser. All
trading revenues and expenses are presented on a gross basis in the
accompanying financial statements.
The Company uses both commodity futures contracts and price swaps to hedge
the impact of price fluctuations on a portion of its production and trading
activities. The Company enters into a hedging position for specific
transactions that, in management's opinion, may 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 and are recorded at fair value. As
of December 31, 1999, the Company, utilizing appropriate mark to market
criteria, has recorded an unrealized gain on these contracts of approximately
$1.4 million. Gains and losses are recognized as fair values fluctuate from
period to period as 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. 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 (loss) per share
Earnings (loss) per share ("EPS") is based on the weighted-average number
of common shares outstanding (referred to as basic earnings (loss) per share)
and earnings per share giving effect to all dilutive potential common shares
that were outstanding during the reporting period (referred to as diluted
earnings (loss) per share or earnings (loss) per share-assuming dilution).
The following data show the amounts used in computing earnings (loss) per
share and the effect on income (loss) and the weighted average number of
shares of dilutive potential common stock.
<TABLE>
<CAPTION>
For the years ended
December 31,
-------------------------
1999 1998 1997
------- -------- -------
(In thousands )
<S> <C> <C> <C>
Income (loss) available to common stockholders.... $20,828 $(93,743) $29,261
======= ======== =======
Weighted average number of common shares used in
basic EPS........................................ 32,307 31,756 31,367
Effect of dilutive securities (see Note 7):
Stock options................................... 395 -- 466
Written put option.............................. 88 -- 107
------- -------- -------
Weighted average number of common shares and
dilutive potential common stock used in EPS--
assuming dilution................................ 32,790 31,756 31,940
======= ======== =======
</TABLE>
F-8
<PAGE>
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
On August 3, 1999, the holder of the written put option elected to exercise
such option and, accordingly, the Company issued 150,000 shares of its common
stock. In conjunction with the exercise of this option, the Company received
the holder's one percent interest in a subsidiary of the Company.
Dilutive securities were not included in computing diluted EPS for 1998
because their effects were antidilutive.
Recently Issued Accounting Standards
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133 ("SFAS 133"), "Accounting for
Derivative Instruments and Hedging Activities." SFAS 133 establishes
accounting and reporting standards requiring that every derivative instrument
(including certain derivative instruments embedded in other contracts) be
recorded in the balance sheet as either an asset or liability measured at its
fair value. It also requires that changes in the derivative's fair value be
recognized currently in earnings unless specific hedge accounting criteria are
met. Special accounting for qualifying hedges allows a derivative's gains and
losses to offset related results on the hedged item in the income statement,
and requires that a company must formally document, designate, and assess the
effectiveness of transactions that receive hedge accounting. Statement of
Financial Accounting Standards No. 137, issued in 1999, delayed the adoption
of SFAS 133. The adoption of SFAS 133 will be January 1, 2001 for the Company.
The Company has not yet quantified the impacts of adopting SFAS 133 on its
financial statements and has not determined the timing of or method of
adoption of SFAS 133. However, SFAS 133 could substantially increase
volatility in earnings and other comprehensive income.
2. ACQUISITIONS
On December 16, 1999 and January 7, 2000, in separate transactions, the
Company acquired additional working interests in the Piceance Basin gas
properties in northwestern Colorado and all of the outstanding joint venture
interest in a related gas gathering system, processing plant and pipeline from
several industry partners for a total purchase price of approximately $83.0
million. The acquisitions (accounted for under the purchase method) were
financed primarily with funds from the Company's Line of Credit. Approximately
$47.3 million was funded in December 1999 and the balance of $35.7 million was
funded in January 2000.
The Company's 1999 Consolidated Statements of Income include only one month
of operations for the property interest acquired in December 1999. The
following unaudited pro forma consolidated results of operations assume the
acquisitions occurred on January 1 of each year. The pro forma results do not
necessarily represent results which would have occurred if the acquisitions
had taken place on the basis assumed above, nor are they indicative of the
results of future combined operations.
<TABLE>
<CAPTION>
Year Ended December
31,
-------------------
1999 1998
(in thousands, except per share amounts) ---------- --------
(Unaudited)
<S> <C> <C>
Total Revenues.......................................... $1,025,003 $648,010
Net Income (Loss)....................................... $ 22,592 $(93,324)
Earnings (loss) per common share
Basic................................................. $ .70 $ (2.94)
Assuming dilution..................................... $ .69 $ (2.94)
</TABLE>
The pro forma amounts reflect the results of operations for the Company,
the acquired working interests, and the following purchase accounting
adjustments for the periods presented:
. Elimination of certain inter-company transactions.
F-9
<PAGE>
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
. Depletion and Depreciation on the acquired interests.
. Additional incremental interest expense on additional debt that would
have been incurred to finance these acquisitions.
. Estimated income tax effect on the pro forma adjustments.
3. RECEIVABLES
<TABLE>
<CAPTION>
1999 1998
-------- --------
(in thousands)
<S> <C> <C>
Oil and gas revenue and trading receivables............... $ 84,317 $108,969
Joint interest billings................................... 10,625 16,074
Other accounts receivable................................. 4,964 2,755
-------- --------
$ 99,906 $127,798
======== ========
</TABLE>
The Company's accounts receivable are primarily due from oil and gas
entities in the Rocky Mountain region and from industrial end-users and local
distribution companies. Collection of joint interest billings is generally
secured by future production. The Company performs periodic credit evaluations
of customers purchasing production and purchased natural gas for which no
collateral is required. Based upon these evaluations, the Company may require
a standby letter of credit or a financial guarantee. Historically, the Company
has not experienced significant losses related to these extensions of credit.
As of December 31, 1999 and 1998, receivables are recorded net of allowance
for doubtful accounts of $1,912,000 and $2,199,000, respectively.
4. INVENTORY
Materials and supplies and natural gas inventory are stated at the lower of
average cost or market. Natural gas, when sold from inventory, is charged to
expense using the average-cost method.
<TABLE>
<CAPTION>
1999 1998
------- ------
(in thousands)
<S> <C> <C>
Natural Gas................................................... $19,907 $7,195
Material and Supplies......................................... 3,027 1,773
------- ------
$22,934 $8,968
======= ======
</TABLE>
5. PROPERTY AND EQUIPMENT
<TABLE>
<CAPTION>
1999 1998
---------- ----------
(in thousands)
<S> <C> <C>
Oil and gas properties, full cost method:
Unevaluated costs, not being amortized........... $ 67,676 $ 57,914
Evaluated costs.................................. 1,231,417 1,109,822
Gas gathering systems............................ 40,627 38,799
Furniture, vehicles and equipment.................. 12,375 11,120
---------- ----------
1,352,095 1,217,655
Less accumulated depreciation, depletion, amortiza-
tion and impairment............................... (625,606) (535,487)
---------- ----------
$ 726,489 $ 682,168
========== ==========
</TABLE>
F-10
<PAGE>
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
6. UNEVALUATED OIL AND GAS PROPERTY COSTS
Unevaluated oil and gas property costs associated with unevaluated
properties and major development projects consist of the following:
<TABLE>
<CAPTION>
Costs incurred during
--------------------------------------
1999 1998 1997 Prior Total
------- ------- ------- ------ -------
(in thousands)
<S> <C> <C> <C> <C> <C>
United States
Acquisition costs..................... $12,696 $19,412 $17,757 $1,996 $51,861
Exploration costs..................... 14,139 777 207 7 15,130
Peru--Acquisition costs ................ 685 -- -- -- 685
------- ------- ------- ------ -------
$27,520 $20,189 $17,964 $2,003 $67,676
======= ======= ======= ====== =======
</TABLE>
The unevaluated costs were incurred for projects which are being explored.
The Company anticipates that substantially all unevaluated costs will be
classified as evaluated costs within the next five years.
7. LONG-TERM DEBT
<TABLE>
<CAPTION>
1999 1998
-------- --------
(in thousands)
<S> <C> <C>
Line of Credit............................................ $200,000 $175,000
7.55% Senior Notes........................................ 150,000 150,000
Production Payments....................................... 9,369 14,399
-------- --------
Total..................................................... 359,369 339,399
Less: current portion, included in other liabilities...... 4,119 5,332
-------- --------
Long-term debt............................................ $355,250 $334,067
======== ========
</TABLE>
Line of Credit
The Company has a reserve-based line of credit with a group of banks which
provides up to $250 million, maturing September 30, 2002. 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, 1999 (which was
based on an unaudited June 30, 1999 reserve report, plus reserve additions
from certain acquisitions made in December 1999), the Company's borrowing
limit was $236 million. In conjunction with property acquisitions made in
January 2000 (see Note 2), the borrowing limit was increased to $250 million.
The lenders are currently reviewing the December 31, 1999 reserve report
together with changes in reserves resulting from acquisitions and divestitures
of property interests subsequent to December 31, 1999 to determine current
collateral value. At the conclusion of this review, the borrowing base could
change. The Company is required to pay only interest on funds borrowed during
the revolving period. At its option, the Company has elected to use the London
Interbank Eurodollar Rate (LIBOR) plus a spread ranging from .185 percent to
.625 percent (depending on the Company's Senior Debt Rating and the ratio of
the Company's outstanding indebtness to its earnings before interest, taxes
and depreciation, depletion and amortization) for a substantial portion of the
outstanding balance. As of December 31, 1999 the Company's outstanding balance
under the line of credit was $200 million which was accruing interest at an
average LIBOR based rate of 6.501 percent. As of January 7, 2000, in
conjunction with the funding of an acquisition on the same date, the Company's
outstanding balance of its line of credit increased to $225 million.The line
of credit agreement provides for facility fees ranging between 9/100 of one
percent and 37.5/100 of one percent of the lesser of the available commitment
F-11
<PAGE>
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
and the borrowing base. The Credit Agreement restricts the payment of
dividends, borrowings, sale of assets, loans to others, and 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.
7.55% Senior Notes
In February 1997, the Company completed a public offering of $150 million
(principal amount) of its 7.55% Senior Notes due 2007 ("Notes"). A portion of
the net proceeds from the offering was used to repay the Company's existing
line of credit. The Notes are senior unsecured obligations of the Company
ranking equally in right of payment to all existing and future senior
indebtedness of the Company. At the option of the Company, the Notes may be
redeemed at any time, in whole or in part, by paying an amount specified for a
make-whole premium. The indenture of the Notes limits the Company's ability to
incur indebtedness secured by certain liens, engage in certain sale/leaseback
transactions, and engage in certain merger, consolidation or reorganization
transactions. Interest is paid semi-annually on February 1 and August 1 of
each year.
Production Payments
In November 1997, the Company sold its interest in certain Colorado
properties to an investment group which includes a Company subsidiary. For
accounting purposes, the Company has treated the sale as a non-recourse
monetary production payment reflected in long-term liabilities on the balance
sheet. Net of transaction costs, the proceeds from the sale were approximately
$15.5 million in cash. Payments of the production payment liability are funded
from the operating cash flow of the properties, less funds required for
working capital purposes. The liability is expected to be fully repaid by
2003.
The aggregate amount of long-term debt maturities, (including estimated
operating cash flows from properties designated for production payments) for
each of the five years after 1999 are: $4.1 million, $3.4 million, $201.9
million and $150 million for remaining years.
Fair value of financial instruments
The estimated fair values of the Company's financial instruments are:
<TABLE>
<CAPTION>
Carrying Fair
Amount Value
-------- --------
(in thousands)
<S> <C> <C>
1999
Cash and cash equivalents................................. $ 20,634 $ 20,634
Long-term debt (including current portion)................ 359,369 353,926
1998
Cash and cash equivalents................................. $ 14,339 $ 14,339
Long-term debt (including current portion)................ 339,399 339,106
</TABLE>
The carrying amounts of accounts receivable, accounts payable and accrued
liabilities approximate fair value because of the short-term nature of these
instruments.
The fair value of the Company's long-term debt is estimated based on
current rates and re-pricing terms available to the Company for its Line of
Credit and on quoted market prices for the 7.55% Senior Notes.
Outstanding letters of credit totaled approximately $2.8 million at
December 31, 1999. The letters of credit guarantee performance to third
parties. The Company does not expect any losses due to non-performance and,
therefore, believes that the fair value of these instruments is zero.
F-12
<PAGE>
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
8. COMMON STOCK AND OPTIONS
Common Stock
In August 1999, the holder of a written put option, issued by the Company
in April 1997 in conjunction with a property acquisition, elected to exercise
such option. Pursuant to the terms of this option, the Company issued 150,000
shares of its common stock and, in return, received the holder's one percent
interest in a subsidiary of the Company.
In March 1998, the Company issued 260,917 shares of its common stock in an
acquisition of a company whose sole asset is a 15 percent interest in an oil
and gas license covering an area denominated as Block 67 located in the
Republic of Peru.
In June 1997, the Company's shareholders voted to increase the authorized
number of shares of the Company's common stock from 35 million to 45 million.
During 1999, 1998 and 1997, the Company acquired treasury stock only as a
result of stock option exercises or the buy back of shares, which were
unsolicited from stockholders. Treasury stock acquired during any year was
retired at the end of that year.
The Company has a stockholders rights plan designed to insure that
stockholders receive full value for their shares in the event of certain
takeover attempts.
Stock Options
The Company has three employee stock option plans, a 1994 Plan, a 1997 Plan
and a 1999 Plan, under which the Company's common stock may be granted to
officers and other employees of the Company and subsidiaries. The 1994 Plan as
amended, the 1997 Plan and the 1999 Plan provide for the granting of options
to purchase 1,000,000, 1,500,000 and 600,000 shares of the Company's common
stock, respectively. In addition, the Company has a non-discretionary stock
option plan, as amended, under which options for an aggregate of 300,000
shares of the Company's common stock may be granted to non-employee directors.
Effective with the 1995 merger of the Company and Plains Petroleum Company
("Plains"), the Company assumed preexisting stock option plans of Plains and
converted all options then outstanding into options to acquire shares of the
Company's common stock. No further options will be granted under the Plains'
plans.
Pursuant to the plans, the exercise price of each option cannot be less
than the market price of the Company's stock on the date of grant. Options
under the Company's plans generally become exercisable in equal installments
on each of the first four anniversaries of the date of grant. All options
granted under the Plains option plans are currently exercisable. The options
expire, to the extent not exercised, between five and ten years after the date
of the grant, or within 90 days (30 days under the Plains plan) after the
recipient's earlier termination of employment with the Company. Options can be
incentive stock options or non-statutory stock options.
F-13
<PAGE>
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Changes in outstanding stock options under these plans are summarized as
follows:
<TABLE>
<CAPTION>
1999 1998 1997
-------------------- -------------------- --------------------
Weighted- Weighted- Weighted-
Number of Average Number of Average Number of Average
Option Exercise Option Exercise Option Exercise
Shares Price Shares Price Shares Price
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning
of year................ 2,609,876 $28.63 2,088,208 $26.29 1,481,559 $22.50
Granted................. 763,945 21.85 1,253,307 30.10 787,250 33.18
Exercised............... (465,687) 22.24 (344,139) 16.96 (83,851) 16.48
Forfeited............... (197,310) 30.46 (387,500) 31.15 (96,750) 32.74
--------- ------ --------- ------ --------- ------
Outstanding at end of
year................... 2,710,824 27.68 2,609,876 28.63 2,088,208 26.29
========= ====== ========= ====== ========= ======
Options exercisable at
year-end............... 990,559 959,326 718,633
Weighted-average fair
value of options
granted during the
year................... $ 11.39 $ 17.27 $ 20.69
</TABLE>
The calculated value of stock options granted under these plans, following
calculation methods prescribed by SFAS 123, uses the Black-Scholes stock option
pricing model with the following weighted-average assumptions used:
<TABLE>
<CAPTION>
1999 1998 1997
----- ----- -----
<S> <C> <C> <C>
Expected option life--years............................. 4.82 5.54 5.44
Risk-free interest rate................................. 5.47% 5.19% 6.78%
Dividend yield.......................................... 0 0 0
Volatility.............................................. 55.33% 56.87% 57.47%
</TABLE>
The following table summarizes information about stock options outstanding
at December 31, 1999:
<TABLE>
<CAPTION>
Stock Options Outstanding Stock Options Exercisable
---------------------------------------------- -----------------------------
Number Weighted-Average Weighted- Number Weighted-
Range of Outstanding at Remaining Average Exercisable at Average
Exercise Prices 12/31/99 Contractual Life Exercise Price 12/31/99 Exercise Price
--------------- -------------- ---------------- -------------- -------------- --------------
<S> <C> <C> <C> <C> <C>
$12--20 527,953 5.9 $16.56 34,401 $17.98
20--25 631,284 4.3 23.30 357,071 23.11
25--30 122,690 3.9 28.35 59,940 28.38
30--35 1,244,897 4.7 32.96 453,647 33.01
35--40 123,500 4.4 36.59 45,125 37.09
40--43 60,500 4.0 42.44 40,375 42.42
--------- --- ------ ------- ------
2,710,824 4.8 $27.68 990,559 $29.21
========= ======= ======
</TABLE>
F-14
<PAGE>
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The Company applies APB Opinion No. 25 and related interpretations in
accounting for stock options. Accordingly, no compensation cost has been
recognized for its stock options. Had compensation cost for the options been
determined based on fair value at grant dates since 1996, as presented by SFAS
No. 123, the Company's net income (loss) and earnings (loss) per share would
have been the pro forma amounts indicated below.
<TABLE>
<CAPTION>
For the Year Ended
December 31,
--------------------------
1999 1998 1997
------- --------- -------
(in thousands)
<S> <C> <C> <C>
Net income (loss)
As reported..................................... $20,828 $ (93,743) $29,261
Pro forma....................................... $12,832 $(101,008) $22,301
Net income (loss) per share
As reported
Basic......................................... $ .64 $ (2.95) $ .93
Diluted....................................... $ .64 $ (2.95) $ .92
Pro forma
Basic......................................... $ .40 $ (3.18) $ .71
Diluted....................................... $ .39 $ (3.18) $ .70
</TABLE>
9. RETIREMENT BENEFITS
The Company has a voluntary 401(k) employee savings plan. Under this plan,
as amended, the Company matches 100% of each participating employee's
contribution, 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
employee's rights to the Company's matching contributions are subject to a
vesting schedule. Company contributions were $607,000, $675,000 and $434,000
in 1999, 1998 and 1997, respectively.
Pursuant to a 1995 merger agreement between Plains and the Company, Plains'
employee benefit plans were terminated and plan assets were distributed to the
participants. A final distribution for Plains' executive deferred compensation
plan and directors' deferred plan was made to the participants by the trustee
of the assets in January 1998.
10. DERIVATIVES
Production Activities
The Company uses swap agreements to reduce the effect of price and
transportation cost volatility on a portion of its natural gas production. In
a typical swap agreement, on a monthly basis for the term of the swap
agreement, the Company receives or pays the difference between a fixed price
per unit of production and a price based on an agreed-upon third party index.
The Company reviews and monitors the credit standing of the counter party to
each of its swap agreements and believes that the counter party will fully
comply with its contractual obligations.
As of December 31, 1999, the Company had in effect outstanding natural gas
swaps associated with its Rocky Mountain natural gas production of 69.1 Bcf at
varying volumes per month through February 2003. Fixed prices associated with
these swaps range from $1.71 to $2.83 per MMBtu. As of December 31, 1999, the
fair value of these contracts was a negative $29.3 million. The Company does
not have any derivatives on its oil production as of December 31, 1999.
Gains, losses and costs related to the derivatives qualifying as hedges are
not recognized until the related gas or oil production has been produced or
delivered or the financial instrument expires. These gains and losses
F-15
<PAGE>
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
offset prices that have been received for natural gas and oil production. Net
hedging gains and losses are included in oil and gas revenues. For the years
ended December 31, 1999, 1998 and 1997, the Company's losses under its natural
gas production swap agreements were $8.3 million, $0.7 million and $4.3
million, respectively. For 1999, the Company recognized hedging losses of
approximately $4.6 million under its oil production swap agreements. The
Company did not enter into hedging positions for its oil production in 1998 or
1997.
Trading Activities
As of December 31, 1999, the Company had entered into a variety of
contracts to purchase and sell natural gas and oil at both fixed prices and at
index based prices. The Company also enters into financial instruments that
seek to reduce sensitivity to price movements or to create guaranteed margins
on certain delivery and purchase commitments. To the extent the Company has an
underlying physical position in the form of a firm purchase commitment or
Company owned equity reserves, these contracts are considered hedges. The fair
value of these contracts as of December 31, 1999 is an estimated gain of $32.5
million. In the event the Company does not have an underlying physical
commodity from which to settle against, such contracts are marked-to-market on
a quarterly basis and unrealized gains and losses are recognized in the
results of operations currently. Trading activities resulted in net gains of
$19.5 million, $14.9 million and $5.9 million for the years ended December 31,
1999, 1998 and 1997, respectively. Included in the 1999 net trading gain is an
unrealized mark-to-market gain of $1.4 million.
11. COMMITMENTS AND CONTINGENCIES
Lease Commitments
The minimum future payments under the terms of operating leases,
principally for office space, are as follows:
<TABLE>
<CAPTION>
(in thousands)
--------------
<S> <C>
Year ended December 31, 2000.................................. $1,010
2001.......................................................... 372
2002.......................................................... 67
2003.......................................................... 33
------
$1,482
======
</TABLE>
Rent expense was $1,305,000, $1,282,000 and $1,055,000 for the years ended
December 31, 1999, 1998 and 1997, respectively.
Litigation
On July 23, 1999, Plains received a favorable ruling on all contested
issues in a case filed in United States Tax Court arising from the Internal
Revenue Service ("IRS") examination of Plains' 1991, 1992 and 1993 federal
income tax returns. The IRS did not appeal this ruling.
The IRS also examined the federal tax returns of the Company for the
periods ended July 1995, December 1995 and December 1996. Pursuant to a
January 18, 2000 settlement agreement, the Company paid $77,259 to resolve
this matter.
Pursuant to an August 1996 decision of the United States Court of Appeals
for the District of Columbia Circuit and subsequent orders of the FERC,
natural gas producers who received reimbursement for Kansas ad valorem taxes
paid in the mid-1980's on top of the then maximum lawful price for natural gas
have been ordered
F-16
<PAGE>
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
to refund these tax reimbursements plus interest. In connection with this
decision, the Company has refunded $5.46 million (principal and interest),
including an escrowed refund of $1.21 million attributable to royalty interest
owners. As the royalty interest owners reimburse the Company for their
proportionateshare of the refund, the escrowed funds will be released to the
gas purchaser to whom the refund is owed. The Company will be obligated for
royalty owner refunds if it is unsuccessful in recouping these from royalty
owners and is unable to obtain FERC relief for the royalty-related refunds not
recouped. The Company is a party to an appeal challenging the FERC's orders
requiring producers to pay interest on these refund amounts. If this appeal is
successful, the Company will recover approximately $2.6 million of the amount
it has refunded.
At December 31, 1999, the Company was a party to certain other legal
proceedings which have arisen out of the ordinary course of business. Based on
the facts currently available, in management's opinion the liability,
individually or in the aggregate, if any, to the Company resulting from such
actions, including those specifically mentioned above, will not have a
material adverse effect on the Company's consolidated financial position or
results of operations.
Environmental
At year-end 1999, there were no known environmental or other regulatory
matters related to the Company's operations which are reasonably expected to
result in a material liability to the Company. Compliance with environmental
laws and regulations has not had, and in management's opinion is not expected
to have, a material adverse effect on the Company's capital expenditures,
results of operations or competitive position.
12. INCOME TAXES
The provision for income taxes consists of the following:
<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- -------
(in thousands)
<S> <C> <C> <C>
Current
Federal...................................... $ -- $ (175) $ 87
State........................................ 163 90 (231)
-------- -------- -------
163 (85) (144)
Deferred
Federal...................................... 11,680 (51,287) 17,345
State........................................ 667 (4,396) 724
-------- -------- -------
12,347 (55,683) 18,069
-------- -------- -------
$12,510 $(55,768) $17,925
======== ======== =======
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:
<CAPTION>
1999 1998 1997
-------- -------- -------
(in thousands)
<S> <C> <C> <C>
Tax by applying the statutory federal income
tax rate to pretax accounting income (loss)... $ 11,668 $(52,323) $16,515
Increase (decrease) in tax from:
State income taxes........................... 830 (4,306) 493
Other, net................................... 12 861 917
-------- -------- -------
$ 12,510 $(55,768) $17,925
======== ======== =======
</TABLE>
F-17
<PAGE>
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Long-term deferred tax assets (liabilities) are comprised of the following
at December 31, 1999 and 1998:
<TABLE>
<CAPTION>
1999 1998
---------- --------
(in thousands)
<S> <C> <C>
Deferred tax assets:
Allowance for losses................................ $ 3,216 $ 40
Partnership activities.............................. -- 6,592
Loss carryforwards and other........................ 85,353 64,060
---------- --------
Gross deferred tax assets......................... 88,569 70,692
Deferred tax liabilities:
Depreciation, depletion and amortization............ (106,972) (80,381)
Partnership activity................................ (4,091) --
Capitalized interest and other assets............... (546) (305)
---------- --------
Gross deferred tax liabilities.................... (111,609) (80,686)
---------- --------
Net deferred tax liability............................ (23,040) (9,994)
Valuation allowance................................... (2,600) (3,300)
---------- --------
$ (25,640) $(13,294)
========== ========
</TABLE>
Valuation allowances of $2.6 million and $3.3 million were provided at
December 31, 1999 and 1998, respectively, based on carryforward amounts which
may not be utilized before expiration.
The Company has net operating loss carryforwards available totaling $231.5
million, which expire in the years 2000 through 2019. The Company also has AMT
tax credits of $2.4 million.
The 1995 merger with Plains also resulted in a change in the Company's and
Plains' ownership as defined by Section 382 of the Internal Revenue Code. The
change effectively limits the annual utilization of the Company's and Plains'
remaining net operating losses arising prior to the merger to approximately
$15.8 million per year for the Company. Portions of the above limitations
which are not used each year may be carried forward to future years.
13. SUPPLEMENTAL CASH FLOW SCHEDULES AND INFORMATION
<TABLE>
<CAPTION>
1999 1998 1997
------- ------- ------
(in thousands)
<S> <C> <C> <C>
Cash paid during years
Income tax........................................ $ 3,927 $ 130 $ 824
Interest.......................................... 21,207 20,384 8,079
Supplemental information of noncash investing and
financing activities:
Issuance of common stock exchanged for treasury
shares in cashless option transactions........... $ 789 $ 233 $ 207
</TABLE>
In March 1998, the Company issued 260,917 shares of common stock with a
market value of $9.1 million in an acquisition of a company. The acquired
company's sole asset was a 15 percent interest in an oil and gas license in
the area denominated as Block 67 located in the Republic of Peru.
During 1999 and 1998, the Company's production payment obligations were
reduced by certain tax credit benefits of $.8 million and $2.2 million,
respectively, directly attributed to the properties burdened by the production
payment and received by the holder of the production payment liability.
F-18
<PAGE>
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
During 1997, in separate transactions, the Company assumed a production
payment with a value of $2.8 million and issued a written put option on
150,000 shares of the Company's common stock with a market value of $4.2
million (at the date of issue) in connection with acquisitions of interests in
oil and gas properties located in the Uinta and Piceance Basins, respectively.
In August 1999, the owner of the written put option elected to exercise such
option, and accordingly the Company issued 150,000 shares of its common stock.
14. BUSINESS SEGMENT INFORMATION
The Company operates principally in two business segments: oil and gas
exploration and production and natural gas trading. In addition to marketing
its own gas, the Company engages in natural gas trading activities, which
involves purchasing natural gas from third parties and selling natural gas to
other parties at prices and volumes that management anticipates will result in
profits to the Company.
The Company evaluates segment performance based on the profit or loss from
operations before income taxes. Corporate general and administrative expenses
are unallocated except for certain direct costs associated with the Company's
trading activity. Consolidated and segment financial information is as
follows:
<TABLE>
<CAPTION>
Natural Gas Oil & Gas Segment Corporation &
Trading E&P Totals Unallocated Consolidated
----------- --------- --------- ------------- ------------
(in thousands)
<S> <C> <C> <C> <C> <C>
1999
Revenues................ $792,016 $ 207,165 $ 999,181 $ 4,774 $1,003,955
Interest Income......... -- -- -- 826 826
-------- --------- --------- -------- ----------
Total Revenues........ 792,016 207,165 999,181 5,600 1,004,781
DD&A.................... -- 86,163 86,163 4,505 90,668
Profit (loss)........... 17,514 58,926 76,440 (43,102) 33,338
Assets.................. -- 720,453 720,453 163,848 884,301
Expenditures for assets,
net.................... -- 134,440 134,440 1,804 136,244
1998
Revenues................ $412,982 $ 206,338 $ 619,320 $ 5,430 $ 624,750
Interest Income......... -- -- -- 649 649
-------- --------- --------- -------- ----------
Total Revenues........ 412,982 206,338 619,320 6,079 625,399
DD&A.................... -- 97,957 97,957 4,166 102,123
Impairment.............. -- 168,304 168,304 -- 168,304
Profit (loss)........... 13,782 (118,549) (104,767) (44,744) (149,511)
Assets.................. -- 676,228 676,228 162,651 838,879
Expenditures for assets,
net.................... -- 202,912 202,912 2,867 205,779
1997
Revenues................ $171,140 $ 207,914 $ 379,054 $ 1,973 $ 381,027
Interest Income......... -- -- -- 1,573 1,573
-------- --------- --------- -------- ----------
Total Revenues........ 171,140 207,914 379,054 3,546 382,600
DD&A.................... -- 69,056 69,056 3,333 72,389
Profit (loss)........... 5,044 80,955 85,999 (38,813) 47,186
Assets.................. -- 738,952 738,952 133,749 872,701
Expenditures for assets,
net.................... -- 315,980 315,980 15,173 331,153
</TABLE>
The Company's revenues are derived in the United States and Canada. The
Company's long-lived assets are principally located in the United States.
F-19
<PAGE>
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
15. QUARTERLY INFORMATION (UNAUDITED)
<TABLE>
<CAPTION>
Three Months Ended
------------------------------------
3/31/99 6/30/99 9/30/99 12/31/99
-------- -------- -------- ---------
(in thousands, except per share
data)
<S> <C> <C> <C> <C>
1999
Net revenues.......................... $220,900 $225,367 $278,479 $ 277,875
Gross margin.......................... 22,560 18,193 17,765 18,189
Income from operations................ 12,417 6,673 6,974 7,274
Net income............................ 7,699 4,127 4,322 4,680
Net income per share *:
Basic............................... .24 .13 .13 .14
Assuming dilution................... .24 .13 .13 .14
<CAPTION>
Three Months Ended
------------------------------------
3/31/98 6/30/98 9/30/98 12/31/98
-------- -------- -------- ---------
<S> <C> <C> <C> <C>
1998
Net revenues.......................... $130,687 $129,658 $147,072 $ 213,890
Gross margin (loss) (1)............... 20,807 15,989 13,891 (156,474)
Income (loss) from operations (1)..... 10,022 4,215 2,987 (166,735)
Net income (loss)..................... 6,214 2,613 1,852 (104,422)
Net income (loss) per share *:
Basic............................... .20 .08 .06 (3.24)
Assuming dilution................... .19 .08 .06 (3.24)
</TABLE>
(1) In the fourth quarter of 1998, a pre-tax impairment charge of $168.3
million was recorded. (see Note 1).
* Individual quarterly earnings (loss) per share may not aggregate to the
earnings (loss) per share for the year.
F-20
<PAGE>
SUPPLEMENTAL OIL AND GAS INFORMATION
The following information, pertaining to the Company's oil and gas
producing activities for the years ended December 31, 1999, 1998 and 1997, is
presented in accordance with Statement of Financial Accounting Standards No.
69, "Disclosure About Oil and Gas Producing Activities" (SFAS No. 69).
Major Purchaser
During 1999, one natural gas purchaser accounted for 2 percent of the
Company's total revenue (11 percent of oil and gas revenues). Sales of gas to
this same purchaser represented 4 percent and 8 percent of total revenues in
1998 and 1997, respectively.
Costs Incurred In Oil And Gas Exploration And Development Activities
The following costs were incurred by the Company in oil and gas property
acquisition, exploration, and development activities during the years ended
December 31:
<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- --------
(in thousands)
<S> <C> <C> <C>
Acquisition of evaluated properties.......... $ 53,001 $ 3,529 $ 45,148
Acquisition of unevaluated properties:
United States.............................. 21,504 32,127 63,643
Peru....................................... -- 12,089 10,597
Exploration costs:
United States.............................. 27,467 59,331 118,779
Peru....................................... -- 15,196 --
Development costs:
United States.............................. 55,615 84,577 93,701
Peru....................................... 685 -- --
-------- -------- --------
158,272 206,849 331,868
Other, principally proceeds from mineral
conveyances................................. (26,915) (7,185) (14,253)
-------- -------- --------
Total additions to oil and gas properties.... $131,357 $199,664 $317,615
======== ======== ========
</TABLE>
Property acquisition costs include costs incurred to purchase, lease, or
otherwise acquire a property. Exploration costs include the costs of
geological and geophysical activity, dry holes, and drilling and equipping
exploratory wells. Development costs include costs incurred to gain access to
and prepare development well locations for drilling and to drill and equip
development wells.
In addition, the Company incurred costs of $1.8 million in 1999 for various
supporting production facilities consisting principally of natural gas
gathering systems and processing plants. Production facility expenditures for
1998 and 1997 were $3.2 million and $3.9 million.
Oil And Gas Reserves (Unaudited)
The following reserve related information for 1999 is based on estimates
prepared by the Company. All of the Company's reserves are located in the
United States. Approximately 85% of the Company's reserve information as of
December 31, 1999 and all of the Company's reserve information as of December
31, 1998 and 1997 was reviewed by independent reservoir engineers. Ryder
Scott, an independent reservoir engineer, reviewed the Company's Hugoton
Embayment, Wind River Basin and Piceance Basin year end 1999 reserve
information and all, but the Company's Coal Bed Methane reserves in Wyoming,
year end 1998 reserve information. The reserve information for the Company's
Coal Bed Methane properties located in the Powder River Basin as of December
31, 1999 and December 31, 1998 was audited by Netherland, Sewell & Associates,
Inc., an independent reservoir engineer. 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.
F-21
<PAGE>
<TABLE>
<CAPTION>
1999 1998 1997
-------------------- -------------------- --------------------
Oil (MBbl) Gas (Mmcf) Oil (MBbl) Gas (Mmcf) Oil (MBbl) Gas (Mmcf)
---------- --------- --------- --------- --------- ---------
(in thousands)
<S> <C> <C> <C> <C> <C> <C>
Proved developed and
undeveloped reserves:
Beginning of year...... 9,650 912,430 18,651 851,244 23,231 674,893
Revisions of previous
estimates............. 3,220 (6,790) (7,437) (55,343) (11,651) (54,945)
Purchase of minerals in
place................. -- 160,424 -- 3,520 1,910 52,303
Extensions and
discoveries........... 1,047 127,604 746 217,870 8,287 258,520
Production............. (1,432) (94,953) (2,033) (94,893) (2,235) (76,625)
Sale of minerals in
place................. (2,827) (22,823) (277) (9,968) (891) (2,902)
------ --------- ------ ------- ------- -------
End of year............ 9,658 1,075,892 9,650 912,430 18,651 851,244
====== ========= ====== ======= ======= =======
Proved developed
reserves:
Beginning of year...... 6,212 543,068 10,751 553,787 15,773 511,645
------ --------- ------ ------- ------- -------
End of year............ 5,664 664,096 6,212 543,068 10,751 553,787
====== ========= ====== ======= ======= =======
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows (Unaudited)
The standardized measure of discounted future net cash flows is based on
estimated quantities of proved reserves and the future periods in which they
are expected to be produced and on year-end economic conditions. Estimated
future gross revenues are priced on the basis of year-end prices, except in
the case of contracts where the applicable contract price, including fixed and
determinable escalations, were used for the duration of the contract.
Estimated future gross revenues are reduced by estimated future development
and production costs, as well as certain abandonment costs and by estimated
future income tax expense. Future income tax expenses have been computed
considering the tax basis of the oil and gas properties plus available
carryforwards and credits.
The standardized measure of discounted future net cash flows should not be
construed to be an estimate of the fair market value of the Company's proved
reserves. Estimates of fair value would also take into account anticipated
changes in future prices and costs, the reserve recovery variances from
estimated proved reserves and a discount factor more representative of the
time value of money and the inherent risks in producing oil and gas.
Significant changes in estimated reserve volumes or product prices could have
a material effect on the Company's consolidated financial statements.
<TABLE>
<CAPTION>
1999 1998 1997
---------- ---------- ----------
(in thousands)
<S> <C> <C> <C>
Future cash inflows....................... $2,431,441 $1,927,074 $2,158,461
Future production costs................... (705,476) (570,923) (608,123)
Future development costs.................. (281,727) (238,169) (250,467)
Future income tax expenses................ (300,354) (187,113) (306,946)
---------- ---------- ----------
Future net cash flows................... 1,143,884 930,869 992,925
10% annual discount for estimated timing
of cash flows............................ (482,577) (400,221) (428,794)
---------- ---------- ----------
Standardized measure of discounted future
net cash flows........................... $ 661,307 $ 530,648 $ 564,131
========== ========== ==========
</TABLE>
The estimate of future income taxes is based on the future net cash flows
from proved reserves adjusted for the tax basis of the oil and gas properties
but without consideration of general and administrative and interest expenses.
For standardized measure purposes the Company estimates future income taxes
using the "year-by-year" method. For ceiling test purposes, the Company
estimates future income taxes using the "short-cut" method.
F-22
<PAGE>
The following are the principal sources of changes in the standardized
measure of discounted future net cash flows:
<TABLE>
<CAPTION>
1999 1998 1997
---------- --------- ----------
(in thousands)
<S> <C> <C> <C>
Net change in sales price and production
costs..................................... $ 45,470 $(103,105) $ (457,246)
Changes in estimated future development
costs..................................... 18,055 43,383 43,391
Sales and transfers of oil and gas
produced, net of production costs (157,768) (146,875) (152,536)
Net change due to extensions and
discoveries............................... 76,523 115,145 195,992
Net change due to purchases and sales of
minerals in place......................... 117,670 (6,980) 32,153
Net change due to revisions in quantities.. 35,208 (76,985) (122,656)
Net change in income taxes................. (64,554) 68,083 183,901
Accretion of discount...................... 56,702 63,163 69,881
Other, principally revisions in estimates
of timing of production 3,353 10,688 6,448
---------- --------- ----------
Net changes................................ 130,659 (33,483) (200,672)
Balance, beginning of year................. 530,648 564,131 764,803
---------- --------- ----------
Balance, end of year....................... $ 661,307 $ 530,648 $ 564,131
========== ========= ==========
</TABLE>
The December 31, 1999 weighted average prices utilized for purposes of
estimating the Company's proved reserves and future net revenues were $22.01
per barrel of oil and $2.06 per Mcf of natural gas.
F-23
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Act of
1934, the Registrant has duly caused this report to be signed on its behalf by
the undersigned, thereunto duly authorized.
Barrett Resources Corporation
Date: March 29, 2000 /s/ Peter A. Dea
By___________________________________
Peter A. Dea
Vice Chairman of the Board, and
Chief Executive Officer
Date: March 29, 2000 /s/ John F. Keller
By___________________________________
John F. Keller
Chief Financial Officer, and
Principal Financial
and Accounting Officer
<TABLE>
<CAPTION>
Signature Title Date
--------- ----- ----
<S> <C> <C>
/s/ William J. Barrett Director March 29, 2000
- --------------------------------------
William J. Barrett
/s/ C. Robert Buford Director March 29, 2000
- --------------------------------------
C. Robert Buford
/s/ Derrill Cody Director March 29, 2000
- --------------------------------------
Derrill Cody
/s/ Peter A. Dea Director March 29, 2000
- --------------------------------------
Peter A. Dea
/s/ James M. Fitzgibbons Director March 29, 2000
- --------------------------------------
James M. Fitzgibbons
/s/ William W. Grant, III Director March 29, 2000
- --------------------------------------
William W. Grant, III
/s/ John F. Keller Director March 29, 2000
- --------------------------------------
John F. Keller
/s/ A. Ralph Reed Director March 29, 2000
- --------------------------------------
A. Ralph Reed
/s/ James T. Rodgers Director March 29, 2000
- --------------------------------------
James T. Rodgers
/s/ Philippe S.E. Schreiber Director March 29, 2000
- --------------------------------------
Philippe S.E. Schreiber
</TABLE>
<PAGE>
EXHIBIT 10.8B
AMENDMENT NO. 1
WHEREAS, Barrett Resources Corporation (the "Company") and Peter A. Dea
(the "Executive") have executed a Severance Protection Agreement dated February
9, 1998 (the "Agreement");
WHEREAS, effective November 18, 1999, the Executive was elected the
Company's Vice Chairman and Chief Executive Officer; and
WHEREAS, the Company and the Executive desire to amend the Agreement in
light of the Executive's promotion.
NOW, THEREFORE, the Company and the Executive agree as follows:
1. Paragraph 3.1(b)(2), line 3, of the Agreement shall be amended by
deleting the phrase "two times" and replacing it with the phrase
"three times".
2. Paragraph 3.1(b)(3), line 1, of the Agreement shall be amended by
deleting the phrase "twenty-four (24) months with the phrase
"thirty-six (36) months".
3. This amendment is effective November 18, 1999.
ATTEST: BARRETT RESOURCES CORPORATION
/s/ Eugene A. Lang, Jr. BY: /s/ William J. Barrett
- ----------------------- ----------------------
Secretary William J. Barrett
Chairman of the Board
PETER A. DEA
/s/ Peter A Dea
---------------
<PAGE>
Exhibit 21
BARRETT RESOURCES CORPORATION
Subsidiaries of the Registrant
Name of Company State of Incorporation
- --------------- ----------------------
Bargath, Inc. ............................................ Colorado
Barrett 1997 Trust (a business trust) .................... Delaware
Barrett Fuels Corporation ................................ Delaware
Barrett Resources International Corporation .............. Delaware
Barrett Resources (Peru) Corporation ..................... Delaware
Grand Valley Gathering System ............................ Colorado
Parachute Mountain, Inc. ................................. New Mexico
Plains Petroleum Company ................................. Delaware
Plains Petroleum Gathering Company ....................... Delaware
Plains Petroleum Operating Company ....................... Delaware
All of the subsidiaries named above are included in the consolidated financial
statements of the Registrant included herein.
<PAGE>
Exhibit 23.1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTS
As independent public accountants, we hereby consent to the incorporation by
reference of our report included in this Form 10-K into Barrett Resources
Corporation's previously filed Registration Statements on Form S-3, File
Nos.333-51985, 333-51461 and 333-85809 and on Form S-8, File Nos. 333-29669,
333-18311, 333-29577, 333-02529 and 333-79849.
ARTHUR ANDERSEN LLP
Denver, Colorado
March 27, 2000
<PAGE>
Exhibit 23.2
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND CONSULTANTS
As independent petroleum consultants, we hereby consent to the
incorporation by reference of our report included in this Form 10-K into Barrett
Resources Corporation's previously filed Registration Statements on Form S-3,
File Nos. 333-51985, 333-51461 and 333-85809, and on Form S-8, File Nos.
333-29669, 333-18311, 333-29577, 333-02529 and 333-79849.
RYDER SCOTT COMPANY, L.P.
Denver, Colorado
March 27, 2000
<PAGE>
Exhibit 23.3
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
We hereby consent to the reference to our firm in the Form 10-K of
Barrett Resources Corporation (the "Company") for the years ended December 31,
1999 and 1998 and the incorporation by reference thereof of our reserve review
letter reports into the Company's previously filed Registration Statements on
Form S-3 (File Nos. 333-51985, 333-51461 and 333-85809) and on Form S-8 (File
Nos. 333-29669, 333-18311, 333-02529, 333-29577 and 333-79849).
NETHERLAND, SEWELL & ASSOCIATES, INC.
Dallas, Texas
March 24, 2000
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<CASH> 20,634
<SECURITIES> 0
<RECEIVABLES> 101,818
<ALLOWANCES> 1,912
<INVENTORY> 22,934
<CURRENT-ASSETS> 154,522
<PP&E> 1,352,095
<DEPRECIATION> 625,606
<TOTAL-ASSETS> 884,301
<CURRENT-LIABILITIES> 139,763
<BONDS> 355,250
0
0
<COMMON> 326
<OTHER-SE> 363,322
<TOTAL-LIABILITY-AND-EQUITY> 884,301
<SALES> 998,932
<TOTAL-REVENUES> 1,004,781
<CGS> 925,915
<TOTAL-COSTS> 925,915
<OTHER-EXPENSES> 24,007
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 21,521
<INCOME-PRETAX> 33,338
<INCOME-TAX> 12,510
<INCOME-CONTINUING> 20,828
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 20,828
<EPS-BASIC> .64
<EPS-DILUTED> .64
</TABLE>
