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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For Year Ended December 31, 1998
or
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the Transition Period from to
Commission File No. 1-13446
BARRETT RESOURCES CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 84-0832476
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
1515 Arapahoe Street,
Tower 3, Suite 1000
Denver, Colorado 80202
(Address of principal (Zip Code)
executive offices)
(303) 572-3900
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
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
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, 1999, the Registrant had 32,032,104 common shares
outstanding, and the aggregate market value of the common shares held by non-
affiliates was approximately $686,281,158. This calculation is based upon the
closing sale price of $22.25 per share for the stock on March 15, 1999.
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TABLE OF CONTENTS
Item Page
---- ----
PART I
1 and 2. Business and Properties...................................... 1
3. Legal Proceedings............................................ 17
4. Submission of Matters to Vote of Security Holders............ 17
PART II
5. Market for Registrant's Common Stock and Related Security
Holders Matters............................................. 18
6. Selected Financial Data...................................... 18
7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................... 19
8. Financial Statements and Supplementary Data.................. 24
9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................... 24
PART III
10. Directors and Executive Officers of the Company.............. 25
11. Executive Compensation....................................... 29
12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 33
13. Certain Relationships and Related Transactions............... 34
PART IV
14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K......................................................... 35
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; the Mid-Continent Region of Kansas, Oklahoma, New
Mexico and Texas; and the Gulf of Mexico Region of offshore Texas and
Louisiana. At December 31, 1998, the Company's estimated proved reserves were
970.3 Bcfe (94% natural gas and 6% crude oil) with an implied reserve life of
9.1 years based on 1998 total production of 107 Bcfe.
The Company concentrates its activities in core areas in which it has
accumulated detailed geologic knowledge and developed significant management
expertise. The Company continues to build on its interests in the Piceance
Basin in northwestern Colorado, the Wind River Basin in Wyoming, and the
Anadarko and Arkoma Basins in Oklahoma. The Company also has significant
interests in the Hugoton Embayment in Kansas and Oklahoma, the Niobrara play
in northeastern Colorado, the Powder River Basin of northeastern Wyoming, the
Gulf of Mexico and the Uinta Basin of northeastern Utah. At December 31, 1998,
these principal areas of focus represented approximately 96% of the Company's
estimated proved reserves.
The Company is currently pursuing development projects in the Wind River,
Piceance, Powder River, Anadarko and Arkoma Basins, and exploration projects
in the Wind River and Anadarko Basins and the Gulf of Mexico. The Company's
average net daily production increased to 293 MMcfe for the year ended
December 31, 1998 from 247 MMcfe for the year ended December 31, 1997.
1
As of December 31, 1998, the Company owned an interest in 3,102 wells, of
which 2,378 were producing. Of these producing wells, 1,252 were operated by
the Company. These operated wells contributed approximately 73% of the
Company's natural gas and oil production for the year ended December 31, 1998.
The Company also owns interests in and operates a natural gas gathering
system, a 27-mile pipeline and a natural gas processing plant in the Piceance
Basin.
Barrett markets all of its own natural gas and oil production from wells
that it operates. In addition, the Company engages in natural gas trading
activities, which involve purchasing natural gas from third parties and
selling natural gas to other parties at prices and volumes that management
anticipates will result in profits to the Company. Through these natural gas
trading activities, the Company obtains knowledge and information that enables
it to more effectively market its own production. See "Natural Gas and Oil
Marketing and Trading."
Employees and Offices
The Company currently has 196 full time employees, including 10 officers
(three of whom are geologists and three of whom are petroleum engineers), 12
geologists, four geophysicists, 14 engineers, one environmental manager, 10
landmen, three district managers, one operations superintendent, and
administrative, clerical, accounting and field operations personnel, none of
whom is represented by organized labor unions.
The Company's executive offices are located at 1515 Arapahoe Street, Tower
3, Suite 1000, Denver, Colorado 80202, and its telephone number is (303) 572-
3900.
Core Areas of Activity
The following table sets forth certain information concerning these core
areas of activity:
Average Daily
Estimated Proved Estimated Proved Production for
Reserves at Reserves at Year Ended
Basin or Field December 31, 1997 December 31, 1998 December 31, 1998
-------------- ----------------- ----------------- -----------------
(Bcfe) (Bcfe) (MMcfe)
Rocky Mountain Region
Wind River............ 118.4 137.3 63.8
Piceance.............. 339.6 315.3 55.9
Powder River.......... 24.2 11.9 15.1
Powder River-CBM...... 18.7 142.6 18.6
Green River........... 9.8 15.2 3.0
Uinta................. 82.3 42.2 9.0
NE Colorado-Niobrara.. 23.6 24.6 5.5
Mid-Continent Region
Arkoma................ 28.8 26.0 12.9
Anadarko.............. 33.8 25.4 20.0
Hugoton Embayment..... 195.8 172.1 42.7
Permian............... 20.9 11.7 8.5
Gulf of Mexico Region... 59.2 39.0 37.0
Other Natural Gas and
Oil Activities(1)...... 8.0 7.0 1.2
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Total................... 963.2 970.3 293.2
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(1) 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.
2
Cave Gulch Area. In August 1994, the Company drilled the Cave Gulch Federal
Unit 1-16 well and discovered a significant natural gas field in the Fort
Union and Lance Sandstones below the Owl Creek Thrust. Since August 1994, the
Company has acquired additional interests in the area and currently owns
working interests ranging from 41% to 100% in 11,572 gross and 9,080 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.
In 1998, the Company continued its shallow development program by drilling
and completing four Lance wells (three were successful and one stepout well
was plugged and abandoned), and one shallow Fort Union producer. One of these
wells, the West Cave Gulch 1-36, had an initial producing rate of 13.9 MMcfd
of gas and 121 BOPD. The Company also drilled and completed its first 20-acre
Lance pilot test, the Cave Gulch Unit 21, at an initial flow rate of 4.2 MMcfd
and 17 BOPD. Although certain Lance zones exhibited no significant pressure
depletion, the well's production performance will be monitored during 1999 to
gauge the feasibility of additional 20-acre infill wells. Through December
1998, the Company has operated and completed a total of 23 Lance wells (22
successful and one unsuccessful), one shallow Fort Union producer, and one
Mesaverde producer.
In February 1997, the Company reached a total depth of 19,106 feet on its
deep discovery well, the Cave Gulch Federal 16. In August 1997, the well was
completed in the lower part of the Third Frontier Sandstone with a stabilized
flow rate of 10.2 MMcfd, and in August 1998 was recompleted in the upper part
of the Third Frontier Sand, as well as the entire First Frontier Sand. Prior
to recompletion, the well was flowing approximately 3.5 MMcfd and after
recompletion it flowed 11.9 MMcfd. Several pay zones in this well, including
the Fourth and Fifth Frontier Sands, and the Muddy Sandstone have not yet been
opened for production. The Company owns an 85.3% working interest in this
well.
In early 1998, the Cave Gulch Federal 1-29LAK, the Company's second deep
test, encountered a significant gas kick while drilling at 18,175 feet in the
Muddy Formation. With the assistance of pressure control personnel the well
was placed on production February 20, 1998, and produced 7.5 Bcf during its
first six months on production. On August 13, 1998 the well blew out
uncontrollably due to what the Company believes was a downhole casing failure.
The natural gas venting from the well was ignited on August 17, 1998. A nearby
deep development well, the Cave Gulch Federal 4-19LAK, was converted to a
relief well and drilled to a total depth of 16,462 feet. The 4-19LAK
intersected the 1-29LAK wellbore in early January 1999. In late November 1998,
the venting gas was extinguished when the 1-29LAK wellbore bridged off,
abruptly constricting the gas flow. In early 1999, the Company temporarily
abandoned the 4-19LAK relief wellbore. A drilling rig was moved onto the 1-
29LAK location in early February 1999 and an assessment will be made of the
condition and extent of necessary repairs to the wellbore. It will then be
determined whether to repair the well, place it back on production or drill a
replacement well. Insurance is expected to cover the costs associated with the
control of the 1-29LAK, the drilling of the relief well and the repair or
redrilling of the 1-29LAK well down to the depth of the blowout. Insurance
coverage does not extend to the natural gas vented between August 13 and late
November 1998. The Company has a 70% working interest in the 1-29LAK well.
On September 18, 1997, the Company spud the Cave Gulch 3-29MAD, an ultra-
deep exploratory well designed to test the Madison and Tensleep Formations and
reached a total depth of 21,965 feet on May 11, 1998. Both the Madison and
Tensleep Formations tested non-productive. The Company has a 97% working
interest in these ultra-deep horizons. Subsequent to testing the ultra-deep
horizons, the well was plugged back to just below the Muddy, Lakota and
Morrison horizons. In October 1998, the Company perforated and stimulated the
Muddy Sandstone resulting in an initial flow rate of 36.0 MMcfd. Bottom hole
pressure tests indicated that the 3-29MAD well and the Cave Gulch 1-29LAK are
in the same Muddy reservoir. By year-end 1998, the 3-29MAD had produced
approximately 2.0 Bcf from the Muddy Formation. Pay horizons such as the
Lakota Formation, as well as four benches in the Frontier Formation, remain
behind pipe in this well. The Company currently has an 80% working interest in
the Frontier, Muddy, and Lakota horizons in the 3-29MAD well.
3
In July 1998, the Company spud its fourth deep test, the Cave Gulch Federal
5-30LAK targeting the Frontier, Muddy, Lakota, Morrison, and Sundance
Formations. The well was completed in January 1999, and is currently producing
8.5 MMcfd. The Company owns an 85% working interest in this well.
Two interstate pipelines serving the Cave Gulch area completed expansions
during 1997, which increased take-away capacity. At the same time, the Company
installed a centralized compressor and wet gas conditioning facility on its
gathering system, which enables the Company to transport increased volumes of
gas to the interstate pipelines. Gross Cave Gulch Field production at year-end
1998 was 90.5 MMcfed.
The Company is in the final stages of a 62 square mile three-dimensional
("3-D") seismic acquisition program covering land immediately south of the
original Cave Gulch 22 square mile 3-D seismic survey obtained in early 1995.
This survey will aid the Company's exploratory program both within and
adjacent to the Cave Gulch area.
Owl Creek Thrust. The Company continues to evaluate additional exploration
prospects in the Owl Creek Thrust, along the northern margins of the Wind
River Basin. In July 1997, the Company entered into a definitive Exploration
and Area of Mutual Interest Agreement with an oil and gas industry partner to
explore for oil and gas along the Owl Creek Thrust. The partner was assigned
45% of the Company's interest in 77,127 net acres. To date, the Company and
its partner have drilled two unsuccessful exploratory tests.
At December 31, 1998, the Wind River Basin represented 14% of the Company's
estimated proved reserves, and 22% of the Company's total 1998 production. The
Company intends to spend 18% of its estimated $92 million 1999 capital
expenditure budget in the Wind River Basin for development, leasehold
acquisition, seismic surveys and exploration. The Company will drill at least
two deep Frontier-Muddy-Lakota tests, and one to four shallow Fort Union-Lance
wells in 1999.
Piceance Basin. The Piceance Basin of northwestern Colorado is a core
operating area for the Company and will continue to be very prominent in the
Company's capital spending plans. The Company's activities in the Piceance
Basin are conducted primarily in three fields: Parachute, Rulison and Grand
Valley.
The Company's drilling activities in the Piceance Basin primarily target the
lenticular sandstones of the Williams Fork Formation of the Mesaverde Group.
The Company drilled its first well in the Piceance Basin in 1984, and as of
December 31, 1998, the Company owned interests in 399 wells and operated 374
of these wells.
On January 8, 1998, the Company gained approval from the Colorado Oil and
Gas Conservation Commission ("COGCC") for 20-acre well density on 2,830 net
acres, approximately 4% of its net acreage, in the Piceance Basin. This COGCC
approval allows for 107 additional 20-acre infill locations associated with
the approved acreage.
The Company's 1999 plans call for drilling or participating in 31 Williams
Fork wells and one dual horizontal Cozzette/Corcoran well, the RMV 94-21H,
while operating two drilling rigs in the Basin. After completing and flow
testing the horizontal laterals, the vertical Williams Fork member in the RMV
94-21H will be completed and commingled with the Cozzette/Corcoran. Based upon
the results of this well, a 3-D seismic program may be shot and one additional
horizontal Cozzette/Corcoran well may be drilled in the Rulison Field in 1999.
At December 31, 1998, the Piceance Basin represented 32% of the Company's
estimated proved reserves, and 19% of the Company's total 1998 production. The
Company intends to spend 18% of its 1999 capital expenditure budget in the
Piceance Basin for development and exploration, including participating in
drilling up to 32 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
4
the Company's wells to Questar Pipeline Corporation's interstate pipeline.
Through four acquisitions in 1996, the Company increased its ownership
interest in this system to 64%. As of December 31, 1998, the Grand Valley
Gathering System was connected to 318 natural gas producing wells. The system
now has the flexibility to deliver natural gas to three interstate pipelines
as well as Public Service of Colorado's western Colorado distribution system.
It is anticipated that a fourth interstate pipeline (TransColorado) will be
connected to the gathering system at the end of the first quarter of 1999. In
December 1994, the Company completed the construction of a 90 MMcfd per day
natural gas processing plant to extract liquid hydrocarbons from the natural
gas stream. In 1997, the Company looped the main 8-inch pipeline adding 20
miles of new 16-inch pipeline and associated compression. The gathering system
has in excess of 200 miles of lateral lines connected to it. Following these
improvements and subject to the take-away capacity of these four pipeline
systems, the gathering system has the capability of delivering over 150 MMcfd
gas per day.
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 made
acquisitions 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 primarily from
multiple sandstone reservoirs of the lower Green River Formation at depths
averaging 5,500 feet.
Altamont-Bluebell Field. The Altamont-Bluebell Field complex, which includes
the Cedar Rim area, covers a large portion of the northern Uinta Basin. The
Company owns working interests ranging from 25% to 100% in 55 producing wells
and in approximately 115,804 gross and 89,974 net acres of leasehold
interests. The Company's production in this area is predominantly from the
multiple sandstone reservoirs of the Wasatch Formation, which are found at an
average depth of 12,000 feet. Also productive in the field are the upper,
lower, and middle portions of the Green River Formation at depths of 5,000 to
7,000 feet.
In 1998, the Company plugged eight depleted wells in the Altamont-Bluebell
Field. In addition, in an effort to further evaluate upside opportunities in
the Altamont-Bluebell properties, the Company successfully recompleted three
wells and drilled one infill development well as part of a joint venture
program with an outside party.
At December 31, 1998, the Uinta Basin represented approximately 4% of the
Company's estimated proved reserves and 3% of the Company's production. The
Company intends to spend 1% of its 1999 capital expenditure budget in the
Uinta Basin in 1999 for development, leasehold acquisition and exploration.
Powder River Basin. The Powder River Basin in Wyoming is primarily an oil
province, with production from Cretaceous and Permian Age formations. One of
the reservoir targets in this Basin is the Permian Minnelusa formation. The
Company has recently engaged in the development of coal bed methane which
targets the shallow Fort Union Formation.
Coal Bed Methane. In October 1997, the Company entered into a joint
development agreement to participate, with a 50% working interest, in a coal
bed methane project covering a 2.1 million acre area of mutual interest
("AMI") located north and south of Gillette, Wyoming. In 1998, the Company
rapidly expanded its coal bed methane leasehold position with its joint
development partner to over 800,000 gross acres. The coal seams lie 500-1,500
feet below the surface making drilling and completion of the wells very
economic. In 1998, the Company participated in 307 wells, including 159 that
are waiting on pipeline connection, and 104 new producing wells in this area,
bringing the total number of coal bed methane producing wells at year-end to
412, with gross production at a combined rate of approximately 75 MMcfd.
5
The Bureau of Land Management ("BLM") has 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 Company anticipates completion of the
EIS in September 1999.
On July 20, 1998, the U.S. Tenth Circuit Court of Appeals ruled in the Case
of the Southern Ute Indian Tribe vs. Amoco Production Company. The Tenth
Circuit reversed a District court decision that held that the fee owner of
land patented under the 1909 and 1910 Coal Land Act owned the coal bed methane
rights. Based upon the Tenth Circuit decision, Barrett put on hold the
drilling of coal bed methane wells located on fee leases in the Powder River
Basin. On October 21, 1998, President Clinton signed legislation by which the
Federal government relinquished its claim to coal bed methane under lands
patented pursuant to the 1909 and 1910 Acts where private leases were executed
prior to the signing of this legislation. With this, the Company resumed
drilling on its fee leases. Additionally, the Company will have a 10% working
interest in the new 90-mile Fort Union Gathering System that will have an
initial take-away capacity of 300 MMcfd beginning in late 1999.
At December 31, 1998, the Powder River Basin represented 16% of the
Company's estimated proved reserves and 11% of the Company's total 1998
production. This Basin contributes approximately 35% of the Company's daily
oil production. The Company intends to spend 24% of its 1999 capital
expenditure budget in the Basin, including participating in an additional 500
to 600 wells in its coal bed methane play.
Northeastern Colorado--Niobrara. During 1998, 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. Gas accumulations in the chalk are
generally controlled by structural closure. In 1998, the Company acquired 18
miles of proprietary seismic data and 460 miles of trade seismic data. The
Company drilled or participated in 23 wells during 1998, of which 20 were
successful.
At December 31, 1998, Niobrara represented 3% of the Company's estimated
proved reserves, and 2% of the Company's total 1998 production. The Company
intends to spend 8% of its 1999 capital budget in the play for the drilling of
16 wells, acquiring additional leasehold, seismic data and related
infrastructure.
Mid-Continent Region
Arkoma Basin. In 1998, the Company participated in the drilling of five
wells in three areas of the Arkoma Basin in Oklahoma: South Panola, Red Oak,
and Wilburton. All five wells were completed as gas wells. Due to the complex
structure and overlapping nature of the rock formations, the Company uses 3-D
seismic surveys extensively in the Arkoma Basin.
At December 31, 1998, the Arkoma Basin represented 3% of the Company's
estimated proved reserves and 4% of the Company's total 1998 production. The
Company intends to spend 1% of its 1999 capital expenditure budget for
drilling one well, seismic surveys and land acquisitions.
Anadarko Basin. In 1998, the Company participated in the drilling of 21
wells in the Anadarko Basin with working interests ranging from 2% to 63%. Of
the 21 gas wells drilled, 15 were completed as producers and six were
unsuccessful. The Company has become increasingly active in the Mountain Front
Springer play, and is currently processing and interpreting 3-D seismic data
to help evaluate its 254,559 gross acres (128,703 net acres) in the Basin.
At December 31, 1998, the Anadarko Basin represented 3% of the Company's
estimated proved reserves, and 7% of the Company's total 1998 production. The
Company intends to spend 12% of its 1999 capital expenditure budget for the
drilling of up to 24 wells, leasehold acquisitions and seismic surveys.
6
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 three fields in
the Hugoton Embayment: the Hugoton, the Guymon-Hugoton and Panoma.
Hugoton and Guymon-Hugoton Fields. In the Hugoton and Guymon-Hugoton
Fields, the Company has a working interest in 372 gross wells and operates 320
of these wells. The Hugoton and the Guymon-Hugoton Fields produce from the
Chase Formation. Four wells were drilled in the Hugoton Field in 1998, three
of which have been placed on production and one is awaiting completion.
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 .
Natural Gas Sales Agreement. The majority of the Company's natural gas
production from the Hugoton and Panoma Fields is sold under a long-term
contract (life-of-field) to KN Gas Supply Services, Inc. ("KNGSS"). Among
other things, this contract provides for annual re-determination of the price
to the Company. In 1998, the price was calculated each month by using the
average of four Mid-Continent index prices less a variable amount ranging from
$0.11 for an average index price of less than $0.75 to a maximum of $0.20 for
an average index price of $2.26 or higher per MMBtu. The volume of natural gas
for which the Company receives payment is reduced by one percent of the volume
as an in-kind fuel charge for moving the natural gas. By a letter agreement
dated December 18, 1997, natural gas sold under this contract between January
1, 1998 and December 31, 2000 will be priced in the same manner as in 1997.
Net Profit Agreements. The Company produces natural gas in the Guymon-
Hugoton Field and the nearby Camrick Field under a Dry Gas Agreement with
Chevron U.S.A. Inc. ("Chevron"). This agreement allows the Company to expend
funds for the operation of the properties (including the cost of drilling
wells) and to recoup the funds so expended from current production income.
Eighty percent of net operating income generated by the natural gas production
(after operational costs are recouped, including the cost of drilling and
equipping wells) is then paid to Chevron. As of December 31, 1998, the Company
had interests in 56 wells subject to the terms of this agreement. The Company
also produces natural gas in the Hugoton and Panoma Fields under various
agreements similar to the Chevron agreement, except that net operating income
is allocated 15% to the Company and 85% to other parties. At December 31,
1998, the Company had interests in an aggregate of 54 Chase Formation wells
and eight Council Grove Formation wells burdened by these other agreements.
The payments made pursuant to the net profit agreements are treated as lease
operating expenses by the Company. Additional or replacement wells drilled on
the properties would be operated under the same terms and conditions as
existing wells, and would result in the commencement of the 80/20 or 85/15 net
operating income allocation after the cost of the new wells is recovered.
Hugoton Gas Trust Agreement. Natural gas rights established in 1955 to
approximately 50,000 acres in Finney and Kearny Counties, Kansas were
transferred to Plains by 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, 1998, the gross proved natural gas reserves attributable to the
leases burdened by this agreement were estimated to be 127.1 Bcf. The natural
gas payments are treated as lease operating expenses by the Company. At
December 31, 1998, the Company had working interests in 196 wells that were
subject to these payments. Any additional natural gas wells drilled on this
acreage also will be subject to the $0.06 per Mcf payment of natural gas
produced.
At December 31, 1998, the Hugoton Embayment represented 18% of the Company's
estimated proved reserves and 15% of the Company's total 1998 production. The
Company intends to spend 2% of its 1999 capital expenditure budget in the
Hugoton Embayment for drilling three wells and other well work.
7
Permian Basin. The Permian Basin, located in west Texas and southeast New
Mexico, is primarily an oil province. As of December 31, 1998, the Company had
an interest in 172 gross wells located in the Permian Basin.
At December 31, 1998, the Permian Basin represented 1% of the Company's
estimated proved reserves, and 3% of the Company's total 1998 production. The
Company intends to spend less than 1% of its 1999 capital expenditure budget
in the Permian Basin.
Gulf of Mexico Region
The Company currently owns an interest in 89 leases in the Gulf of Mexico
(44 offshore Texas and 45 offshore Louisiana). The Company modified its Gulf
of Mexico strategy in 1998 to align itself with its overall plan of building a
diversified, lower risk portfolio of Gulf of Mexico properties. The Company
intends to continue to selectively (i) sell down its interest in several high
working interest prospects, (ii) farmout its interest in several high-risk
prospects, and (iii) forfeit its interest in sub-economic prospects in lieu of
paying annual rentals. As a result of its 1998 farmout efforts, four wells
will be drilled on Company leases in the first half of 1999 at no cost or risk
to the Company. Due to its sell-down effort, the Company recouped
approximately $1.6 million of previously invested capital and asset sales have
netted an additional $4.8 million.
In December 1998, the Company entered into an exchange agreement with a
partner common to two producing fields. This agreement served to consolidate
each partner's interest in areas of specific interest to them. As the new
operator of three of the four blocks, the Company plans numerous
workovers/recompletions and has underwritten an ongoing 3-D seismic
acquisition program to acquire data over the area. The Company expects
delivery of the data in the summer of 1999.
The Company has also entered into a three-year seismic participation
agreement with a Gulf of Mexico exploration company recognized for its
utilization of leading edge technology. This agreement covers over 1,000
blocks of 3-D seismic data located primarily in the central Gulf of Mexico in
water depths less than 300 feet. This agreement, executed in early 1999, will
enable the Company to participate for a 25% interest in any prospects
developed by this venture.
At December 31, 1998, the Gulf of Mexico Region represented 4% of the
Company's estimated proved reserves and 13% of the Company's total 1998
production. The Company intends to spend 13% of its 1999 capital expenditure
budget in the Gulf of Mexico.
International Operations
In January 1997, the Company entered into an agreement with industry
partners that provided the Company with a 45% working interest in Block 67,
covering two million gross acres in the Maranon Basin of northeastern Peru. In
March 1998, the Company acquired an additional 25% working interest. During
1998, the Company drilled and temporarily abandoned three exploratory wells,
each of which resulted in 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 these
wells are capable of per well 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. Current
oil prices make it uneconomic 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.
At year-end 1998, the Company was engaged in exclusive contract negotiations
with Peruvian authorities to acquire Block 39, a new license area covering
approximately 1.0 million acres, located immediately to the south and east of
Block 67.
8
In November 1996, the Company obtained a 55% working interest in a license
to evaluate Block 55 (A, B, and C), which encompasses 820,000 acres in the
Maranon Basin of Peru. The Company and its partner conducted seismic
reprocessing, environmental impact and engineering feasibility studies
regarding the viability of developing the Bretana Field, discovered in 1974 by
another company on this Block. Block 55 was relinquished in November 1998.
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(degrees) Fahrenheit. Natural gas equivalents are determined
using the ratio of six Mcf of natural gas to one barrel of crude oil,
condensate or natural gas liquids so that one barrel of oil is referred to as
six Mcf of natural gas equivalent or "Mcfe."
As used in this 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 extend significantly a
known prospect.
A "farmout" is an assignment to another party of an interest in a drilling
location and related acreage conditional upon the drilling of a well on that
location. A "farm-in" is an assignment by the owner of a working interest in
an oil and gas lease of the working interest or a portion thereof to another
party who desires to drill on the leased acreage. Generally, the assignee is
required to drill one or more wells in order to earn its interest in the
acreage. The assignor usually retains a royalty or reversionary working
interest in the lease. The assignee is said to have "farmed-in" the acreage.
"Present value of estimated future net revenues" means the present value of
estimated future revenues to be generated from the production of proved
reserves calculated in accordance with the Securities and Exchange Commission
guidelines, net of estimated production and future development costs, using
prices and costs as of
9
the date of estimation without future escalation, without giving effect to
non-property related expenses such as general and administrative expenses,
debt service, future income tax expense and depreciation, depletion and
amortization, and discounted using an annual discount rate of 10%.
A "recompletion" is the completion of an existing well for production from a
formation that exists behind the casing of the well.
"Reserves" means natural gas and crude oil, condensate and natural gas
liquids on a net revenue interest basis, found to be commercially recoverable.
"Proved developed reserves" includes proved developed producing reserves and
proved developed behind-pipe reserves. "Proved developed producing reserves"
includes only those reserves expected to be recovered from existing completion
intervals in existing wells. "Proved undeveloped reserves" includes those
reserves expected to be recovered from new wells on proved undrilled acreage
or from existing wells where a relatively major expenditure is required for
recompletion.
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:
Natural Gas and Oil Production
--------------------------------
Year Ended December 31,
--------------------------------
1996 1997 1998
---------- ---------- ----------
Quantities Produced and Sold
Natural gas (Bcf)........................... 60.9 76.6 94.9
Oil and condensate (MMBbls)................. 1.9 2.2 2.0
Average Sales Price
Natural gas ($/Mcf)......................... $ 1.88 $ 2.18 $ 1.92
Oil and condensate ($/Bbl).................. $ 19.51 $ 17.69 $ 11.42
Average Production Costs ($/Mcfe)............. $ 0.66 $ 0.64 $ 0.55
Productive Wells
The productive wells in which the Company owned a working interest as of
December 31, 1998 are described in the following table:
Productive Wells(1)
---------------------------
Gas Wells Oil Wells
-------------- ------------
Gross Net Gross Net
----- -------- ----- ------
Rocky Mountain Region
Wind River........................................ 25 19.48 20 6.47
Piceance.......................................... 378 220.02 0 0.00
NE Colorado-Niobrara.............................. 132 91.87 0 0.00
Powder River...................................... 17 2.00 257 74.00
Powder River-CBM.................................. 363 169.00 0 0.00
Green River....................................... 17 10.64 0 0.00
Uinta............................................. 0 0.00 90 76.31
Mid-Continent Region
Arkoma............................................ 147 34.96 0 0.00
Anadarko.......................................... 255 84.05 21 12.52
Hugoton Embayment................................. 425 364.31 0 0.00
Permian........................................... 13 9.24 106 91.39
Gulf of Mexico Region............................... 56 16.06 16 2.58
Other............................................... 12 9.00 28 0.23
----- -------- --- ------
Total........................................... 1,840 1,030.63 538 263.50
===== ======== === ======
- --------
(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.
10
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 Peru during 1998:
Wells Drilled
-------------------------------------
Year Ended December 31,
-------------------------------------
1996 1997 1998
----------- ------------ ------------
Gross Net Gross Net Gross Net
----- ----- ----- ------ ----- ------
Development
Natural gas............................. 94 46.24 224 117.76 372 191.49
Oil..................................... 43 30.48 37 25.04 8 .14
Non-productive.......................... 17 8.03 20 11.28 17 8.58
--- ----- --- ------ --- ------
Total................................. 154 84.75 281 154.08 397 200.1
=== ===== === ====== === ======
Exploratory
Natural gas............................. 8 4.05 9 4.19 13 8.52
Oil..................................... 3 1.00 1 .33 8 3.78
Non-productive.......................... 6 3.66 8 5.09 6 3.6
--- ----- --- ------ --- ------
Total................................. 17 8.71 18 9.61 27 15.9
=== ===== === ====== === ======
In addition, the Company was participating in 9 gross (3.96 net) wells,
which were in the process of being drilled, at December 31, 1998.
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. The estimates as of December 31, 1996 and 1997 were reviewed
by Ryder Scott Company, an independent reservoir engineering firm. Ryder Scott
Company reviewed all of the Company's December 31, 1998 reserves, except the
reserves associated with the Powder River Basin coal bed methane play. The
Powder River Basin coal bed methane reserves were reviewed by Netherland,
Sewell & Associates, Inc., an independent reservoir engineer. The total proved
net reserves estimated by the Company as of December 31, 1996, 1997 and 1998
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.
Estimated Proved Reserves
-----------------------------------------------
December 31,
-----------------------------------------------
1996 1997 1998
---------------- ------------------------------
(dollars in millions, except sales price data)
Estimated Proved Reserves
Natural gas (Bcf)............ 674.9 851.2 912.4
Oil and condensate (MMBbls).. 23.2 18.7 9.7
Total (Bcfe)............... 814.3 963.2 970.3
Proved developed reserves
(Bcfe)........................ 606.3 618.3 580.4
Natural gas price as of Decem-
ber 31 ($/Mcf)................ $ 3.46 $ 2.19 $ 2.01
Oil price as of December 31
($/Bbl)....................... $ 24.12 $ 15.52 $ 9.35
Present value of estimated fu-
ture net revenues
before future income taxes
discounted at 10%(1)........ $ 1,121.5 $ 745.0 $ 627.8
Standardized measure of dis-
counted net cash flows(2)..... $ 764.8 $ 564.1 $ 530.6
11
- --------
(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 $3.46
per Mcf of natural gas and $24.12 per Bbl of oil at December 31, 1996; and
$2.19 per Mcf of natural gas and $15.52 per Bbl of oil at December 31,
1997 and $2.01 per Mcf of natural gas and $9.35 per Bbl of oil at December
31, 1998.
(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 Gas and Oil 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.
12
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, 1998 are summarized in the
following table. "Undeveloped Acreage" includes leasehold interests that
already may have been classified as containing proved undeveloped reserves.
Developed Acreage Undeveloped Acreage (1)
----------------- -----------------------
Gross Net Gross Net
----------------- -----------------------
Rocky Mountain Region
Wind River.......................... 14,925 9,905 125,735 70,803
Piceance............................ 46,440 29,207 105,390 49,089
Powder River........................ 125,627 58,391 804,188 318,796
Green River......................... 15,915 5,880 22,420 14,782
Uinta............................... 61,840 51,098 108,569 92,285
Mid-Continent Region
Arkoma.............................. 44,197 33,118 28,550 11,268
Anadarko............................ 126,984 54,192 127,575 74,511
Hugoton Embayment................... 88,332 84,946 3,200 833
Permian............................. 16,590 10,156 2,437 653
Gulf of Mexico Region................. 130,170 48,809 226,096 118,849
International......................... 0 0 2,054,175 1,437,923
Other................................. 34,493 28,457 89,825 43,800
-------- -------- ----------- -----------
Total............................. 705,513 414,159 3,698,160 2,233,592
======== ======== =========== ===========
- --------
(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 3,698,160 gross and 2,233,592
net undeveloped acres, 266,229 gross and 96,679 net acres are held by
production from other leasehold acreage.
Substantially all the leases summarized in the preceding table will expire
at the end of their respective primary terms unless the existing leases are
renewed or production has been obtained from the acreage subject to the lease
prior to that date, in which event the lease will remain in effect until the
cessation of production. The following table sets forth the gross and net
acres subject to leases summarized in the preceding table that will expire
during the periods indicated:
Acres Expiring
--------------------
Gross Net
--------- ---------
Twelve Months Ending:
December 31, 1999....................................... 111,812 64,823
December 31, 2000....................................... 2,227,515* 1,518,680*
December 31, 2001....................................... 158,916 84,109
December 31, 2002 and later............................. 915,342 458,715
* Of the acreage expiring in the year 2000, 2,054,175 gross (1,437,923 net)
acres are attributable to the Company's license on Block 67 in the Republic
of Peru. This acreage will expire only if the Company elects not to proceed
with further activity on Block 67.
Overriding Royalty Interests
The Company owns overriding royalty interests covering in excess of 137,401
gross acres. The majority of these overriding royalty interests are within a
range of approximately .25 to 5.0 percent.
13
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. Through these natural gas
trading activities, the Company obtains knowledge and information that enables
it to more effectively market its own production.
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, 1998, less than 3% of the
Company's production was committed to natural gas sales contracts that had
fixed prices or price ceilings. With the exception of two contracts covering
approximately 8,100 MMBtu per day of natural gas production from the Piceance
Basin through 2011, none of the contracts provides for fixed prices or price
ceilings. The Company believes that it has sufficient production from its
properties to meet the Company's delivery obligations under its existing
natural gas sales contracts.
The Company has entered into a series of firm transportation agreements with
various Rocky Mountain pipeline companies. At January 1, 1999, these
transportation arrangements had terms ranging from seven months 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 46% of the Company's current daily Rocky Mountain 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, 1998, the Company had entered into financial transactions
to hedge approximately 8.0 million MMBtu of natural gas production on a short
term for the period from January 1999 through October 1999. 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 million MMBtu of natural gas production from the Rocky Mountain
Region for the five-year period from March 1998 through February 2003. At
year-end 1998, 100.0 million MMBtu of these hedges remained in place.
For the year ended December 31, 1998, revenues from trading activities,
which includes the cost of natural gas purchased or sold for trading purposes,
were $413.0 million, which constituted 66% of the Company's consolidated
revenues and generated a gross margin of $14.9 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 1998. Oil
revenues totaled $23.2 million for the year ended December 31, 1998 and
represented 4% of the Company's total revenues for that period. The Company
does not engage in oil trading activities.
14
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.
15
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
May 6, 1998 included in the Company's Registration Statement on Form S-3 (File
Number 333-51985). All written and oral forward-looking statements
attributable to the Company or persons acting on its behalf subsequent to the
date of this Annual Report on Form 10-K are expressly qualified in their
entirety by the Cautionary Statements.
16
Item 3. Legal Proceedings
Plains Petroleum Company Tax Case
The Internal Revenue Service ("IRS") has examined the federal tax returns of
Plains, a wholly owned subsidiary of the Company, for pre-merger calendar
years 1991, 1992 and 1993. The IRS issued a "Notice of Deficiency" of $5.3
million together with penalties of $1.1 million, and an undetermined amount of
interest. The IRS Notice of Deficiency resulted primarily from the IRS's
disallowance of certain net operating loss deductions claimed during the
periods under examination. These net operating losses originally had been
incurred by companies that were acquired by Tri-Power Petroleum, Inc. which
was then acquired by Plains in 1986. For years following 1993, the Company has
additional net operating loss carryforwards of approximately $30 million
related to the same acquisition, of which $28 million has been used in
subsequent income tax returns.
The IRS has also examined the federal tax returns of the Company for the
periods ended July 1995, December 1995 and December 1996. The IRS issued a
letter proposing changes to tax for those periods totaling $5.7 million. The
proposed tax changes resulted primarily from the disallowance of net operating
loss and merger related deductions claimed for the periods ended December 1995
and 1996. These net operating losses are the primary issue involved with the
earlier examination of the Plains' tax returns for the calendar years 1991
through 1993.
Management disagrees with the IRS position. In management's opinion, the
federal tax returns of Plains reflect the proper federal income tax liability
and the existing net operating loss carryforwards are appropriate as supported
by relevant authority. The Company is vigorously contesting these proposed
adjustments and believes its positions will be substantially sustained. In
this connection, the Company filed a petition on November 29, 1996 with the
United States Court requesting a redetermination of the IRS's Notice of
Deficiency. A trial of this matter was held in May 1998, and all post-trial
briefs have been filed. A decision is expected in the first half of 1999.
Kansas Ad Valorem Tax Refund
Pursuant to an August 1996 decision of the United States Court of Appeals
for the District of Columbia Circuit (the "Circuit Court") 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 has 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. Beginning in the second quarter of 1999 Plains will
reduce royalty payments to its current Kansas royalty owners to recoup the
amount placed in escrow. As amounts are recouped from royalty owners the
escrowed funds will be released to the gas purchaser to whom the refund is
owed. Only to the extent Plains is unsuccessful in recouping this amount from
its royalty owners or is unable to obtain FERC relief for the royalty-related
refunds not so recouped will Plains have any financial obligation for any part
of this royalty owner refund obligation. Also, Plains 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, Plains will recover
approximately $2,600,000 of the amount it has refunded.
Other Legal Proceedings
At December 31, 1998, the Company was a party to certain other legal
proceedings, which have arisen out of the ordinary course of business. Based
on the facts currently available, in management's opinion, the liability,
individually or in the aggregate, if any, to the Company resulting from such
actions will not have a material adverse effect on the Company's consolidated
financial position or results of operations.
Item 4. Submission of Matters to Vote of Security Holders
No matters were submitted to a vote of the Company's security holders during
the fourth quarter of the year ended December 31, 1998.
17
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:
Quarter Ended High Low
------------- ------ ------
March 31, 1997................................................. $46.00 $29.87
June 30, 1997.................................................. $34.37 $26.62
September 30, 1997............................................. $38.93 $25.37
December 31, 1997.............................................. $41.06 $27.93
March 31, 1998................................................. $34.94 $24.06
June 30, 1998.................................................. $39.37 $31.06
September 30, 1998............................................. $38.00 $18.87
December 31, 1998.............................................. $28.93 $16.69
On March 15, 1999, the closing price for the Company's common stock was
$22.25 per share.
(b) Holders. The number of record holders of the Company's common stock as
of March 15, 1999 was 3,581.
(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:
Year Ended December 31,
----------------------------------------------
1998 1997 1996 1995 1994
-------- -------- -------- -------- --------
(in thousands, except per share data)
Revenues....................... $625,399 $382,600 $202,572 $128,016 $109,458
Net income (loss).............. (93,743) 29,261 29,526 (2,240) 11,299
Net income (loss) per share.... (2.95) 0.92 1.02 (0.09) 0.46
Total assets at the end of each
period........................ 838,879 872,701 576,945 340,412 310,952
Long-term debt at the end of
each period................... 334,067 266,437 70,000 89,000 53,000
18
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, 1998, the Company had cash and cash equivalents of $14.3
million, negative working capital of $5.1 million, property and equipment of
$682.2 million and total assets of $838.9 million. Compared to December 31,
1997, cash and cash equivalents decreased $0.2 million, working capital
decreased $1.9 million, net property and equipment decreased $65.0 million,
and total assets decreased $33.8 million. The decrease in property and
equipment and total assets in 1998 is principally attributed to an impairment
of oil and gas properties of $168.3 million (pre-tax) resulting from the
application of the full cost ceiling test.
During 1998, the Company generated operating cash flow of $119.3 million
before working capital changes compared with $120.1 million in 1997. After
working capital changes, cash flow provided by operations was $117.0 million,
a decrease of $17.3 million from 1997.
As of December 31, 1998 and 1997, respectively, the outstanding balance
under the Company's bank credit facility was $175 million and $100 million.
The Company's bank credit facility is an unsecured $250 million facility with
a consortium of six banks. As of December 31, 1998, the Company's borrowing
base was $200 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 Company's lenders
are currently reviewing the December 31, 1998 reserve report to determine
current collateral value. 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. As of March 10, 1999, the Company had reduced the outstanding balance of
this credit facility by $25 million to $150 million.
Capital Expenditures
During 1998 the Company invested $205.8 million in oil and gas properties
and other equipment, including acquisitions and exploration and development
programs. The 1998 acquisition program consisted principally of purchasing
additional interests in the Block 67 license located in the Republic of Peru
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, the
Gulf of Mexico and the Republic of Peru.
The Company's capital expenditure budget for 1999 has been established at
$92 million. In response to low product prices and the desire to limit debt
levels, the Company decreased its 1999 capital expenditure budget by $113.8
million from the 1998 capital expenditure level. Approximately 51 percent of
the 1999 budget will be concentrated on drilling and completion of proved
undeveloped reserves on existing properties. The Company's 1999 exploration
and development program will be focused in the Rocky Mountain Region ($66
million), Mid-Continent ($14 million) and the Gulf of Mexico ($12 million).
Due to lower oil prices, the Company has limited its activities in its
international project located in the Republic of Peru. The Company's
exploration and development programs are discussed in "Business and
Properties" under Items 1 and 2 of this Form 10-K.
19
Reserves and Pricing
Proved reserves at year-end 1998 were 970.3 billion cubic feet of natural
gas equivalents (Bcfe), approximately a one percent increase over the
Company's December 31, 1997 proved reserves. Approximately 98 percent of the
reserve additions were generated through exploration and development projects
and two percent of the reserve additions were provided by property
acquisitions. Proved reserves were reduced by production of approximately
107.1 Bcfe, sales of properties with reserves of 11.6 Bcfe, and downward
revisions of previous estimates of 100.0 Bcfe. Lower year-end prices and lower
than expected performance of certain properties contributed to the adjustments
of previous estimates. During 1998, as a result of its drilling and
acquisition activities net of sales and revisions, the Company's reserve
replacement was 107 percent of total production.
As of year-end 1998, the standardized measure of discounted future net cash
flows decreased $33.5 million, or six percent, from 1997 primarily due to
reserve revisions and decreases in oil and gas prices offset by reserve
quantity additions. Reserve extensions and discoveries added $115 million to
the standardized measure. The changes in year-end sales prices and production
costs from 1997 to 1998 decreased the standardized measure of discounted
future net cash flows by $103 million. Reserves produced during the year and
sales of proved reserves, net of purchases, reduced the standardized measure
by $147 million and $7 million, respectively. 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,
1998, the Company was receiving weighted average prices of $9.35 per barrel of
oil and $2.01 per Mcf of gas. These lower prices caused the Company to
recognize a pre-tax "ceiling test" impairment of $129 million on its U.S.
properties. In addition, the Company recognized a pre-tax impairment of $39
million on its exploration projects in Peru. A further 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. In a typical swap agreement, the Company and a
counterparty will enter into an agreement whereby one party will pay a fixed
price and the other will pay an index price on a specified volume of
production during a specified period of time. Settlement is made by the
parties for the difference between the two prices at approximately the same
time as the physical transactions. The intent of hedging activities is to
reduce the volatility associated with the sales prices of the Company's
natural gas and oil production. Although hedging transactions associated with
the Company's production 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, 1998, the Company held positions to hedge 108
million MMBtu of the Company's future natural gas production through February
2003. The Company currently has no oil swaps in place.
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. The Company intends to
continue to acquire and develop oil and gas properties in its areas of
activity as dictated by market conditions and financial ability. The Company
retains flexibility to participate in oil and gas activities at a level that
is supported by its cash flow and financial ability. Management believes that
the Company's borrowing capacities and cash flow are sufficient to fund its
currently anticipated activities. The Company intends to continue to use
financial leverage to fund its operations as investment opportunities become
available on terms that management believes warrant investment of the
Company's capital resources.
Year 2000
The following Year 2000 statements constitute a Year 2000 Readiness
Disclosure within the meaning of the Year 2000 Information and Readiness
Disclosure Act of 1998.
20
Year 2000 issues result from the inability of certain electronic hardware
and software to accurately calculate, store or use a date subsequent to
December 31, 1999. These dates can be erroneously interpreted in a number of
ways, e.g., the year 2000 could be interpreted as the year 1900. This
inability could result in a system failure or miscalculations that could in
turn cause operational disruptions. These issues could affect not only
information technology ("IT") systems, such as computer systems used for
accounting, land, engineering and seismic processing, but also systems that
contain embedded chips.
The Company has completed an assessment of its IT systems to determine
whether these systems are Year 2000 compliant. The Company has determined that
these systems are either compliant or with relatively minor modifications or
upgrades (many of which would have been made in any event as part of the
Company's continuing effort to enhance its IT systems) will be compliant. All
necessary modifications and upgrades and the testing thereof are expected to
be completed by the end of the first quarter of 1999.
The Company is assessing its non-information systems to ascertain whether
these systems contain embedded computer chips that will not properly function
subsequent to December 31, 1999. These systems include office equipment, the
automatic wellhead equipment used to operate wells in the Piceance Basin and
southwest Kansas, the Company-owned gas gathering pipelines in the Piceance
Basin, the Uinta Basin and in southwest Kansas, and the Company's gas
processing plant in the Piceance Basin. Except for certain portions of the
southwest Kansas wellhead automation equipment, all of these systems have been
determined to be Year 2000 compliant. The Company has completed the
modifications and testing of the southwest Kansas wellhead automation
equipment and determined that the equipment is Year 2000 compliant. A Company-
wide test will be made in the second quarter of 1999 to verify that all IT
systems are Year 2000 compliant.
To date, the Company has relied upon its internal staff to assess its Year
2000 readiness. Outside consultants have been and will be used for limited
projects such as the modification and testing of the southwest Kansas wellhead
automation equipment. The costs associated with assessing the Company's Year
2000 internal compliance and related systems modification, upgrading and
testing are not currently expected to exceed $250,000. Costs incurred through
December 31, 1998 have been minimal.
The Company is in the process of communicating with certain of its
significant suppliers, service companies, gas gatherers and pipelines,
electricity providers and financial institutions to determine the
vulnerability of the Company to third parties' failure to address their Year
2000 issues. While the Company has not yet received definitive responses
indicating all such entities are Year 2000 compliant, it has not received
information suggesting the Company is vulnerable to potential Year 2000
failures by these parties. These communications are expected to continue into
the first quarter of 1999. At this time the Company has not developed any
contingency plans to address third party non-compliance with Year 2000
matters. However, should its communications with any third parties indicate
significant vulnerability, development of contingency plans will be
considered.
The Company does not anticipate any significant disruptions of its
operations due to Year 2000 issues. Among the potential "worst case" problems
the Company could face would be the loss of electricity used to power well
pumps and compressors that would result in wells being shut-in, or the
inability of a third party gas gathering company or pipeline to accept gas
from the Company's wells or gathering lines which would also result in the
Company's wells being shut-in. A disruption in production would result in the
loss of income.
Results of Operations
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).
21
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 per Mcf in 1997 to $1.92 per Mcf in 1998. Gas production
accounted for 89 percent of total production on an energy equivalent basis.
The Wind River and Piceance Basins properties accounted for 24 percent and 21
percent, respectively, of total gas production. The Powder River and Uinta
Basins 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 U.S. 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.
1997 vs. 1996
In 1997, the Company adopted Statement of Financial Accounting Standards No.
128, "Earnings Per Share" (SFAS No. 128). As prescribed by SFAS No. 128,
earnings per share amounts for 1996 have been restated. References to per
share amounts are based on diluted shares outstanding.
During 1997, the Company earned net income of $29.3 million ($.92 per share)
compared to $29.5 million ($1.02 per share) in 1996.
Revenues increased $180 million (89 percent) to $382.6 million in 1997.
Operating expenses increased 112 percent to $335.4 million. In 1997, oil and
gas production revenue increased 36 percent to $206.9 million, and trading
revenues increased 265 percent to $171.1 million. Lease operating expenses
increased $10.3 million and depreciation, depletion and amortization increased
$26.6 million.
22
Production revenues increased $55.2 million to $206.9 million primarily due
to a 46 percent increase in gas revenues. The increased gas revenues are a
result of an increase in the average gas price from $1.88 per Mcf in 1996 to
$2.18 per Mcf in 1997 and an increase in gas production of 15.7 Bcf (26
percent) for 1997. Gas production accounted for 85 percent of total production
on an energy equivalent basis. The Wind River Basin and Piceance Basin
properties accounted for 26 percent and 21 percent, respectively, of total gas
production. The Powder River Basin and Uinta Basin properties accounted for 40
percent and 23 percent, respectively, of total oil production.
Lease operating expenses of $57.9 million averaged $.64 per Mcfe ($3.86 per
BOE) compared to $.66 per Mcfe ($3.95 per BOE) in 1996. Depreciation,
depletion and amortization increased $26.6 million primarily due to production
increases. During 1997, depletion and amortization on oil and gas production
was provided at an average rate of $.77 per Mcfe ($4.60 per BOE) compared to
an average rate of $.59 per Mcfe ($3.54 per BOE) in 1996.
The gross margin on trading activities increased $3.1 million to $5.9
million in 1997. Gas trading volumes increased 183 percent to 84.8 million
MMBtu in 1997.
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 1997, the Company
hedged 18.6 Bcf (24 percent) of its gas production for a net cost of $4.3
million. No oil was hedged during 1997.
General and administrative expenses of $24.9 million reflect an increase of
47 percent over the previous year. The 1997 amount is net of $5.0 million of
operating fee recoveries compared to a $4.0 million recovery in 1996. The 1997
increase in general and administrative expenses is a result of the Company's
continued growth and expansion. Interest expense increased significantly from
$3.7 million in 1996 to $13.2 million in 1997 due primarily to the issuance of
$150 million of long term bonds in February 1997.
Income tax expense increased by 20 percent in 1997 to $17.9 million. The
Company's effective financial statement tax rate in 1997 was 38.0 percent
compared to 33.6 percent in 1996.
Item 7a. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
The Company uses commodity derivative financial instruments, including
futures and swaps, to reduce the effect of natural gas price volatility on a
portion of its natural gas production. Commodity swap agreements are generally
used to fix a price at the natural gas market location or to fix a price
differential between the price of natural gas at Henry Hub and the price of
gas at its market location. Settlements are based on the difference between a
fixed and a variable price as specified in the agreement. The following table
summarizes the Company's derivative financial instrument position on its
natural gas production as of December 31, 1998. 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, 1998.
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.
For the year MMBtu Price Range Per MMBtu Fair Value
------------ ----------- --------------------- ----------------
1999--2003 108 million $1.71--$2.25 $(13.25) million
23
The Company also uses commodity derivative financial instruments in its
trading activities to hedge price fluctuations 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 financial instrument
position on its natural gas trading activities as of December 31, 1998. 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, 1998.
Actual settlement of these instruments as they mature will differ from these
estimates. Gains or losses realized from these instruments hedging the
Company's production are expected to be offset by corresponding changes in the
settlement value of actual natural gas traded.
For the year MMBtu Price Range Per MMBtu Fair Value
------------ ------------- --------------------- --------------
1999--2001 294.8 million $1.46--$2.77 $27.33 million
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, 1998.
Expected Maturity /Redemption
------------------------------------------------
Fair
1999 2000 2001 2002 2003 Thereafter Value
---- ---- ---- ------ ---- ---------- ------
(Dollars in millions)
Long-term debt:
Fixed rate............... $5.4 $4.4 $3.4 $ 1.3 -- $150.0 $158.8
Average Interest Rate.... 7.56% 7.56% 7.56% 7.55% -- 7.55%
Variable rate............ -- -- -- $175.0 -- -- $175.0
Average Interest Rate.... -- -- -- 5.625% -- --
Item 8. Financial Statements and Supplemental Data
The Consolidated Financial Statements and schedules that constitute Item 8
are attached at the end of this Annual Report on Form 10-K. An index to these
Consolidated Financial Statements and Schedules is also included in Item 14(a)
of this Annual Report on Form 10-K.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosures
Not applicable.
24
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:
Director
Age Position With the Company Since
--- ------------------------- --------
William J. 70 Chairman of the Board, Chief
Barrett(1)(6)(8)........... Executive Officer, and a Director 1983
C. Robert 65 Director
Buford(1)(2)(3)(4)(5)...... 1983
Derrill 60 Director
Cody(1)(2)(3)(4)(5)........ 1995
James M. 64 Director
Fitzgibbons(3)(4)(5)(7).... 1987
William W. Grant, 66 Director
III(3)(4)(5)............... 1995
J. Frank Keller(6).......... 55 Chief Financial Officer, Executive
Vice President, and a Director 1983
A. Ralph Reed............... 61 Chief Operating Officer, President
and a Director 1990
James T. Rodgers(3)(4)(5)... 64 Director 1993
Philippe S.E. 58 Director
Schreiber(1)(2)(3)(4)(5)... 1985
Joseph P. Barrett(8)........ 45 Senior Vice President--Land --
Peter A. Dea................ 45 Executive Vice President--
Exploration --
Bryan G. Hassler............ 40 Vice President--Marketing --
Robert W. Howard............ 44 Senior Vice President--Investor
Relations, Corporate Development
and Treasurer --
Eugene A. Lang, Jr.......... 45 Senior Vice President and General
Counsel; and Secretary --
Logan Magruder, III......... 42 Vice President--Operations --
Maurice F. Storm............ 38 Vice President and General Manager--
Mid- Continent Region --
- --------
(1) Member of the Executive Committee of the Board of Directors.
(2) Member of the Board Planning and Nominating Committee of the Board of
Directors.
(3) Member of the Audit Committee of the Board of Directors.
(4) Member of the Compensation Committee of the Board of Directors.
(5) Member of the Succession 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 has continuously 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 proprietorships. From 1971 to 1978, Mr.
Barrett served as Vice President--Exploration and a director of Rainbow
Resources, Inc., a publicly held
25
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. Mr. Barrett intends to retire as Chairman of the
Board and Chief Executive Officer in March 2000.
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 1.9 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, 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.
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. 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 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 has been an advisory director of Colorado National Bank since 1993. He was
a director of Colorado National Bankshares, Inc. from 1982 to 1993 and the
Chairman of the Board of Colorado National Bank 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 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
26
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 is a Director of the United States affiliates of
The Mayflower Corporation plc., a British publicly traded company involved in
the business of supplying parts and components to auto and truck
manufacturers.
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.
Peter A. Dea was elected Executive Vice President--Exploration effective
December 11, 1998. He served as Senior Vice President--Exploration of the
Company from June 1996 through December 11, 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 in Denver, Colorado
from 1992 through 1993. From 1982 until 1991, Mr. Dea served in various
positions with Exxon Company USA as a Geologist in the Production Department
in Corpus Christi, Texas and as a Senior Geologist and Supervisor in the
Exploration Department in Denver, Colorado. Mr. Dea served as adjunct
Professor of Geology at Western State College, Gunnison, Colorado in the
spring semesters of 1980 and 1982.
Bryan G. Hassler has been Vice-President--Marketing of the Company since
December 1996. 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 been Senior Vice President--General Counsel of the
Company since September 1995. 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 1991, Mr. Magruder held
petroleum engineering and corporate relations positions with other exploration
and production companies.
27
Maurice F. Storm has been Vice President and General Manager of the
Company's Mid-Continent Division since July 1996. From October 1991 to July
1996 Mr. Storm was retained by the Company as a consultant to develop drilling
opportunities in the Anadarko and Arkoma Basins. From September 1984 through
October 1991 Mr. Storm worked for other independent exploration and production
companies in various exploration geologist and management positions.
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,
1998, its officers, directors and holders of more than 10% of the Company's
common stock complied with all Section 16(a) filing requirements. In making
these statements, the Company has relied upon the written representations of
its directors and officers.
28
Item 11. Executive Compensation
Summary Compensation Table
The following table sets forth in summary form the compensation received
during each of the Company's last three completed years by the Chief Executive
Officer and former Chief Executive Officer of the Company and by the four
other most highly compensated executive officers whose compensation exceeded
$100,000 during the year ended December 31, 1998. The figures in the following
table are for fiscal years ended December 31, 1998, 1997, and 1996:
Summary Compensation Table
Long Term Compensation
-------------------------------
Awards Payouts
----------------------- -------
Other
Annual Restricted Securities
Compen- Stock Underlying LTIP All Other
Name and Principal Fiscal Salary Bonus sation Award(s) Options/SARs Payouts Compensation
Position Year ($) ($)(1) ($)(2) ($)(3) (#)(4) ($)(5) ($)(6)
------------------ ------ -------- -------- ------- ---------- ------------ ------- ------------
William J. Barrett(7)... 1998 $306,512 $145,000 -0- -0- 110,000 -0- $9,600
Chairman of the Board,
Chief 1997 $215,000 $250,000 -0- -0- 50,000 -0- $9,500
Executive Officer, and
a director 1996 $255,417 $150,000 -0- -0- 100,000 -0- $7,913
Paul M. Rady(8)......... 1998 $109,730 $ 95,000 -0- -0- -0- -0- $6,075
Former President,
former Chief 1997 $266,252 $160,000 -0- -0- 50,000 -0- $9,500
Executive Officer, and
former director 1996 $206,667 $ 63,000 -0- -0- 52,000 -0- $8,138
A. Ralph Reed(9)........ 1998 $272,250 $ 70,000 -0- -0- 60,000 -0- $9,600
President, Chief
Operating 1997 $217,500 $120,000 -0- -0- -0- -0- $9,500
Officer, and a director 1996 $207,917 $ 54,000 -0- -0- 40,000 -0- $7,988
J. Frank Keller......... 1998 $177,131 $ 50,000 -0- -0- 35,000 -0- $9,600
Executive Vice
President, 1997 $165,768 $ 90,000 -0- -0- 26,700 -0- $9,500
Chief Financial
Officer, and a director 1996 $155,938 $ 40,000 -0- -0- 19,200 -0- $8,222
Peter A. Dea............ 1998 $167,708 $ 35,000 -0- -0- 142,000 -0- $9,600
Executive Vice
President-- 1997 $153,750 $ 65,000 -0- -0- 7,500 -0- $8,838
Exploration 1996 $134,625 $ 25,000 -0- -0- 30,000 -0- $7,224
Bryan G. Hassler........ 1998 $143,950 $ 50,000 -0- -0- 16,000 -0- $8,636
Vice President--
Marketing 1997 $135,000 $ 50,000 -0- -0- -0- -0- $9,500
1996 $ 95,676 $ 33,493 -0- -0- 18,000 -0- $5,085
- --------
(1) The dollar value of bonus (cash and non-cash) paid during the year
indicated. On February 26, 1999, the Compensation Committee awarded a cash
bonus of $121,000 to Mr. Hassler in accordance with the Company's
Marketing and Trading Group Bonus Plan based on 1998 results of the
Marketing and Trading Group. No bonuses were paid to the other named
Executive Officers.
(2) During the period covered by the Table, the Company did not pay any other
annual compensation not properly categorized as salary or bonus, including
perquisites and other personal benefits, securities or property.
(3) During the period covered by the Table, the Company did not make any award
of restricted stock, including share units.
(4) The sum of the number of shares of Common Stock to be received upon the
exercise of all stock options granted.
(5) Except for stock option plans, the Company does not have in effect any
plan that is intended to serve as incentive for performance to occur over
a period longer than one fiscal year.
(6) Represents the Company's matching contribution under the Company's 401(k)
Plan for each named executive officer.
(7) Mr. Barrett was elected as Chief Executive Officer on March 23, 1998.
(8) Mr. Rady served as Chief Executive Officer from July 1, 1997 until March
23, 1998 and as President from September 1994 until March 23, 1998, and
he was an employee of the Company through April 30, 1998.
(9) Mr. Reed was elected as President and Chief Operating Officer on March
23, 1998.
29
Option Grants in Last Fiscal Year
No stock appreciation rights were granted to any executive officers or
employees in the year ended December 31, 1998. The following table provides
information on stock option grants in the year ended December 31, 1998 to the
named executive officers.
Option Grants In Last Fiscal Year
Potential Realizable
Value at Assumed
Number of % of Total Annual Rates of Stock
Securities Options Price appreciation
Underlying Granted to Exercise for Option Term
Options Employees in Price ---------------------
Name Granted (#) Fiscal Year ($/Share) Expiration Date 5% 10%
---- ----------- ------------ --------- ----------------- ---------- ----------
William J. Barrett...... 100,000(1) 9.36% $33.625 March 25, 2005 $ 14,500 $1,314,500
10,000(2) 0.94% $24.375 October 23, 2005 $ 93,950 $ 223,950
Paul M. Rady(3)......... -0- -0- -- -- -- -- -- -- -- --
A. Ralph Reed........... 50,000(4) 4.68% $33.625 March 25, 2005 $ 7,250 $ 657,250
10,000(2) 0.94% $24.375 October 23, 2005 $ 93,950 $ 223,950
J. Frank Keller......... 30,000(4) 2.81% $33.625 March 25, 2005 $ 4,350 $ 394,350
5,000(2) 0.47% $24.375 October 23, 2005 $ 46,975 $ 111,975
Peter A. Dea............ 20,000(4) 1.87% $33.625 March 25, 2005 $ 2,900 $ 262,900
15,000(5) 1.40% $32.625 July 31, 2005 $ 17,175 $ 212,175
7,000(6) 0.66% $24.375 October 23, 2005 $ 65,765 $ 156,765
100,000(7) 9.36% $22.125 December 11, 2005 $1,164,500 $2,464,500
Bryan G. Hassler........ 15,000(4) 1.40% $33.625 March 25, 2005 $ 2,175 $ 197,175
10,000(5) 0.94% $32.625 July 31, 2005 $ 11,450 $ 141,450
5,000(6) 0.47% $24.375 October 23, 2005 $ 46,975 $ 111,975
- --------
(1) One-half of these option shares become exercisable on March 25, 1999, and
the other half become exercisable on March 25, 2000.
(2) These option shares were exercisable on the date of grant, October 23,
1998.
(3) Mr. Rady served as Chief Executive Officer from July 1, 1997 until March
23, 1998 and as President from September 1994 until March 23, 1998.
(4) One-fourth of these option shares become exercisable on each of March 25,
1999; March 25, 2000 and March 25, 2002.
(5) One-fourth of these option shares become exercisable on each of July 23,
1999; July 23, 2000; July 23, 2001 and July 23, 2002.
(6) One-fourth of these option shares become exercisable on each of July 31,
1999; July 31, 2000; July 31, 2001 and July 31, 2002.
(7) One-fourth of these option shares become first exercisable on each of
December 11, 1999; December 11, 2000; December 11, 2001 and December 11,
2002.
30
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, 1998 by the Company's Chief
Executive Officer and the four other most highly compensated executive
officers of the Company whose compensation exceeded $100,000 during the year
ended December 31, 1998 and the year-end value of unexercised options held by
these persons:
Aggregated Option Exercises
For Fiscal Year Ended December 31, 1998
And Year-End Option Values (/1/)
Number of
Securities Underlying Value of Unexercised
Unexercised Options In-the-Money Options
Shares Value at Fiscal Year-End(#)(4) at Fiscal Year-End($)(5)
Acquired on Realized ------------------------- -------------------------
Name Exercise(2) ($)(3) Exercisable Unexercisable Exercisable Unexercisable
---- ----------- ---------- ----------- ------------- ----------- -------------
William J. Barrettt .... 19,524 $ 225,746 188,000 100,000 $321,250 -0-
Chief Executive
Officer, and Chairman
of the Board and a
director
Paul M. Rady ........... 100,000 $1,844,375 -0- -0- -0- -0-
Former President,
former Chief Executive
Officer, and former
director
A. Ralph Reed........... 56,648 $ 626,346 58,400 70,000 $198,550 $ 17,500
President, Chief
Operating Officer and a
director
J. Frank Keller......... -0- -0- 76,275 59,625 $505,225 $ 8,400
Executive Vice
President, Chief
Financial Officer, and
a director
Peter A. Dea............ 12,500 $ 170,313 24,375 162,000 $100,000 $191,875
Executive Vice
President--Exploration
Bryan G. Hassler........ 1,019 $ 18,661 19,731 40,250 $ 44,504 -0-
Vice President--
Marketing
- --------
(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, 1998.
(3) With respect to options exercised during the Company's year ended
December 31, 1998, 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, 1998,
separated between those options that were exercisable and those options
that were not exercisable.
(5) For all unexercised options held as of December 31, 1998, 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, 1998. As
required, the price used to calculate these figures was the closing sale
price of the Common Stock at year's end, which was $24.00 per share on
December 31, 1998. On March 15, 1999, the closing sale price was $22.25
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. The Company currently
contributes on behalf of each participating employee 100 percent of that
employee's contribution, up to a maximum of six percent of base salary, 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
31
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. Each Outside Director also receives
$300 for each telephone meeting lasting more than 15 minutes. The Chairman of
the Compensation and Audit Committees receives a $1,500 meeting attendance fee
for each committee meeting. 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 their
exercise price is equal to the closing sales price for the Company's Common
Stock on the date of grant. The options expire upon the later to occur of five
years after the date of grant and two years after the date those options first
became exercisable.
Other Arrangements. During the year ended December 31, 1998, 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 (the "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 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
Agreement), the employee will be entitled to a lump sum cash payment equal to
three times (two times in the case of Messrs. Dea and 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. Dea) from the date of termination. Mr. Barrett's Agreement, as amended,
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 dated through March 31, 2000, in addition to continued
benefits through March 31, 2000.
In addition, the Company's stock option plans and option agreements
thereunder provide for the acceleration of option exercisability in the event
of a change-in-control.
32
Compensation Committee Interlocks and Insider Participation
During the year ended December 31, 1998, Messrs. Buford, Cody, Fitzgibbons,
Grant, Rodgers and Schreiber served as the 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, 1998 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 Chairman of the Board from December 1983 through March
1994. However, Mr. Buford was never a salaried employee of the Company.
Item 12. Security Ownership of Certain Beneficial Owners and Management
The following table summarizes certain information as of March 15, 1999 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:
Name of Amount/Nature of Percent of Class
Beneficial Owner Beneficial Ownership Beneficially Owned
---------------- -------------------- ------------------
William J. Barrett................ 582,741 Shares(1) 1.8%
C. Robert Buford.................. 679,866 Shares(2) 2.1%
Derrill Cody...................... 23,560 Shares(3) *
Peter A. Dea...................... 74,463 Shares(3) *
James M. Fitzgibbons.............. 22,500 Shares(3) *
William W. Grant, III............. 35,150 Shares(3) *
Bryan G. Hassler.................. 31,665 Shares(3) *
J. Frank Keller................... 133,707 Shares(3) *
A. Ralph Reed..................... 128,834 Shares(3) *
James T. Rodgers.................. 23,500 Shares(3) *
Philippe S.E. Schreiber........... 27,007 Shares(3)
All Directors and Executive
Officers as a Group (16
Persons)......................... 1,978,758 Shares(5) 6.0%
Franklin Resources, Inc........... 4,337,676 Shares(6) 13.5%
777 Mariners Island
San Mateo, CA 94403
State Farm Mutual Automobile
Insurance Company and
affiliates....................... 2,935,633 Shares(6)(7) 9.2%
One State Farm Plaza
Bloomington, IL 61710
Lazard Freres & Co. LLC........... 1,601,236 Shares(6) 5.0%
30 Rockefeller Plaza
New York, NY 10020
- --------
* Less than 1% of the Common Stock outstanding.
(1) The number of shares indicated includes 21,292 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 238,000 shares underlying
options that currently are exercisable or become exercisable within 60
days following March 15, 1999. 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 598,210 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
33
Exchange Act. The number of shares indicated also includes 12,500 shares
underlying stock options that currently are exercisable or that become
exercisable within 60 days following March 15, 1999.
(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, 1999 that are held
by each of the following persons: Derrill Cody, 23,300; Peter A. Dea,
65,000; James M. Fitzgibbons, 10,500; William W. Grant, III, 22,800; Bryan
G. Hassler, 30,250; J. Frank Keller, 91,500; James T. Rodgers, 13,500 and
Philippe S.E. Schreiber, 20,000.
(4) The number of shares indicated includes 7,800 shares owned by Mary C.
Reed, Mr. Reed's wife, and 80,900 shares underlying options that currently
are exercisable or that become exercisable within 60 days following March
15, 1999.
(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 608,250 shares underlying the options described in notes (1),
(2), (3) and (4), an aggregate of 33,264 shares owned by five executive
officers not named in the above table, and an aggregate of 182,501 shares
underlying options that currently are exercisable or that are exercisable
within 60 days following March 15, 1999 that are held by those five
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 1998, 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.
34
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
Report of Independent Public Accountants.............................. F-1
Consolidated Balance Sheets at December 31, 1998 and 1997............. F-2
Consolidated Statements of Income for each of the three years in the
period ended December 31, 1998....................................... F-3
Consolidated Statements of Stockholders' Equity for each of the three
years in the period ended December 31, 1998.......................... F-4
Consolidated Statements of Cash Flows for each of the three years in
the period ended December 31, 1998................................... F-5
Notes to the Consolidated Financial Statements........................ F-6
Supplemental Oil And Gas Information.................................. F-21
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 36.
(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, 1998.
35
BARRETT RESOURCES CORPORATION
ANNUAL REPORT ON FORM 10-K
For The Year Ended December 31, 1998
EXHIBIT INDEX
Exhibit Description
------- -----------
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.
4.1A Form of Rights Agreement dated as of August 5, 1997 between Barrett
and BankBoston, N.A., which includes, as Exhibit A thereto, the form
of Certificate of Designations specifying the terms of the Series A
Junior Participating Preferred Stock, and as Exhibit B thereto, the
form of Rights Certificate, is incorporated by reference from Exhibit
1 to the Company's Registration Statement on Form 8-A filed August 11,
1997.
4.1B Amendment to Rights Agreement dated August 5, 1997 between Barrett and
BankBoston, N.A.
4.2 Revised Form of Indenture between the Company and Bankers Trust
Company, as trustee, with respect to Senior Notes including specimen
of 7.55% Senior Notes is incorporated by reference from Exhibit 4.1 to
the Company's Amendment No. 1 to Registration Statement on Form S-3
filed February 10, 1997, File No. 333-19363.
4.3 Form of Indenture between the Registrant and Bankers Trust Company, as
trustee, with respect to Debt Securities is incorporated by reference
from Exhibit 4.2 of Registrant's Registration Statement on Form S-3
filed May 6, 1998 (File No. 333-51985).
10.1 Non-Qualified Stock Option Plan Of Barrett Resources Corporation is
incorporated by reference from Registrant's Registration Statement on
Form S-8 dated November 15, 1989.
10.2 Registrant's 1990 Stock Option Plan, as amended, is incorporated by
reference from the Registrant's Registration Statement on Form S-8
dated March 15, 1995.
10.3 Registrant's Non-Discretionary Stock Option, as amended, is
incorporated by reference from Exhibit 99.2 of the Registrant's Proxy
Statement dated April 24, 1997.
10.4 Registrant's 1994 Stock Option Plan, as amended, is incorporated by
reference from the Registrant's Registration Statement on Form S-8
dated March 15, 1995.
10.5 Registrant's 1997 Stock Option Plan is incorporated by reference from
Exhibit 99.1 of the Registrant's Proxy Statement dated April 24, 1997.
10.6A Gas Purchase Contract, No. P-1090, dated April 20, 1984, as amended,
between Plains and KN Energy, Inc. is incorporated by reference from
Plains Petroleum Company's Registration Statement on Form 10 dated
August 21, 1985.
36
Exhibit Description
------- -----------
10.6B Letter Agreement dated January 11, 1996, amending the Gas Purchase
Contract, No. P-1090, dated April 20, 1984, between Plains and KN
Energy, Inc. is incorporated by reference from Exhibit 10.5B of the
Registrant's Annual Report on Form 10-K for the year ended December
31, 1996.
10.7A 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.
10.7B 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.
10.7C 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.
10.7D 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.
10.7E 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.
10.8A Severance Protection Agreement dated February 6, 1998 between
Registrant and William J. Barrett is incorporated by reference from
Exhibit 10.8 to Registrant's Annual Report on Form 10-K for the year
ended December 31, 1997.
10.8B Amendment No. 1 to Severance Protection Agreement dated November 19,
1998 between Registrant and William J. Barrett.
10.9A 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.
10.9B 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.
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.
37
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Barrett Resources Corporation
We have audited the accompanying consolidated balance sheets of Barrett
Resources Corporation (a Delaware corporation) and subsidiaries as of December
31, 1998 and 1997, and the related consolidated statements of income,
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 1998. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Barrett Resources
Corporation and subsidiaries as of December 31, 1998 and 1997, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 1998, in conformity with generally accepted
accounting principles.
Arthur Andersen LLP
Denver, Colorado
February 26, 1999
F-1
BARRETT RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
December 31, 1998 and 1997
(in thousands)
1998 1997
-------- --------
ASSETS
Current assets:
Cash and cash equivalents.................................. $ 14,339 $ 14,479
Receivables, net........................................... 127,798 102,934
Inventory.................................................. 8,968 2,579
Other current assets....................................... 2,053 1,701
-------- --------
Total current assets..................................... 153,158 121,693
Net property and equipment (full cost method)................ 682,168 747,175
Other assets, net............................................ 3,553 3,833
-------- --------
$838,879 $872,701
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable........................................... $104,799 $ 61,870
Amounts payable to oil and gas property owners............. 16,020 27,174
Production taxes payable................................... 20,400 17,945
Accrued and other liabilities.............................. 17,047 17,917
-------- --------
Total current liabilities................................ 158,266 124,906
Long term debt............................................... 334,067 266,437
Deferred income taxes........................................ 13,294 68,977
Commitments and contingencies--Note 10
Stockholders' equity:
Preferred stock, $.001 par value: 1,000,000 shares
authorized, none outstanding.............................. -- --
Common stock, $.01 par value: 45,000,000 shares authorized,
32,002,304 outstanding (31,415,528 at December 31, 1997).. 320 314
Additional paid-in capital................................. 261,998 247,390
Retained earnings.......................................... 70,934 164,677
-------- --------
Total stockholders' equity............................... 333,252 412,381
-------- --------
$838,879 $872,701
======== ========
See accompanying notes.
F-2
BARRETT RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
Years ended December 31, 1998, 1997 and 1996
(in thousands, except per share data)
1998 1997 1996
--------- -------- --------
Revenues:
Oil and gas production.......................... $ 205,501 $206,907 $151,737
Trading revenues................................ 412,982 171,140 46,862
Interest income................................. 649 1,573 760
Other income.................................... 6,267 2,980 3,213
--------- -------- --------
625,399 382,600 202,572
Operating expenses:
Lease operating expenses........................ 58,626 57,904 47,642
Depreciation, depletion and amortization........ 102,123 72,389 45,775
Impairment...................................... 168,304 -- --
Cost of trading................................. 398,041 165,218 44,036
General and administrative...................... 24,546 24,890 16,947
Interest expense................................ 20,858 13,243 3,684
Other expenses, net............................. 2,412 1,770 --
--------- -------- --------
774,910 335,414 158,084
--------- -------- --------
(Loss) income before income taxes................. (149,511) 47,186 44,488
(Benefit) provision for income taxes.............. (55,768) 17,925 14,962
--------- -------- --------
Net (loss) income................................. $ (93,743) $ 29,261 $ 29,526
========= ======== ========
(Loss) earnings per common share
Basic........................................... $ (2.95) $ .93 $ 1.04
Assuming dilution............................... $ (2.95) $ .92 $ 1.02
See accompanying notes.
F-3
BARRETT RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Years ended December 31, 1998, 1997 and 1996
(in thousands)
Additional Total
Common Paid-In Treasury Retained Stockholders'
Stock Capital Stock Earnings Equity
------ ---------- -------- -------- -------------
Balance, January 1, 1996.... $251 $ 86,154 $ (467) $105,890 $191,828
Exercise of stock
options.................. 2 4,077 (527) -- 3,552
Purchase of treasury
stock.................... -- -- (351) -- (351)
Retirement of treasury
stock.................... -- (1,345) 1,345 -- --
Stock issued in connection
with
property acquisitions.... 6 18,362 -- -- 18,368
Issuance of common stock,
net...................... 54 134,743 -- -- 134,797
Net income for the year
ended December 31, 1996.. -- -- -- 29,526 29,526
---- -------- ------ -------- --------
Balance, December 31, 1996.. 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 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 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
==== ======== ====== ======== ========
See accompanying notes.
F-4
BARRETT RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years ended December 31, 1998, 1997 and 1996
(in thousands)
1998 1997 1996
--------- --------- ---------
Cash flows from operations:
Net (loss) income........................... $ (93,743) $ 29,261 $ 29,526
Adjustments needed to reconcile to net cash
flow provided by operations:
Depreciation, depletion and amortization
and impairment........................... 270,858 72,743 45,775
Unrealized (gain) on trading.............. -- -- (1,139)
Deferred income taxes..................... (55,683) 18,069 13,655
Other..................................... (2,168) -- --
--------- --------- ---------
119,264 120,073 87,817
Change in current assets and liabilities:
Receivables................................. (24,864) (29,889) (41,956)
Other current assets........................ (6,383) (1,697) (582)
Accounts payable............................ 42,929 20,253 27,248
Amounts due oil and gas owners.............. (11,154) 8,678 9,622
Production taxes payable.................... 2,455 4,115 5,783
Accrued and other liabilities............... (5,277) 12,749 742
--------- --------- ---------
Net cash flow provided by operations.......... 116,970 134,282 88,674
--------- --------- ---------
Cash flows from investing activities:
Proceeds from sales of oil and gas
properties................................. 6,393 14,233 1,948
Acquisitions of property and equipment...... (203,056) (340,015) (202,610)
--------- --------- ---------
Net cash flow used in investing activities.... (196,663) (325,782) (200,662)
--------- --------- ---------
Cash flows from financing activities:
Proceeds from issuance of common stock,
net........................................ 5,498 1,183 138,349
Purchase of treasury stock.................. -- (2) (351)
Proceeds from long-term borrowing........... 119,000 130,577 91,000
Payments on long-term debt.................. (44,794) (86,131) (110,000)
Proceeds from Senior Notes, net of offering
costs...................................... -- 145,963 --
Other....................................... (151) (150) --
--------- --------- ---------
Net cash flow provided by financing
activities................................... 79,553 191,440 118,998
--------- --------- ---------
Increase (decrease) in cash and cash
equivalents.................................. (140) (60) 7,010
Cash and cash equivalents at beginning of
year......................................... 14,479 14,539 7,529
--------- --------- ---------
Cash and cash equivalents at end of year...... $ 14,339 $ 14,479 $ 14,539
========= ========= =========
See accompanying notes.
F-5
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1998, 1997 and 1996
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 region, Mid-Continent states and the Gulf of
Mexico. 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. In
1996, the Company commenced international activities with an exploration
project 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, except Barrett Piceance,
LLC in which the Company owns 99 percent of the equity. All significant
intercompany transactions have been eliminated in consolidation.
Reclassifications
Certain reclassifications have been made to 1997 and 1996 amounts to conform
to the 1998 presentation.
Use of estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities at the
date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates. There are many factors, including global events, that may influence
the production, processing, marketing, and valuation of crude oil and natural
gas. A reduction in the valuation of oil and gas properties resulting from
declining prices or production could adversely impact depletion rates and
ceiling test limitations.
Partnerships
The consolidated financial statements include the Company's proportionate
share of the assets, liabilities, revenues and expenses of its oil and gas
partnership interests.
Cash and cash equivalents
Cash in excess of daily requirements is invested in money market accounts
and commercial paper with maturities of three months or less. Such investments
are deemed to be cash equivalents for purposes of the consolidated statements
of cash flows. The carrying amount of cash equivalents approximates fair value
because of the short maturity of those instruments.
Oil and gas properties
The Company utilizes the full cost method of accounting for oil and gas
properties whereby all productive and nonproductive costs paid to third
parties that are incurred in connection with the acquisition, exploration and
development of oil and gas reserves are capitalized. No gains or losses are
recognized upon the sale, conveyance or other disposition of oil and gas
properties except in extraordinary transactions 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 Peru.
Amortizable costs include developmental drilling in progress as well as
estimates of future
F-6
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
development costs of proved reserves, but exclude the costs of unevaluated oil
and gas properties. Oil and gas properties accounted for using the full cost
method of accounting, a method utilized by the Company, are excluded from the
long-lived asset impairment test requirement of Financial Accounting Standards
No. 121, but will continue to be subject to the ceiling test limitations.
Accumulated depreciation is written off as assets are retired. Depletion and
amortization equaled approximately $.92, $.77 and $.59 per Mcfe ($5.49, $4.60
and $3.54 per BOE) during the years ended December 31, 1998, 1997 and 1996,
respectively. A full cost method of accounting ceiling test in 1998 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.
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.
The Company uses both commodity futures contracts and price swaps to hedge
the impact of price fluctuations on a portion of its production and trading
activities. The Company enters into a hedging position for specific
transactions that management deems expose the Company to an unacceptable
market price risk. Price swaps or commodities transactions without
corresponding scheduled physical transactions (scheduled physical transactions
include committed trading activities or production from producing wells) do
not qualify for hedge accounting. The Company classifies these positions as
trading positions and records these instruments at fair value. As of December
31, 1998 the Company did not have any positions that did not qualify for hedge
accounting. Gains and losses are recognized as fair values fluctuate from time
to time compared to cost.
Gains or losses on hedging transactions are deferred until the physical
transaction occurs for financial reporting purposes. Deferred gains and losses
and unrealized gains and losses are evaluated in connection with the physical
transaction underlying the hedge position. Hedging gains or losses
significantly exceeding the price movement of the underlying physical
transaction are recorded in the consolidated statements of income in the
period in which the lack of correlation occurred. Gains or losses on hedging
activities are recorded in the
F-7
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
consolidated statements of income as adjustments of the revenue or cost of the
underlying physical transaction. Hedging transactions are reported as
operating activities in the consolidated statements of cash flows.
Earnings per share
In 1997, the Company adopted Statement of Financial Accounting Standards No.
128, "Earnings Per Share" (SFAS No. 128) effective December 15, 1997. This
pronouncement requires the presentation of the earnings per share ("EPS")
based on the weighted-average number of common shares outstanding (referred to
as basic earnings 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 per share or earnings per share-
assuming dilution). In addition, this pronouncement requires restatement of
earnings per share for all prior periods presented. As a result, the Company's
reported earnings per share for 1996 were restated.
The following data show the amounts used in computing earnings per share and
the effect on income and the weighted average number of shares of dilutive
potential common stock.
For the Years Ended
December 31,
-------------------------
1998 1997 1996
-------- ------- -------
(in thousands)
Income (loss) available to common stockholders.... $(93,743) $29,261 $29,526
======== ======= =======
Weighted average number of common shares used in
basic EPS........................................ 31,756 31,367 28,388
Effect of dilutive securities (see Note 7):
Stock options................................... -- 466 432
Written put option.............................. -- 107 --
-------- ------- -------
Weighted number of common shares and dilutive
potential common stock used in EPS--assuming
dilution......................................... 31,756 31,940 28,820
======== ======= =======
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 No. 133"), "Accounting for
Derivative Instruments and Hedging Activities". SFAS No. 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. SFAS No. 133 is
effective for fiscal years beginning after June 15, 1999 and cannot be applied
retroactively. The Company has not yet quantified the impacts of adopting SFAS
No. 133 on its financial statements and has not determined the timing of or
method of adoption of SFAS No. 133. However, SFAS No. 133 could increase
volatility in earnings and other comprehensive income.
In June 1997, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 130 ("SFAS No. 130"), "Reporting
Comprehensive Income". SFAS No. 130 requires the reporting of comprehensive
income (non-owner changes in equity) and its components in the financial
statements. In 1998, the Company did not have any equity changes from non-
owner sources that would be classified as comprehensive income.
F-8
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
2. RECEIVABLES
1998 1997
-------- --------
(in thousands)
Oil and gas revenue and trading receivables............... $108,969 $ 78,962
Joint interest billings................................... 16,074 22,672
Other accounts receivable................................. 2,755 1,300
-------- --------
$127,798 $102,934
======== ========
The Company's accounts receivable are primarily due from medium size oil and
gas entities in the Rocky Mountain and Gulf Coast regions 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, 1998 and 1997, receivables are
recorded net of allowance for doubtful accounts of $658,000 and $694,000,
respectively.
3. 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.
1998 1997
------- -------
(in thousands)
Natural Gas.................................................. $ 7,195 $ 1,164
Material and Supplies........................................ 1,773 1,415
------- -------
$ 8,968 $ 2,579
======= =======
4. PROPERTY AND EQUIPMENT
1998 1997
---------- ----------
(in thousands)
Oil and gas properties, full cost method:
Unevaluated costs, not being amortized............. $ 57,914 $ 119,737
Evaluated costs.................................... 1,109,822 848,334
Gas gathering systems.............................. 38,799 35,551
Furniture, vehicles and equipment.................... 11,120 10,181
---------- ----------
1,217,655 1,013,803
Less accumulated depreciation, depletion,
amortization and impairment......................... 535,487 266,628
---------- ----------
$ 682,168 $ 747,175
========== ==========
F-9
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
5. UNEVALUATED OIL AND GAS PROPERTY COSTS
Unevaluated oil and gas property costs associated with unevaluated
properties and major development projects consist of the following:
Costs incurred during
------------------------------------
1998 1997 1996 Prior Total
------- ------- ------ ----- -------
(in thousands)
Acquisition costs....................... $19,847 $25,225 $4,188 $ 85 $49,345
Exploration costs....................... 6,309 1,497 763 -- 8,569
------- ------- ------ ---- -------
$26,156 $26,722 $4,951 $ 85 $57,914
======= ======= ====== ==== =======
The unevaluated costs were incurred for projects which are being explored.
The Company anticipates that substantially all unevaluated costs will be
classified as evaluated costs within the next five years.
6. LONG-TERM DEBT
1998 1997
-------- --------
(in thousands)
Line of Credit............................................. $175,000 $100,000
7.55% Senior Notes......................................... 150,000 150,000
Production Payments........................................ 14,399 17,231
-------- --------
Total...................................................... 339,399 267,231
Less: current portion...................................... 5,332 794
-------- --------
Long-term debt............................................. $334,067 $266,437
======== ========
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, 1998 (which was
based on an unaudited June 30, 1998 reserve report), the Company's borrowing
limit was $200 million. The lenders are currently reviewing the December 31,
1998 reserve report to determine current collateral value. At the conclusion
of this review, the borrowing base could change. The Company is required to
pay only interest 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, 1998
the Company's outstanding balance under the line of credit was $175 million
which was accruing interest at an average LIBOR based rate of 5.625 percent.
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 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
F-10
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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 January 1997, the Company assumed a production payment in an acquisition
of properties with a term of three years. Payments of the production payment
liability is funded from production from the properties.
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 1998 are: $5.3 million, $4.4 million, $3.4
million, $176.3 million and nil.
Fair value of financial instruments
The carrying amounts of cash, accounts receivable, accounts payable, and
accrued liabilities approximate fair value due to the short-term maturities of
these assets and liabilities. Based on the variable borrowing rates and re-
pricing terms currently available to the Company for the line of credit, the
carrying amounts of the Company's line of credit and the production payment
liabilities approximate fair value. The fair values of the line of credit and
Notes and production payments were $175.0 million and $158.8 million,
respectively, at December 31, 1998.
7. COMMON STOCK AND OPTIONS
Common Stock
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 conjunction with a property acquisition transaction executed in April
1997, the Company issued a written put option that obligates the Company to
issue 150,000 shares of its common stock to the holder of the option should
the holder elect to exercise this option. The Company will then receive the
holder's one percent interest in a subsidiary of the Company. This option is
exercisable by the holder at any time prior to January 31, 2012. In addition,
the Company has a written call option, exercisable between January 1, 2002 and
January 31, 2012, that gives it the right to purchase the minority interest by
issuing the aforementioned common shares. The put option was recorded to
additional paid-in capital at a fair market value totaling $4.2 million, the
value of the Company's common stock to be issued pursuant to the option. The
fair market value was based on the market price of the Company's common stock
at the date the option was issued.
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.
F-11
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
In June 1996, the Company issued 5.4 million shares of common stock for
$26.375 per share in a public offering. The net proceeds from the issuance of
the shares totaled approximately $134.8 million after deducting issuance costs
and underwriting fees.
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 1990 Plan, a 1994 Plan
and a 1997 Plan, under which the Company's common stock may be granted to
officers and other employees of the Company and subsidiaries. The 1990 Plan
provides for the granting of options to purchase 775,000 shares. The 1994 Plan
as amended, provides for the granting of options to purchase 1,000,000 shares
of the Company's common stock. The 1997 Plan provides for the granting of
options to purchase 1,500,000 shares of the Company's common stock. 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. In 1995, the Company assumed
pre-existing 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.
On January 1, 1996, the Company adopted Statement of Financial Accounting
Standards No. 123, "Accounting for Stock Based Compensation" (SFAS No. 123).
The Company elected to continue to account for these plans under APB Opinion
No. 25, under which no compensation costs are recognized for option grants
that are equal to or greater than the market price at time of grant. If
compensation cost for these plans had been determined consistent with SFAS No.
123, the Company's net income (loss) and earnings (loss) per share would have
been reduced or increased as follows:
For the Year Ended
December 31,
--------------------------
1998 1997 1996
--------- ------- -------
(in thousands)
Net income (loss)
As reported..................................... $ (93,743) $29,261 $29,526
Pro forma....................................... $(101,008) $22,301 $27,277
Net income (loss) per share
As reported
Basic......................................... $ (2.95) $ .93 $ 1.04
Diluted....................................... $ (2.95) $ .92 $ 1.02
Pro forma
Basic......................................... $ (3.18) $ .71 $ .96
Diluted....................................... $ (3.18) $ .70 $ .95
F-12
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Changes in outstanding stock options under these plans are summarized as
follows:
1998 1997 1996
-------------------- -------------------- --------------------
Weighted- Weighted- Weighted-
Number of Average Number of Average Number of Average
Option Exercise Option Exercise Option Exercise
Shares Price Shares Price Shares Price
--------- --------- --------- --------- --------- ---------
Outstanding at beginning
of year................ 2,088,208 $26.29 1,481,559 $22.50 986,546 $16.89
Granted................. 1,253,307 30.10 787,250 33.18 727,600 28.59
Exercised............... (344,139) 16.96 (83,851) 16.48 (230,897) 17.72
Forfeited............... (387,500) 31.15 (96,750) 32.74 (1,690) 23.96
--------- --------- ---------
Outstanding at end of
year................... 2,609,876 28.63 2,088,208 26.29 1,481,559 22.50
========= ========= =========
Options exercisable at
year end............... 959,326 718,633 392,959
Weighted-average fair
value of options
granted during the
year................... $ 17.27 $ 20.69 $ 17.74
The calculated value of stock options granted under these plans, following
calculation methods prescribed by SFAS No. 123, uses the Black-Scholes stock
option pricing model with the following weighted-average assumptions used:
1998 1997 1996
----- ----- -----
Expected option life--years............................. 5.54 5.44 4.90
Risk-free interest rate................................. 5.19% 6.78% 6.44%
Dividend yield.......................................... 0 0 0
Volatility.............................................. 56.87% 57.47% 69.54%
The following table summarizes information about stock options outstanding
at December 31, 1998:
Stock Options Outstanding Stock Options Exercisable
---------------------------------------------- -----------------------------
Weighted-
Number Average Weighted- Number Weighted-
Range of Outstanding at Remaining Average Exercisable at Average
Exercise Prices 12/31/98 Contractual Life Exercise Price 12/31/98 Exercise Price
--------------- -------------- ---------------- -------------- -------------- --------------
$ 5-16 109,501 .2 $12.99 109,501 $12.99
16-21 230,004 2.4 19.06 205,004 18.99
21-30 842,064 5.2 24.58 323,014 24.68
30-43 1,428,307 5.5 33.76 321,807 34.08
--------- --- ------ ------- ------
2,609,876 4.9 28.63 959,326 25.28
========= =======
8. 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 $675,000, $434,000 and $341,000
in 1998, 1997 and 1996, respectively.
Pursuant to a 1995 merger agreement between Plains and the Company, Plains'
employee benefit plans were terminated in 1995 and plan assets were
distributed to the participants. Final distribution of plan assets for Plains'
profit-sharing and 401(k) plans was made to participants during 1996. 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.
F-13
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
9. HEDGING ACTIVITIES
Hedging for Production
The Company uses swap agreements to reduce the effect of natural gas price
volatility on a portion of its natural gas production. The objective of its
hedging activities is to achieve more predictable revenues and cash flows. In
a typical swap agreement, on a monthly basis for the term of the swap
agreement, the Company receives 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, 1998, the Company had in effect outstanding natural gas
swaps associated with its Rocky Mountain natural gas production of 27.8
million MMBtu for the year 1999 and 80.2 million MMBtu for the period of
January 2000 through 2003. Fixed prices associated with these swaps range from
$1.71 to $2.25 per MMBtu for 1999 and from $1.71 to $1.79 per MMBtu for
January 2000 through February 2003.
At year-end 1997, the Company held Rocky Mountain natural gas production
hedging positions of 25.1 million MMBtu for the year 1998 and 104 million
MMBtu for the period of January 1999 through February 2003. Fixed prices for
these swaps ranged between $1.71 and $2.24 per MMBtu for 1998 and between
$1.71 and $1.79 per MMBtu for January 1999 through February 2003.
Hedging gains and losses are recorded when the related gas or oil production
has been produced or delivered or the financial instrument expires. These
gains and losses offset prices that have been received for natural gas and oil
production. Net hedging gains (losses) are included in oil and gas revenues.
For the years ended December 31, 1998, 1997 and 1996, the Company's losses
under its production swap agreements were $0.7 million, $4.3 million and $5.0
million, respectively. Realized hedging losses for 1996 were offset by
approximately $1.2 million relating to a portion of such hedges that were held
by the Company as of December 31, 1995 and did not qualify for hedge
accounting due to a reduced correlation between the index price and the price
to be realized for certain physical gas deliveries. The unrealized hedging
costs were recorded as a liability in 1995.
Hedging for Trading Activities
As of December 31, 1998, the Company had in effect outstanding natural gas
swaps associated with its natural gas trading activities of 275.3 million
MMBtu, 14.0 million MMBtu and 5.5 million MMBtu for 1999, 2000 and 2001,
respectively. Fixed prices for 1999 range between $1.46 and $2.77 per MMBtu.
Hedges for the years 2000 and 2001 are priced at specific pipeline indices.
These swaps are in place to cover fixed price purchases and sales.
At year-end 1997, the Company had in effect outstanding natural gas swaps
associated with its natural gas trading activities of 25.9 million MMBtu for
January through March 1998 with fixed prices of $1.58 to $3.12 per MMBtu and
14.4 million MMBtu for April 1998 through October 1999 with fixed prices of
$1.31 to $1.83 per MMBtu.
F-14
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
10. COMMITMENTS AND CONTINGENCIES
Lease Commitments
The minimum future payments under the terms of operating leases, principally
for office space, are as follows:
(in thousands)
Year ended December 31, 1999.................................. $1,276
2000.......................................................... 1,135
2001.......................................................... 532
2002.......................................................... 139
2003.......................................................... 33
------
$3,115
======
Total minimum future rental payments have not been reduced by $108,000 of
sublease rentals to be received in 1999. Rent expense was $1,282,000,
$1,055,000 and $990,000 for the years ended December 31, 1998, 1997 and 1996,
respectively.
Litigation
The Internal Revenue Service (IRS) has examined the federal tax returns of
Plains, a subsidiary of Barrett Resources Corporation, for pre-merger calendar
years 1991, 1992 and 1993. The IRS issued a "Notice of Deficiency" of $5.3
million together with penalties of $1.1 million, and an undetermined amount of
interest. The IRS Notice of Deficiency resulted primarily from the IRS's
disallowance of certain net operating loss deductions claimed during the
periods under examination. These net operating losses originally had been
incurred by companies that were acquired by Tri-Power Petroleum, Inc. which
was then acquired by Plains in 1986. For years following 1993, the Company has
additional net operating loss carryforwards of approximately $30 million
related to the same acquisition.
The IRS has also examined the federal tax returns of the Company for the
periods ended July 1995, December 1995 and December 1996. The IRS issued a
letter proposing changes to tax for those periods totaling $5.7 million. The
proposed tax changes resulted primarily from the disallowance of net operating
loss and merger related deductions claimed for the periods ended December 1995
and 1996. These net operating losses are the primary issue involved with the
earlier examination of the Plains' tax returns for the calendar years 1991
through 1993.
Management disagrees with the IRS position in each of the examinations. In
management's opinion, the federal tax returns of both Barrett and Plains
reflect the proper federal income tax liability and the existing net operating
loss carryforwards are appropriate as supported by relevant authority. The
Company is vigorously contesting these proposed adjustments and believes its
positions will be substantially sustained. In connection with the audit of tax
years 1991 through 1993, the Company filed a petition on November 29, 1996
with the United States Tax Court requesting a redetermination of the IRS's
Notice of Deficiency. A trial of this matter was held in May 1998, and all
post-trial briefs have been filed. A decision is expected in the first half of
1999.
Pursuant to an August 1996 decision of the United States Court of Appeals
for the District of Columbia Circuit (the "Circuit Court") and subsequent
orders of the FERC, natural gas producers who received reimbursement for
Kansas ad valorem taxes paid in the mid-1980's on top of the then maximum
lawful price for natural gas have been ordered to refund these tax
reimbursements plus interest. In connection with this decision, the Company
has refunded $5.46 million (principal and interest), including an escrowed
refund of $1.21 million attributable to royalty interest owners. As the
royalty interest owners reimburse the Company for their
F-15
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
proportional share 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, 1998, 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 1998, 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.
11. INCOME TAXES
The provision for income taxes consists of the following:
1998 1997 1996
-------- ------- -------
(in thousands)
Current
Federal......................................... $ (175) $ 87 $ 513
State........................................... 90 (231) 794
-------- ------- -------
(85) (144) 1,307
Deferred
Federal......................................... (51,287) 17,345 12,833
State........................................... (4,396) 724 822
-------- ------- -------
(55,683) 18,069 13,655
-------- ------- -------
$(55,768) $17,925 $14,962
======== ======= =======
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:
1998 1997 1996
-------- ------- -------
(in thousands)
Tax by applying the statutory federal income
tax rate to pretax accounting income (loss)... $(52,323) $16,515 $15,571
Increase (decrease) in tax from:
State income taxes........................... (4,306) 493 1,616
Other, net................................... 861 917 (2,225)
-------- ------- -------
$(55,768) $17,925 $14,962
======== ======= =======
F-16
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Long-term deferred tax assets (liabilities) are comprised of the following
at December 31, 1998 and 1997:
1998 1997
-------- ---------
(in thousands)
Deferred tax assets:
Allowance for losses................................. $ 40 $ --
Partnership activities............................... 6,592 8,549
Loss carryforwards and other......................... 64,060 44,400
-------- ---------
Gross deferred tax assets.......................... 70,692 52,949
Deferred tax liabilities:
Depreciation, depletion and amortization............. (80,381) (120,504)
Capitalized interest on other assets................. (305) (229)
-------- ---------
Gross deferred tax liabilities..................... (80,686) (120,733)
-------- ---------
Net deferred tax liability............................. (9,994) (67,784)
Valuation allowance.................................... (3,300) (1,193)
-------- ---------
$(13,294) $ (68,977)
======== =========
Valuation allowances of $3.3 million and $1.2 million were provided at
December 31, 1998 and 1997, respectively, based on carryforward amounts which
may not be utilized before expiration.
The Company has net operating loss carryforwards available totaling $163.3
million, which expire in the years 1999 through 2010. 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 $15,831,000 per
year for the Company. Portions of the above limitations which are not used
each year may be carried forward to future years.
12. Supplemental Cash Flow Schedules and Information
1998 1997 1996
------- ------ ------
(in thousands)
Cash paid during years
Income tax......................................... $ 130 $ 824 $ 416
Interest........................................... 20,384 8,079 3,809
Supplemental information of noncash investing and
financing activities:
Issuance of common stock exchanged for treasury
shares in cashless option transactions............ $ 233 $ 207 $ 527
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 is a 15 percent interest in an oil and gas license in the
area denominated as Block 67 located in the Republic of Peru.
During 1998, the Company's production payment obligations were reduced by
certain tax credit benefits of $2.2 million directly attributed to the
properties burdened by the production payment and received by the holder of
the production payment liability.
F-17
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.
During 1996, the Company issued 50,000 shares of common stock with a market
value of $1.9 million and exchanged certain oil and gas properties plus $13.4
million cash for oil and gas properties located in the Uinta Basin of Utah. In
addition, with respect to acquisitions of various oil and gas and related
properties located in the Piceance Basin of Colorado in 1996, the Company
issued 585,661 shares of common stock valued at $16.5 million and recognized
additional deferred taxes of $13.7 million, for the difference between the tax
basis and book basis of the properties acquired.
13. RELATED PARTIES
During 1998, 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.
In April 1996, the Company acquired for $2.7 million from Zenith Drilling
Corporation ("Zenith") all of Zenith's oil and gas interests located in the
Piceance Basin of Colorado. In addition, the Company acquired all the stock of
Grand Valley Corporation ("GVC") in exchange for 350,000 shares of the
Company's common stock. The sole asset of GVC was an approximate 10% interest
in the Grand Valley Gathering System. The Company previously owned interests
in and is the operator of both the gathering system and the gas and oil assets
in which it acquired interests as a result of these transactions.
A member of the Company's Board of Directors owns 89% of Zenith and, at the
time of the GVC transaction, was a director of GVC and owned 10% of GVC. Due
to these relationships, the terms of these transactions with Zenith and GVC
were negotiated on behalf of the Company by a Special Committee of the Board
of Directors of the Company, consisting of four independent outside directors.
The Company also obtained an opinion from an investment banking firm that the
terms of these transactions were fair to the Company.
During the year ended December 31, 1996, Zenith was billed by the Company as
operator, approximately, $77,000 for Zenith's portion of lease operating
expenses and development costs in certain leases operated by the Company.
Also, as a result of Zenith's working interest in those leases, Zenith
received approximately $448,000 as its share of revenues for 1996.
F-18
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
14. QUARTERLY INFORMATION (UNAUDITED)
Three Months Ended
----------------------------------------
3/31/98 6/30/98 9/30/98 12/31/98
--------- --------- --------- ----------
(in thousands, except per share data)
1998
Net revenues.............. $ 130,687 $ 129,658 $ 147,072 $ 213,890
Gross margin(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 per share:
Basic................... .20 .08 .06 (3.24)
Assuming dilution....... .19 .08 .06 (3.24)
--------
(1) In the quarter ended December 31, 1998, a pre-tax impairment
charge of $168.3 million was recorded. (see Note 1).
Three Months Ended
----------------------------------------
3/31/97 6/30/97 9/30/97 12/31/97
--------- --------- --------- ----------
(in thousands, except per share data)
1997
Net revenues.............. $ 75,768 $ 70,496 $ 88,660 $ 145,049
Gross margin.............. 23,404 15,621 16,774 28,663
Income from operations.... 15,988 7,077 7,464 16,657
Net income................ 9,913 4,387 4,629 10,332
Net income per share:
Basic................... .32 .14 .15 .33
Assuming dilution....... .31 .14 .14 .32
F-19
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
15. Business Segment Information
The Company operates principally in two business segments: natural gas
trading and oil and gas exploitation and production. 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:
Natural Gas Oil & Gas Segment Corporation &
Trading E&P Total Unallocated Consolidated
----------- --------- --------- ------------- ------------
(in thousands)
1998
Revenues................ $412,982 $ 206,338 $ 619,320 $ 5,430 $ 624,750
Interest Income......... 0 0 0 649 649
-------- --------- --------- -------- ---------
Total Revenues........ 412,982 206,338 619,320 6,079 625,399
DD&A.................... 0 97,957 97,957 4,166 102,123
Impairment.............. 0 168,304 168,304 0 168,304
Profit (loss)........... 13,782 (118,549) (104,767) (44,744) (149,511)
Assets.................. 0 676,228 676,228 162,651 838,879
Expenditures for
assets................. 0 202,912 202,912 2,867 205,779
1997
Revenues................ $171,140 $ 207,914 $ 379,054 $ 1,973 $ 381,027
Interest Income......... 0 0 0 1,573 1,573
-------- --------- --------- -------- ---------
Total Revenues........ 171,140 207,914 379,054 3,546 382,600
DD&A.................... 0 69,056 69,056 3,333 72,389
Profit (loss)........... 5,044 80,955 85,999 (38,812) 47,186
Assets.................. 0 738,952 738,952 133,749 872,701
Expenditures for
assets................. 0 315,980 315,980 15,173 331,153
1996
Revenues................ $ 46,862 $ 151,737 $ 198,599 $ 3,213 $ 201,812
Interest Income......... 0 0 0 760 760
-------- --------- --------- -------- ---------
Total Revenues........ 46,862 151,737 198,599 3,973 202,572
DD&A.................... 0 42,583 42,583 3,192 45,775
Profit (loss)........... 2,241 61,837 64,078 (19,590) 44,488
Assets.................. 0 483,186 483,186 93,759 576,945
Expenditures for
assets................. 0 214,236 214,236 18,523 232,759
The Company's revenues are derived in the United States. The Company's long-
lived assets are located in the United States.
F-20
SUPPLEMENTAL OIL AND GAS INFORMATION
The following information, pertaining to the Company's oil and gas producing
activities for the years ended December 31, 1998, 1997 and 1996, 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 1998, one natural gas purchaser accounted for four percent of the
Company's total revenue (12 percent of oil and gas revenues). Sales of gas to
this same purchaser represented 8 percent and 11 percent of total revenues in
1997 and 1996, 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:
1998 1997 1996
-------- -------- --------
(in thousands)
Acquisition of evaluated properties............. $ 3,529 $ 45,148 $ 68,157
Acquisition of unevaluated properties:
United States................................. 32,127 63,643 45,051
Peru.......................................... 12,089 10,597 1,229
Exploration costs:
United States................................. 59,331 118,779 32,086
Peru.......................................... 15,196 -- --
Development costs............................... 84,577 93,701 69,651
Other, principally proceeds from mineral
conveyances.................................... (7,185) (14,253) (1,948)
-------- -------- --------
Total additions to oil and gas properties....... $199,664 $317,615 $214,226
======== ======== ========
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 $3.2 million in 1998 for various
supporting production facilities consisting principally of natural gas
gathering systems and processing plants. Production facility expenditures for
1997 and 1996 were $3.9 million and $15.1 million.
Oil And Gas Reserves (Unaudited)
The following reserve related information for 1998 is based on estimates
prepared by the Company. All of the Company's reserves are located in the
United States. With the exception of the Company's coalbed methane reserves in
Wyoming, the 1998 reserve information for the Company was reviewed by Ryder
Scott, an independent reservoir engineer. The 1998 reserve information for the
Company's coalbed methane properties located in the Powder River Basin was
audited by Netherland, Sewell & Associates, Inc., an independent reservoir
engineer. The Company's 1997 and 1996 reserves were prepared by the Company
and reviewed by Ryder Scott as of December 31, 1997 and December 31, 1996.
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
1998 1997 1996
--------------------- --------------------- ---------------------
Oil (MBbl) Gas (Mmcf) Oil (MBbl) Gas (Mmcf) Oil (MBbl) Gas (Mmcf)
---------- ---------- ---------- ---------- ---------- ----------
(in thousands)
Proved developed and
undeveloped reserves:
Beginning of year...... 18,651 851,244 23,231 674,893 12,967 513,531
Revisions of previous
estimates............. (7,437) (55,343) (11,651) (54,945) (210) (778)
Purchase of minerals in
place................. -- 3,520 1,910 52,303 6,628 95,914
Extensions and
discoveries........... 746 217,870 8,287 258,520 6,029 127,547
Production............. (2,033) (94,893) (2,235) (76,625) (1,913) (60,883)
Sale of minerals in
place................. (277) (9,968) (891) (2,902) (270) (438)
------ ------- ------- ------- ------ -------
End of year............ 9,650 912,430 18,651 851,244 23,231 674,893
====== ======= ======= ======= ====== =======
Proved developed
reserves:
Beginning of year...... 10,751 553,787 15,773 511,645 11,669 419,672
====== ======= ======= ======= ====== =======
End of year............ 6,212 543,068 10,751 553,787 15,773 511,645
====== ======= ======= ======= ====== =======
Standardized Measure of Discounted Future Net Cash Flows
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.
1998 1997 1996
---------- ---------- ----------
(in thousands)
Future cash inflows....................... $1,927,074 $2,158,461 $2,893,217
Future production costs................... (570,923) (608,123) (773,233)
Future development costs.................. (238,169) (250,467) (152,141)
Future income tax expenses................ (187,113) (306,946) (628,901)
---------- ---------- ----------
Future net cash flows................... 930,869 992,925 1,338,942
10% annual discount for estimated timing
of cash flows............................ (400,221) (428,794) (574,139)
---------- ---------- ----------
Standardized measure of discounted future
net cash flows........................... $ 530,648 $ 564,131 $ 764,803
========== ========== ==========
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
The following are the principal sources of changes in the standardized
measure of discounted future net cash flows:
1998 1997 1996
--------- --------- ---------
(in thousands)
Net change in sales price and production
costs....................................... $(103,105) $(457,246) $ 415,937
Changes in estimated future development
costs....................................... 43,383 43,391 16,288
Sales and transfers of oil and gas produced,
net of production costs..................... (146,875) (152,536) (110,341)
Net change due to extensions and
discoveries................................. 115,145 195,992 230,797
Net change due to purchases and sales of
minerals in place........................... (6,980) 32,153 167,235
Net change due to revisions in quantities.... (76,985) (122,656) (41,486)
Net change in income taxes................... 68,083 183,901 (249,836)
Accretion of discount........................ 63,163 69,881 28,053
Other, principally revisions in estimates of
timing of production........................ 10,688 6,448 (1,718)
--------- --------- ---------
Net changes.................................. (33,483) (200,672) 454,929
Balance, beginning of year................... 564,131 764,803 309,874
--------- --------- ---------
Balance, end of year......................... $ 530,648 $ 564,131 $ 764,803
========= ========= =========
The December 31, 1998 weighted average prices utilized for purposes of
estimating the Company's proved reserves and future net revenues were $9.35 per
barrel of oil and $2.01 per Mcf of natural gas.
F-23
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 17, 1999 /s/ William J. Barrett
By: _________________________________
William J. Barrett
Chairman of the Board, and Chief
Executive Officer
Date: March 17, 1999 /s/ John F. Keller
By: _________________________________
John F. Keller
Chief Financial Officer, and
Principal Financial and
Accounting Officer
Signature Title Date
--------- ----- ----
/s/ William J. Barrett Director March 17, 1999
______________________________________
William J. Barrett
/s/ C. Robert Buford Director March 17, 1999
______________________________________
C. Robert Buford
/s/ Derrill Cody Director March 17, 1999
______________________________________
Derrill Cody
/s/ James M. Fitzgibbons Director March 17, 1999
______________________________________
James M. Fitzgibbons
/s/ William W. Grant, III Director March 17, 1999
______________________________________
William W. Grant, III
/s/ John F. Keller Director March 17, 1999
______________________________________
John F. Keller
/s/ A. Ralph Reed Director March 17, 1999
______________________________________
A. Ralph Reed
/s/ James T. Rodgers Director March 17, 1999
______________________________________
James T. Rodgers
/s/ Philippe S.E. Schreiber Director March 17, 1999
______________________________________
Philippe S.E. Schreiber
BARRETT RESOURCES CORPORATION
ANNUAL REPORT ON FORM 10-K
For The Year Ended December 31, 1998
EXHIBIT INDEX
Exhibit Description
------- -----------
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.
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 as of August 5, 1997 between
Barrett and BankBoston, N.A.
4.2 Revised Form of Indenture between the Company and Bankers Trust
Company, as trustee, with respect to Senior Notes including specimen
of 7.55% Senior Notes is incorporated by reference from Exhibit 4.1 to
the Company's Amendment No. 1 to Registration Statement on Form S-3
filed February 10, 1997, File No. 333-19363.
4.3 Form of Indenture between the Registrant and Bankers Trust Company, as
trustee, with respect to Debt Securities is incorporated by reference
from Exhibit 4.2 of Registrant's Registration Statement on Form S-3
filed May 6, 1998 (File No. 333-51985).
10.1 Non-Qualified Stock Option Plan Of Barrett Resources Corporation is
incorporated by reference from Registrant's Registration Statement on
Form S-8 dated November 15, 1989.
10.2 Registrant's 1990 Stock Option Plan, as amended, is incorporated by
reference from the Registrant's Registration Statement on Form S-8
dated March 15, 1995.
10.3 Registrant's Non-Discretionary Stock Option, as amended, is
incorporated by reference from Exhibit 99.2 of the Registrant's Proxy
Statement dated April 24, 1997.
10.4 Registrant's 1994 Stock Option Plan, as amended, is incorporated by
reference from the Registrant's Registration Statement on Form S-8
dated March 15, 1995.
10.5 Registrant's 1997 Stock Option Plan is incorporated by reference from
Exhibit 99.1 of the Registrant's Proxy Statement dated April 24, 1997.
10.6A Gas Purchase Contract, No. P-1090, dated April 20, 1984, as amended,
between Plains and KN Energy, Inc. is incorporated by reference from
Plains Petroleum Company's Registration Statement on Form 10 dated
August 21, 1985.
Exhibit Description
------- -----------
10.6B Letter Agreement dated January 11, 1996, amending the Gas Purchase
Contract, No. P-1090, dated April 20, 1984, between Plains and KN
Energy, Inc. is incorporated by reference from Exhibit 10.5B of the
Registrant's Annual Report on Form 10-K for the year ended December
31, 1996.
10.7A 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.
10.7B 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.
10.7C 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.
10.7D 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.
10.7E 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.
10.8A Severance Protection Agreement dated February 6, 1998 between
Registrant and William J. Barrett is incorporated by reference from
Exhibit 10.8 to Registrant's Annual Report on Form 10-K for the year
ended December 31, 1997.
10.8B Amendment No. 1 to Severance Protection Agreement dated November 19,
1998 between Registrant and William J. Barrett.
10.9A 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.
10.9B 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.
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.