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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, 1996
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, 80202
TOWER 3, SUITE 1000 (ZIP CODE)
DENVER, COLORADO
(ADDRESS OF PRINCIPAL EXECUTIVE
OFFICES)
(303) 572-3900
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
(None)
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
COMMON STOCK (PAR VALUE $.01 PER SHARE)
TITLE OF CLASS
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes [X] No [_]
Indicate by check mark if there are no delinquent filers to disclose herein
pursuant to Item 405 of Regulation S-K, and there will not be any delinquent
filers to disclose, to the best of registrant's knowledge, in definitive proxy
or information statements incorporated by reference in Part III of this Form
10-K or any amendment to this Form 10-K. [_]
As of March 20, 1997, the Registrant had 31,340,876 common shares
outstanding, and the aggregate market value of the common shares held by non-
affiliates was approximately $996,572,776. This calculation is based upon the
closing sale price of $34.00 per share for the stock on March 20, 1997.
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TABLE OF CONTENTS
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ITEM PAGE
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PART I
1 and 2. Business and Properties...................................... 1
3. Legal Proceedings............................................ 17
4. Submission of Matters to Vote of Security Holders............ 18
PART II
Market for the Registrants common stock and Related Security
5. Holders Matters.............................................. 19
6. Selected Financial Data...................................... 19
Managements Discussion and Analysis of Financial Condition
7. and Results of Operations.................................... 19
8. Financial Statements and Supplemental Data................... 24
Changes in and Disagreements with Accountants on Accounting
9. and Financial Disclosures.................................... 24
PART III
10. Directors and Executive Officers of the Company.............. 25
11. Executive Compensation....................................... 29
Security Ownership of Certain Beneficial Owners and
12. Management................................................... 33
13. Certain Relationships and Related Transactions............... 34
PART IV
14. Exhibits, Financial Schedules, and Reports on Form 8-K....... 35
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PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
Barrett Resources Corporation (the "Company" or "Barrett", which reference
shall include the Company's wholly owned subsidiaries) was incorporated in
December 1980 as an oil and gas company under the name AIMEXCO Inc. and became
publicly owned with a $5.8 million common stock offering in May 1981. In
December 1983, AIMEXCO acquired all the common stock of Barrett Energy
Company, which owned a number of oil and gas properties, in exchange for 71.5
percent of the common stock of AIMEXCO that was outstanding after the
transaction. In January 1984, the Company changed its name to Barrett
Resources Corporation.
In November 1985, the Company acquired Excel Energy Corporation, a Utah
corporation that owned oil and gas interests, in exchange for approximately
1,425,000 shares of the Companys 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 Companys 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.
Effective July 1, 1993, the Company sold substantially all its interests in
oil and gas properties, a gas processing plant and the related gas gathering
system located in the Wattenberg Field of Colorado. The adjusted sales price,
net of selling expenses, was approximately $14.4 million.
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, 1996, the Company's estimated proved reserves were
814.3 Bcfe (83% natural gas and 17% crude oil) with an implied reserve life of
11.3 years based on 1996 total production of 72 Bcfe.
The Company concentrates its activities in core areas in which it has
accumulated detailed geologic knowledge and developed significant management
expertise. The Company continues to build on its interests in the Piceance
Basin in northwestern Colorado, the Uinta Basin of northeastern Utah, the
Anadarko and Arkoma Basins in Oklahoma, the Wind River Basin in Wyoming and
the Gulf of Mexico. The Company also has significant interests in the Hugoton
Embayment in Kansas and Oklahoma, the Permian Basin in Texas and New Mexico,
and the Powder River Basin in Wyoming. At December 31, 1996, these principal
areas of focus represented approximately 94% of the Company's estimated proved
reserves.
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The Company continues to experience significant growth in its proved
reserves, production volumes, revenues and cash flow, particularly in the Wind
River, Piceance, Anadarko, Arkoma and Uinta Basins. The Company currently is
pursuing development projects in the Wind River, Piceance, Anadarko, Arkoma
and Uinta Basins, and exploration projects in the Wind River and Anadarko
Basins, the Gulf of Mexico and the Republic of Peru. The Company's average net
daily production increased to 198 MMcfe for the year ended December 31, 1996
from 159 MMcfe for the year ended December 31, 1995.
As of December 31, 1996, the Company owned interests in 2,106 producing
wells and operated 1,310 of these wells. These operated wells contributed
approximately 82% of Barrett's natural gas and oil production for the year
ended December 31, 1996. The Company also owns interests in and operates a
natural gas gathering system, a 27-mile pipeline and a natural gas processing
plant in the Piceance Basin.
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 181 full time employees, including 12 officers
(five of whom are geologists and two of whom are petroleum engineers), 14
geologists, six geophysicists, 12 engineers, one environmental manager, 11
landmen, four district managers, one operations superintendent, and
administrative, clerical, accounting and field operations personnel, none of
whom is represented by organized labor unions.
The Company's executive offices are located at 1515 Arapahoe Street, Tower
3, Suite 1000, Denver, Colorado 80202, and its telephone number is (303) 572-
3900. In addition, the Company maintains regional offices in Tulsa, Oklahoma
and Houston, Texas.
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CORE AREAS OF ACTIVITY
The following table sets forth certain information concerning these core
areas of activity:
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AVERAGE DAILY
ESTIMATED PROVED ESTIMATED PROVED PRODUCTION FOR
RESERVES AT RESERVES AT YEAR ENDED
DECEMBER 31, DECEMBER 31, DECEMBER 31,
BASIN OR FIELD 1995 1996 1996
-------------- ---------------- ---------------- --------------
(BCFE) (BCFE) (MMCFE)
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Rocky Mountain Region
Wind River.............. 88.1 95.8 42.2
Piceance................ 119.1 201.7 28.5
Powder River............ 30.0 32.0 15.6
Green River............. 12.5 14.8 5.4
Uinta................... 4.2 92.2 3.9
Mid-Continent Region
Arkoma.................. 27.4 26.7 12.9
Anadarko................ 33.7 46.2 21.6
Hugoton Embayment....... 200.7 211.9 42.7
Permian................. 39.1 31.8 12.9
Gulf of Mexico Region..... 8.7 23.8 5.9
Other Natural Gas and Oil
Activities(1)............ 27.8 37.4 6.7
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Total................. 591.3 814.3 198.3
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(1) Reserves primarily located in northeastern Colorado, the Paradox Basin
(Utah and Colorado) and Nevada.
ROCKY MOUNTAIN REGION
WIND RIVER BASIN. In 1994, following its major natural gas discovery in the
Cave Gulch Field, the Company began a focused exploration program in the Wind
River Basin of Wyoming, particularly along the Owl Creek Thrust fault.
Cave Gulch Field. In August 1994, the Company drilled the Barrett #1 Cave
Gulch Federal Unit well and discovered a significant natural gas field in the
Fort Union and Lance Sandstones below the Owl Creek Thrust. The Company
currently owns a 94% working interest in the Cave Gulch Federal Unit. Since
August 1994, the Company has acquired additional interests in the area and
currently owns working interests ranging from 5% to 100% in 16,011 gross
leasehold acres, constituting 9,590 net leasehold acres, in the Cave Gulch
area. Combined daily production for the Cave Gulch Field net to the Company's
interest at December 31, 1996 was 50 MMcf of natural gas and 171 barrels of
oil.
In February 1997, the Company reached a total depth of 19,106 feet on the
Cave Gulch #16 deep test well, which was drilled to test the deeper Frontier,
Muddy, Lakota, Morrison and Sundance Formations. The well encountered these
formations at least 1,100 feet structurally updip (high) to the productive
zones in four offset gas wells, three of which have produced from the Frontier
Formation and the fourth of which has produced from the Muddy, Lakota,
Morrison and Sundance Formations. The Company has run production casing and
will begin testing the well in April 1997. The Company owns an 85.2% working
interest in this well, subject to reduction to 84.9% after payout.
During 1996, the Company had planned to drill up to 10 wells in the Cave
Gulch Field. However, the Bureau of Land Management (the "BLM") determined
that an environmental impact statement ("EIS") in the greater Cave Gulch area
would be required to assess future development proposals from the Company and
other
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operators in the area. As a result, the Company drilled four Lance wells in
1996, and began drilling the Barrett #16 Cave Gulch deep test. The BLM has
indicated that the EIS will be completed in August 1997, but there is no
assurance that this will be the case. No additional drilling activity in this
area for 1997 has been approved by the BLM, and the BLM has indicated that no
drilling activity will be approved prior to the completion of the EIS. The
Company will, however, be permitted to recomplete wells. In the event that the
BLM allows drilling activity in this area pending the completion of the EIS,
the Company will proceed accordingly.
Through December 31, 1996, the Company had drilled 14 wells in the Cave
Gulch area to test the Lance and Fort Union Sandstones. Five of these wells
are producing, two are shut in due to line pressures, four are shut in due to
limited pipeline capacity, two are being completed and one is waiting on
completion. Two interstate pipelines serve the Cave Gulch area, and both have
proposed expansions to increase their take-away capacity. The Company is
supporting these expansion proposals with transportation volume commitments.
Both pipeline expansions are scheduled to be completed by mid-1997. In an
effort to increase production, the Company has installed a temporary gas
conditioning facility that will allow the Company to remove liquids from the
portion of the gas that currently does not meet pipeline specifications and to
compress gas prior to entering one of the interstate pipelines. By the end of
March 1997, this temporary facility enabled the Company to increase its
natural gas production in the Cave Gulch area to approximately 71.3 MMcf per
day.
Stone Cabin Project. In the second quarter of 1996, the Company acquired a
100% working interest in 9,754 acres in the Wallace Creek Unit and adjacent
land. This acreage, in the Company's Stone Cabin Project, is along the south
flank of the Wind River Basin. In July 1996, the Company began an exploration
and development program to target the Upper Cretaceous Muddy Sandstone and the
Raderville Sandstone of the Lower Cody Shale Formation. The Company has
drilled four wells in this program, two of which are producing. The Company is
testing the other two wells to determine if they are capable of commercial
production. The Company plans to drill up to five wells in 1997 to further
develop the Muddy Formation. The BLM is imposing restrictions on winter
drilling activities, which will delay drilling until April 1997.
Owl Creek Thrust. The Company continues to evaluate additional exploration
prospects in the Owl Creek Thrust and central Wind River Basin. The Company
has 82,406 gross and 76,681 net acres under lease in portions of the Owl Creek
Thrust and central Wind River Basin outside of the Cave Gulch area. In 1997,
the Company plans to drill three exploratory test wells along the Owl Creek
Thrust.
At December 31, 1996, the Wind River Basin represented 12% of the Company's
estimated proved reserves, and 21% of the Company's total production. In 1997,
6% of Barrett's capital expenditure budget is planned to be spent in the Wind
River Basin for development, leasehold acquisition, seismic surveys and
exploration, including participating in drilling up to 27 wells.
PICEANCE BASIN. The Piceance Basin of northwestern Colorado is a core
operating area for the Company and will continue to be very prominent in the
Company's capital spending plans. The Company's activities in the Piceance
Basin are conducted primarily in three fields: Parachute, Rulison and Grand
Valley.
The Company's drilling activities in the Piceance Basin primarily target the
lenticular sandstones of the Williams Fork Formation of the Mesaverde Group.
These sandstone reservoirs overlie the blanket sandstones of the Iles
Formation in the basal Mesaverde. Barrett drilled its first well in the
Piceance Basin in 1984. At December 31, 1996, the Company owned interests in
297 wells, and operated 285 of these wells in the Piceance Basin.
In 1996, the Company completed the acquisition of working interests in the
Piceance Basin from some of the Company's former joint working interest owners
in this project, and the Company's average working interest in properties in
this area increased from approximately 29% to approximately 62%. The Company
paid an aggregate of $28.9 million cash and issued an aggregate of 585,661
shares of common stock to acquire these interests.
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In February 1995, the Company received approval for 40-acre well density by
the Colorado Oil and Gas Conservation Commission (the "Colorado Commission")
with respect to 81 640-acre sections in the Parachute, Rulison and Grand
Valley Fields, and has commenced an active development drilling program on 40-
acre sites in the same Fields. In November 1996, the Company requested and
received approval from the Colorado Commission for two four-well pilot
drilling programs on 20-acre well density. These two pilot programs are
located in the Rulison and Grand Valley Fields and are currently drilling. The
Company will evaluate the engineering and geologic data resulting from these
pilot programs and determine whether to apply for approval for 20-acre well
density on all or selected acreage in the Piceance Basin in the future. There
is no assurance that the Colorado Commission will approve any additional
requests for 20-acre well density.
At December 31, 1996, this Basin represented 25% of the Company's estimated
proved reserves, and represented 14% of the Company's total production. The
Company currently is continuously operating three drilling rigs in the Basin,
with a fourth rig to be added in the second quarter 1997. In 1997, the Company
intends to spend 15% of its capital expenditure budget in the Piceance Basin
for development and exploration, including participating in drilling up to 101
wells and 20 recompletions.
Grand Valley Gathering System. In 1985, the Company's wholly-owned
subsidiary, Bargath, Inc., designed and constructed a gathering system in the
Grand Valley Field to transport natural gas from certain of the Company's
wells to Questar Pipeline Corporation's interstate pipeline. This gathering
system subsequently has been expanded to approximately 150 miles, and a 16-
inch, 27-mile pipeline has been added. Through three acquisitions in 1996, the
Company increased its ownership interest in this system to approximately 62%.
As of December 31, 1996, the Grand Valley Gathering System was connected to
220 producing natural gas wells in the Piceance Basin. The system now has the
flexibility to deliver natural gas to three interstate pipelines, which are
owned respectively by Questar Pipeline Company, Northwest Pipeline Corporation
and Colorado Interstate Gas Company, and one intrastate pipeline owned by
Public Service Company of Colorado and K N Energy, Inc. ("K N"). In December
1994, the Company completed the construction of a 90,000 MMBtu per day natural
gas processing plant to extract liquid hydrocarbons from the natural gas
stream. Depending on the take-away capacity from time to time of these four
pipeline systems, the gathering system has the capability of delivering
approximately 90,000 MMBtu of natural gas per day.
UINTA BASIN. As an extension of its Piceance Basin operations, in 1995, the
Company entered the Uinta Basin of Duchesne and Uintah Counties, in
northeastern Utah. The Uinta Basin is separated from the Piceance Basin by the
Douglas Creek Arch.
Brundage Canyon Field. Beginning in December 1995, the Company made
acquisitions totaling $5.2 million in the Brundage Canyon Field. As a result
of these acquisitions and new drilling, the Company currently owns working
interests ranging from 75 to 100% in 31 producing wells, a gathering and
transmission system, and 36,500 gross acres, covering approximately 35,500 net
acres, all of which are on the Ute Indian Reservation. Wells in this Field
produce primarily from multiple sandstone reservoirs of the lower Green River
Formation at depths averaging 5,500 feet. As of December 31, 1996, these wells
produced approximately 800 barrels of black wax crude oil per day.
The Company plans extensive work in this Field during 1997, including a 24-
well program to develop infill and field extension locations, a 40-acre pilot
waterflood project, and recompletions and workovers of existing wells to test
the viability of shallower horizons for potential future development.
Altamont-Bluebell Project. The Altamont-Bluebell Field complex, which
includes the Cedar Rim area, covers a large portion of the northern Uinta
Basin. In 1996, the Company acquired through a number of transactions working
interests ranging from 25 to 100% in 159 producing wells and in approximately
131,500 gross and 82,700 net acres of leasehold interests. The largest of
these acquisitions was completed on November 1, 1996 when the Company acquired
producing and non-producing natural gas and oil properties in the Altamont-
Bluebell Field. The effective date of the acquisition of a significant portion
of these properties is January 1, 1997. The purchase included 120 operated
wells with an average working interest of 80%, together with approximately
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100,000 gross and 72,000 net acres of leasehold interests. The total purchase
price for the November 1996 acquisition was approximately $32 million,
including approximately $14 million cash, 50,000 shares of the Company's
common stock, and certain non-strategic producing properties owned by the
Company. The Company's production in this area is predominantly from the
multiple sandstone reservoirs in the Wasatch Formation which are found at an
average depth of 12,000 feet. Also productive in the Field are the upper,
lower, and middle portions of the Green River Formation at depths of 5,000 to
7,000 feet.
In January 1997, the Company acquired additional interests in this Field for
$3.5 million. These interests consist of 16 non-operated wells with average
working interests of 42%, together with approximately 10,000 gross and 4,600
net acres of leasehold interests.
At December 31, 1996, the Uinta Basin represented 11% of the Company's
estimated proved reserves, and 2% of the Company's total production. In 1997,
the Company plans a 30 well recompletion/restimulation program and the
drilling of 34 development and extension wells in the Uinta Basin.
Expenditures for this activity in 1997 are expected to total $26 million, or
9% of the Company's capital expenditure budget. With this activity the Company
plans to test the potential in the lower, middle, and upper Green River
Formation both from behind pipe in existing wells and in new infill locations.
POWDER RIVER BASIN. The Powder River Basin in Wyoming is primarily an oil
province, with production from Cretaceous and Permian-age Formations. One of
the reservoir targets in this area is the Permian Minnelusa Formation. This
Basin contributes approximately 44% of the Company's daily oil production.
The Company has initiated or is planning the use of alkaline surfactant
polymer ("ASP") technology to chemically enhance oil recovery in a number of
fields. The Company also is using 3-D seismic technology to identify
development opportunities in this area. Two exploration wells targeting the
Minnelusa and Shannon Formations, respectively, were drilled and abandoned in
the first quarter of 1997.
At December 31, 1996, this Basin represented 4% of the Company's estimated
proved reserves and 8% of the Company's total production. In 1997, the Company
intends to spend 1% of its capital expenditure budget for development
utilizing 3-D seismic technology, enhanced recovery projects and exploration
opportunities in the Powder River Basin, including participating in drilling
up to 36 wells.
GREATER GREEN RIVER BASIN. The Company owns leasehold interests within the
greater Green River Basin, primarily in the West Side Canal Field and in the
Wyoming Overthrust Trend. The Company participated in two wells in the Green
River Basin in 1996. At December 31, 1996, this Basin represented 2% of the
Company's estimated proved reserves, and 3% of the Company's total production.
In 1997, the Company intends to spend approximately $4 million for capital
expenditures in drilling up to nine wells and recompleting three additional
wells in the Green River Basin.
MID-CONTINENT REGION
ARKOMA BASIN. Due to the complex structure and overlapping nature of the
rock formations, the Company has been using and will continue to use 3-D
seismic surveys extensively in the Arkoma Basin in Oklahoma. In 1996, Barrett
participated in the drilling of 15 wells in four areas of the Arkoma Basin in
Oklahoma: South Panola 3-D area, Limestone Ridge area, Wilburton Field, and
Alderson area.
At December 31, 1996, this Basin represented 3% of the Company's estimated
proved reserves, and 6% of the Company's total production. In 1997, the
Company intends to spend 3% of its capital expenditure budget for drilling in
the Arkoma Basin, including participating in drilling up to 10 wells, together
with land and seismic surveys.
ANADARKO BASIN. Since 1993, the Anadarko Basin in southwestern Oklahoma has
been one of the Company's most active drilling areas. In 1996, the Company
participated in the drilling of 58 wells with working
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interests ranging from 1.5 to 100% after payout. While staying active in the
Strong City Red Fork Play, the Company has become increasingly active in the
Mountain Front Granite Wash and Springer plays.
At December 31, 1996, this Basin represented 6% of the Company's estimated
proved reserves, and 11% of the Company's total production. The Company plans
to spend 10% of its 1997 capital expenditure budget in the Anadarko Basin for
development and exploration drilling, including participating in drilling up
to 71 wells, together with leasehold acquisitions and seismic surveys as
currently planned.
HUGOTON EMBAYMENT. The largest single producing area for the Company is the
Hugoton Embayment, which is one of the largest natural gas producing areas in
the United States, located in southwest Kansas, the Oklahoma panhandle and the
Texas panhandle. The Company produces natural gas from three fields in the
Hugoton Embayment: the Hugoton, the Guymon-Hugoton and Panoma Fields.
Hugoton and Guymon-Hugoton Fields. In the Hugoton and Guymon-Hugoton Fields,
the Company has working interests in 364 gross wells and operates 312 of them.
The Hugoton and the Guymon-Hugoton Fields produce from the Chase Formation.
Six wells were drilled in the Hugoton Field in 1996, all of which have been
placed on production.
Panoma Field. Panoma is the field designation for natural gas produced from
the Council Grove Formation, a formation beneath the Chase Formation. The
Council Grove Formation has similar reservoir rocks as the Chase Formation.
However, the productive limits are not as extensive. Presently, the Company
has a working interest in 54 gross Panoma wells and operates 50 of those
wells, including one well drilled in 1996 which was placed on production in
January 1997.
Natural Gas Sales Agreement. The majority of the Company's natural gas
production from the Hugoton and Panoma Fields is sold under a long-term
contract (life-of-field) to KN Gas Supply Services, Inc. ("KNGSS"). Among
other things, this contract provides for annual re-determination of the price
the Company is to receive. In 1997, as in 1996, the price is calculated each
month by using the average of four Mid-Continent index prices less a variable
amount ranging from $.11 per MMBtu for an average index price less than $.75
to a maximum of $.20 for an average index price of $2.26 or higher. The volume
of natural gas for which the Company receives payment is reduced by one
percent of the volume as an in-kind fuel charge for moving the natural gas.
Net Profit Agreements. The Company produces natural gas in the Guymon-
Hugoton Field and the nearby Camrick Field under a Dry Gas Agreement with
Chevron U.S.A. Inc. ("Chevron"). This agreement allows the Company to expend
funds for the operation of the properties (including the cost of drilling
wells) and to recoup the funds so expended from current production income.
Eighty percent of net operating income generated by the natural gas production
(after operational costs are recouped, including the cost of drilling and
equipping wells) is then paid to Chevron. At each of December 31, 1995 and
1996, the Company had interests in 56 wells subject to the terms of this
agreement. The Company also produces natural gas in the Hugoton Field under
various agreements similar to the Chevron agreement, except that net operating
income is allocated 15% to the Company and 85% to other parties. At December
31, 1996, the Company had interests in an aggregate of 49 Chase Formation
wells and eight Council Grove Formation wells under these other agreements.
The third party interests under all the net profit agreements are treated as
lease operating expenses by the Company. Additional or replacement wells
drilled on the properties would be operated under the same terms and
conditions as existing wells, and would result in the commencement of the
80/20 or 85/15 net operating income allocation after the cost of the new wells
is recovered.
Hugoton Gas Trust Agreement. Natural gas rights established in 1955 to
approximately 50,000 acres in Finney and Kearny Counties, Kansas were
transferred to Plains by K N on October 1, 1984 subject to a natural gas
payment of $0.06 per Mcf for natural gas produced from the acreage. Quarterly
payments are made by the Company to the Hugoton Gas Trust, a publicly held
trust created in 1955. Payments terminate when the estimated
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gross recoverable natural gas reserves decline to 50 Bcf or less. As of
December 31, 1996, the gross proved natural gas reserves attributable to the
leases burdened by this agreement were estimated to be 144.3 Bcf. The natural
gas payments are treated as lease operating expenses by the Company. At
December 31, 1996, the Company had working interests in 196 wells that were
subject to these payments. Any additional natural gas wells drilled on this
acreage also will be subject to the $0.06 payment per Mcf of natural gas
produced.
At December 31, 1996, this Basin represented 26% of the Company's estimated
proved reserves, and 22% of the Company's total production. Barrett intends to
spend $2 million of its 1997 capital expenditure budget on the Hugoton
Embayment for development drilling and increased deliverability through
compression, including participating in drilling 16 new wells.
PERMIAN BASIN. The Permian Basin in west Texas and southeast New Mexico is
primarily an oil province. As of December 31, 1996, the Company had an
interest in 270 gross wells (191 net wells) located in the Permian Basin,
which produce approximately 1,337 barrels of oil per day net to the Company's
interests. In 1996, Barrett participated in drilling 15 wells in the Permian
Basin.
At December 31, 1996, this Basin represented 4% of the Company's estimated
proved reserves, and 7% of the Company's total production. Barrett intends to
spend 3% of its 1997 capital expenditure budget in the Permian Basin,
including participating in drilling up to 21 wells. This includes six wells in
the Sprayberry Trend where a recent 80-acre downspacing was approved.
GULF OF MEXICO REGION
Beginning in the latter half of 1995 and continuing during 1996, the Company
established a new core area in the Gulf of Mexico in the shallow offshore
Louisiana and Texas waters. In 1996, the Company participated in 15 Gulf of
Mexico wells, 12 of which were successful. The Company believes that this area
has significant reserve potential and is well suited to Barrett's exploration
emphasis and geologic expertise. The availability of extensive 3-D seismic
coverage over most of the Outer Continental Shelf ("OCS"), the frequency of
lease sales and the turnover of expiring leases also make the Gulf of Mexico
an attractive area. In addition, wells in the Gulf of Mexico typically produce
at higher rates, which increases cash flow, but have relatively shorter
productive lives. This production profile will complement the Company's long-
lived, relatively lower deliverability wells in the Rocky Mountain and Mid-
Continent regions. Also, Gulf of Mexico natural gas prices historically have
been higher than prices in other regions in which the Company operates.
Initially, the Company's Gulf of Mexico operations centered on developing
high quality prospects with established operators. At the April 1996 Central
Gulf of Mexico Outer Continental Shelf Lease Sale #157, the Company joined
another operator in acquiring nine blocks. The Company has a 25% working
interest through completion of production facilities and a 22% working
interest thereafter in each of these nine blocks. Separately, the Company
joined with a second operator with a 50% working interest, in acquiring one
block. In addition, the Company acquired a block in which it has a 100%
interest. Bonus payments net to the Company for these lease interests totaled
$2.3 million.
The Company's efforts are now directed at internally developing an inventory
of high quality prospects for future drilling. This effort was significantly
advanced at the Western Gulf of Mexico Outer Continental Shelf Lease Sale #161
in September 1996 as a result of which the Company acquired 17 blocks in water
depths ranging from 33 to 315 feet. The Company has a 100% working interest in
14 of these blocks and a 50% working interest in the three other blocks. The
Company's net share of the bonus payments for these leases was $34.4 million.
On March 5, 1997, the Company was the high bidder and apparent winner on
seven tracts offered in the Federal Offshore Lease Sale #166 for the Central
Gulf of Mexico. All bids are subject to approval by the Minerals Management
Service ("MMS"). The Company will have a 100% working interest in all of these
blocks, which range in water depth from 17 to 201 feet, if approved by the
MMS. Barrett's net share of the bonus payment for these apparent winning bids
was $14.87 million if all are accepted.
8
<PAGE>
At December 31, 1996, the Gulf of Mexico represented 3% of the Company's
estimated proved reserves, and 3% of the Company's total production. In 1997,
the Company intends to spend $113 million or 41% of the Company's 1997 capital
expenditure budget to drill 24 wells, acquire additional 3-D seismic for
future prospects, lease additional future prospects and to put into production
eight wells drilled in 1996.
INTERNATIONAL OPERATIONS
With an industry partner, the Company obtained, in November 1996, a license
to evaluate, explore and develop Block 55 (A, B, and C), which encompasses
approximately 820,000 acres in the Maranon Basin of eastern Peru. The Company
currently has a 55% working interest in this project and has the right to
increase its working interest to 77.5%. In the initial phase of the license,
which is underway, the Company and its co-venturer will be conducting seismic
reprocessing and environmental and engineering feasibility studies regarding
the viability of developing the Bretana Field, which was discovered in 1974 by
another company. Gross costs of approximately $1.3 million for this first
phase are expected. Following those studies, it is anticipated that an
appraisal well will be drilled in the third quarter of 1997. The gross costs
of drilling and testing this well are anticipated to be approximately $4.5
million.
In late January 1997, the Company entered into an agreement with industry
partners that provided the Company with a working interest in Block 67, which
covers approximately two million gross acres and is located in the Maranon
Basin of northeastern Peru. The Company and its partners intend to acquire and
analyze between 200 to 250 miles of seismic data in preparation for
exploratory drilling to begin in late 1997 or early 1998. The Company's
participation, which is subject to approval of the government of Peru, is
intended to consist of a 45% working interest, subject to a cost commitment of
60% of the 1996 and 1997 seismic costs and 60% of the cost of up to three
exploratory wells. The Company estimates that its total net cost for this
participation in seismic acquisition and the drilling of three exploratory
wells will approximate $7.5 million in 1997 and $7.2 million in 1998. It is
anticipated that the Company will be designated operator for operations in
Block 67 in mid-1997.
Pursuant to the licenses for both Block 55 and 67, the Republic of Peru
receives a variable royalty payment on production that can range from 18 to
38% based on an investment revenue ratio and is anticipated to average
approximately 23%. Estimated capital expenditures for international operations
for 1997 constitute approximately 4% of the Company's capital expenditure
budget.
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, "MMcf" means million cubic feet,
"Bcf" means billion cubic feet, "Bbl" means barrel, "MBbl" means thousand
barrels, "Mcfe" means thousand cubic feet equivalent, "MMcfe" means million
cubic feet equivalent, and "MMBtu" means million British thermal units.
With respect to information concerning the Company's working interests in
wells or drilling locations, "gross" natural gas and oil wells or "gross"
acres is the number of wells or acres in which the Company has an interest,
and "net" gas and oil wells or "net" acres are determined by multiplying
"gross" wells or acres by the Company's working interest in those wells or
acres. A working interest in 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.
9
<PAGE>
"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 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:
<TABLE>
<CAPTION>
NATURAL GAS AND OIL
PRODUCTION
-----------------------
YEAR ENDED DECEMBER 31,
-----------------------
1994 1995 1996
------- ------- -------
<S> <C> <C> <C>
Quantities Produced and Sold
Natural gas (Bcf).................................. 33.3 47.7 60.9
Oil and condensate (MMBbls)........................ 1.3 1.7 1.9
Average Sales Price
Natural gas ($/Mcf)................................ $ 1.83 $ 1.47 $ 1.88
Oil and condensate ($/Bbl)......................... 13.95 15.76 19.51
Average Production Costs/Mcfe....................... $ 0.69 $ 0.60 $ 0.66
</TABLE>
10
<PAGE>
PRODUCTIVE WELLS
The productive wells in which the Company owned a working interest as of
December 31, 1996 are described in the following table:
<TABLE>
<CAPTION>
PRODUCTIVE WELLS (1)
-------------------------
GAS WELLS OIL WELLS
------------ ------------
GROSS NET GROSS NET
----- ------ ----- ------
<S> <C> <C> <C> <C>
Rocky Mountain Region
Wind River....................................... 46 23.40 0 0.00
Piceance......................................... 297 159.56 0 0.00
Powder River..................................... 39 3.00 328 81.40
Green River...................................... 45 22.64 1 1.00
Uinta............................................ 1 0.78 135 115.58
Mid-Continent Region
Arkoma........................................... 121 32.06 0 0.00
Anadarko......................................... 191 73.03 16 15.60
Hugoton Embayment................................ 418 353.68 0 0.00
Permian.......................................... 16 10.48 254 180.74
Gulf of Mexico Region.............................. 21 5.86 3 1.00
Other.............................................. 100 66.89 74 5.90
----- ------ --- ------
Total.......................................... 1,295 751.38 811 401.22
===== ====== === ======
</TABLE>
- --------
(1) Each well completed to more than one producing zone is counted as a single
well. The Company has royalty interests in certain wells that are not
included in this table.
DRILLING ACTIVITY
The following table summarizes the Company's natural gas and oil drilling
activities, all of which were located in the United States, during the last
three years:
<TABLE>
<CAPTION>
WELLS DRILLED
-----------------------------------
YEAR ENDED DECEMBER 31,
-----------------------------------
1994 1995 1996
----------- ----------- -----------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C>
Development
Natural gas............................. 100 36.51 88 39.03 94 46.24
Oil..................................... 19 12.62 22 11.68 43 30.48
Non-productive.......................... 18 7.65 10 3.51 17 8.03
--- ----- --- ----- --- -----
Total................................. 137 56.78 120 54.22 154 84.75
=== ===== === ===== === =====
Exploratory
Natural gas............................. 1 0.50 0 0.00 8 4.05
Oil..................................... 5 0.58 1 0.33 3 1.00
Non-productive.......................... 8 1.84 8 2.65 6 3.66
--- ----- --- ----- --- -----
Total................................. 14 2.92 9 2.98 17 8.71
=== ===== === ===== === =====
</TABLE>
In addition, the Company was participating in 25 gross (10.82 net) wells,
which were in the process of being drilled, at December 31, 1996.
11
<PAGE>
RESERVES
The table below sets forth the Company's estimated quantities of historical
proved reserves, all of which were located in the United States, and the
present values attributable to those reserves. These estimates were prepared
by the Company. With respect to the reserve estimates as of and prior to
December 31, 1995, certain portions were reviewed by Ryder Scott Company, an
independent reservoir engineer, and the other portions were reviewed or
prepared by Netherland, Sewell & Associates, Inc., an independent reservoir
engineer. The estimates as of December 31, 1996 were reviewed solely by Ryder
Scott Company. The total proved net reserves estimated by the Company were
within 10% of those reviewed and estimated by the engineers; however, on a
well by well basis, differences of greater than 10% may exist.
<TABLE>
<CAPTION>
ESTIMATED PROVED RESERVES
-----------------------------------------------
DECEMBER 31,
-----------------------------------------------
1994 1995 1996
------------ ------------ ------------
(DOLLARS IN MILLIONS, EXCEPT SALES PRICE DATA)
<S> <C> <C> <C>
Estimated Proved Reserves
Natural gas (Bcf).......... 458.8 513.5 674.9
Oil and condensate
(MMBbls).................. 11.4 13.0 23.2
Total (Bcfe)............. 527.5 591.3 814.3
Proved developed reserves
(Bcfe)...................... 440.1 489.7 606.3
Natural gas price as of
December 31 ($/Mcf)......... $ 1.67 $ 1.77 $ 3.46
Oil price as of December 31
($/Bbl)..................... $ 14.43 $ 17.35 $ 24.12
Present value of estimated
future net revenues before
future income taxes
discounted at 10%(1)........ $ 322.7 $ 432.6 $ 1,121.5
Standardized measure of
discounted net cash
flows(2).................... $ 242.6 $ 309.9 $ 764.8
</TABLE>
- --------
(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 $1.95
per Mcf of natural gas and $11.05 per Bbl of oil at December 31, 1993,
$1.67 per Mcf of natural gas and $14.43 per Bbl of oil at December 31,
1994, $1.77 per Mcf of natural gas and $17.35 per Bbl of oil at December
31, 1995 and $3.46 per Mcf of natural gas and $24.12 per Bbl of oil at
December 31, 1996.
(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
12
<PAGE>
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 was filed prior to the Company's merger with Plains, by Barrett and
Plains, respectively. This report was the Annual Survey of Domestic Oil and
Gas Reserves and was filed with the Energy Information Administration ("EIA")
as required by law. Only minor differences of less than 5% in reserve
estimates, which were due to small variances in actual production versus year
end estimates, have occurred in certain classifications reported in this
document as compared to those in the EIA report.
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, 1996 are summarized in the
following table. "Undeveloped Acreage" includes leasehold interests that
already may have been classified as containing proved undeveloped reserves.
<TABLE>
<CAPTION>
DEVELOPED ACREAGE UNDEVELOPED ACREAGE
----------------- -------------------
GROSS NET GROSS NET
-------- -------- ---------- --------
<S> <C> <C> <C> <C>
Rocky Mountain Region
Wind River.............................. 5,115 3,411 105,296 93,344
Piceance................................ 36,560 20,336 116,405 55,443
Powder River............................ 42,848 26,319 68,640 26,214
Green River............................. 22,055 7,038 52,139 37,673
Uinta................................... 97,580 60,940 57,168 44,346
Mid-Continent Region
Arkoma.................................. 51,200 14,450 19,112 13,789
Anadarko................................ 83,265 49,920 56,256 51,855
Hugoton Embayment....................... 88,332 84,946 0 0
Permian................................. 45,701 15,143 5,952 1,313
Gulf of Mexico Region..................... 34,765 9,255 179,791 114,093
International............................. 0 0 820,000 451,000
Other..................................... 41,225 28,209 27,394 11,204
-------- -------- ---------- --------
Total................................. 548,646 319,967 1,508,153 900,274
======== ======== ========== ========
</TABLE>
- --------
(1) Undeveloped acreage is leased acreage on which wells have not been drilled
or completed to a point that would permit the production of commercial
quantities of natural gas and oil regardless of whether such acreage
contains proved reserves. Of the aggregate of 1,508,153 gross and 900,274
net undeveloped acres, 165,896 gross and 75,250 net acres are held by
production from other leasehold acreage.
13
<PAGE>
Substantially all the leases summarized in the preceding table will expire
at the end of their respective primary terms unless the existing leases are
renewed or production has been obtained from the acreage subject to the lease
prior to that date, in which event the lease will remain in effect until the
cessation of production. The following table sets forth the gross and net
acres subject to leases summarized in the preceding table that will expire
during the periods indicated:
<TABLE>
<CAPTION>
ACRES EXPIRING GROSS NET
-------------- --------- -------
<S> <C> <C>
Twelve Months Ending:
December 31, 1997........................................ 91,416 31,630
December 31, 1998........................................ 30,493 30,348
December 31, 1999........................................ 58,476 58,408
December 31, 2000 and later.............................. 1,327,768 779,888
</TABLE>
OVERRIDING ROYALTY INTERESTS
The Company owns overriding royalty interests covering in excess of 52,394
gross acres. The majority of these overriding royalty interests are within a
range of approximately 0.25 to 2.5 percent.
NATURAL GAS AND OIL MARKETING AND TRADING
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.
NATURAL GAS. The Company has entered into a number of gas sales agreements
on behalf of itself and its industry partners with respect to the sale of
natural gas from its properties in each of the Company's basins. These
contracts vary with respect to their specific provisions, including price,
quantity, and length of contract. As of December 31, 1996, less than 7% of the
Company's production was committed to natural gas sales contracts that had
fixed prices or price ceilings. With the exception of two contracts covering
approximately 8,100 MMBtu per day of natural gas production from the Piceance
Basin through 2011, none of the contracts provides for fixed prices or price
ceilings beyond May 1997. The Company believes that it has sufficient
production from its properties to meet the Company's delivery obligations
under its existing natural gas sales contracts.
The Company has entered into a series of firm transportation agreements with
various Rocky Mountain pipeline companies. At January 1, 1997, these
transportation arrangements had terms ranging from seven months to ten years.
These transportation agreements provide the Company the opportunity to
transport a portion of its Rocky Mountain natural gas production into the Mid-
Continent area. These agreements in total provide transportation of
approximately 52% of the Company's current daily Rocky Mountain production.
In addition to the agreements described above, the Company has entered into
a transportation arrangement to support the conversion of a crude oil line to
natural gas service. This expansion is designed to transport Rocky Mountain
natural gas production to the Mid-Continent area for sale. The Company has
committed to 5,000 MMBtu per day of pipeline capacity for a term of five
years. This expansion is subject to Federal Energy Regulatory Commission
("FERC") approval and is scheduled to be operational by the third quarter of
1997.
For each of 1996 and 1997, the Company renegotiated the pricing provisions
with KNGSS with respect to a majority of its Hugoton and Panoma Fields natural
gas production. The price is calculated on a monthly basis by using the
average of four Mid-Continent index prices less a variable amount ranging from
$.11 per MMBtu for an average index price less than $.75 to a maximum of $.20
for an average index price of $2.26 or higher. The volume of natural gas for
which the Company receives payment is reduced by one percent of the volume as
an in-kind fuel charge for moving the natural gas.
14
<PAGE>
During the year ended December 31, 1996, there was one natural gas
purchaser, KNGSS, that accounted for approximately 11% of the Company's total
revenues. The Company believes it would be able to locate alternate customers
in the event of the loss of this customer.
The Company has established a Risk Management Committee to oversee its
production hedging and trading activities. The Risk Management Committee
consists of the Chief Executive Officer, the President and Chief Operating
Officer, the Chief Financial Officer, and the Executive Vice President--
Operations. With respect to production hedge transactions, it is the policy of
the Company that the Risk Management Committee review and approve all such
transactions.
As a result of its natural gas trading activities, the Company may from time
to time have natural gas purchase or sales commitments without corresponding
contracts to offset these commitments, which could result in losses to the
Company. The Company currently attempts to control and manage its exposure to
these risks by monitoring and hedging its trading positions as it deems
appropriate and by having the Company's Risk Management Committee review
significant trades or positions before they are committed to by trading
personnel. All fixed price trading activities are hedged to lock in margins.
As of December 31, 1996, the Company had entered into financial transactions
to hedge approximately 8.8 Bcf of natural gas production for the period from
January 1997 through October 1997. In January 1997, the Company entered into a
transaction to hedge an aggregate of 25.6 Bcf of natural gas production from
the Rocky Mountain Region for the five-year period from March 1998 through
February 2003. In February 1997, the Company entered into an additional
transaction to hedge an aggregate of approximately 18.2 Bcf of natural gas
production from the Rocky Mountain Region for the same five-year period. In
March 1997, the Company entered into an additional transaction to hedge an
aggregate of approximately 13.7 Bcf of natural gas production from the Rocky
Mountain Region for the same time period.
For the year ended December 31, 1996, revenues from trading activities,
which includes the cost of natural gas purchased or sold for trading purposes,
were $46.9 million, which constituted 23% of the Company's consolidated
revenues and generated a gross margin of $2.8 million. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations."
OIL AND CONDENSATE. Oil, including condensate production, is generally sold
from the leases at posted field prices, plus negotiated bonuses. Marketing
arrangements are made locally with various petroleum companies. The Company
sells its own oil production to numerous customers. No single customer's total
oil purchases represented more than 10% of total Company revenues in 1996. Oil
revenues totaled $37.3 million for the year ended December 31, 1996 and
represented 18% of the Company's total revenues for that period. The Company
does not engage in oil trading activities.
GOVERNMENT REGULATION OF THE OIL AND GAS INDUSTRY
GENERAL
The Company's exploration, production and marketing operations are regulated
extensively at the federal, state and local levels. Natural gas and oil
exploration, development and production activities are subject to various laws
and regulations governing a wide variety of matters. For example, hydrocarbon-
producing states have statutes or regulations addressing conservation
practices and the protection of correlative rights, and such regulations may
affect the Company's operations and limit the quantity of hydrocarbons the
Company may produce and sell. Other regulated matters include marketing,
pricing, transportation, and valuation of royalty payments.
Certain operations the Company conducts are on federal oil and gas leases,
which the MMS administers. The MMS issues such leases through competitive
bidding. These leases contain relatively standardized terms and require
compliance with detailed MMS regulations and orders pursuant to the Outer
Continental Shelf Lands
15
<PAGE>
Act ("OCSLA"), which are subject to change by the MMS. For offshore
operations, lessees must obtain MMS approval for exploration plans and
development and production plans prior to the commencement of such operations.
In addition to permits required from other agencies (such as the Coast Guard,
the Army Corps of Engineers and the Environmental Protection Agency), lessees
must obtain a permit from the MMS prior to the commencement of drilling. The
MMS has promulgated regulations requiring offshore production facilities
located on the OCS to meet stringent engineering and construction
specifications. The MMS proposed additional safety-related regulations
concerning the design and operating procedures for OCS production platforms
and pipelines. These proposed regulations were withdrawn pending further
discussions among interested federal agencies. The MMS also has issued
regulations restricting the flaring or venting of natural gas and liquid
hydrocarbons without prior authorization. Similarly, the MMS has promulgated
regulations governing the plugging and abandonment of wells located offshore
and the removal of all production facilities. To cover the various obligations
of lessees on the OCS, the MMS generally requires that lessees post
substantial bonds or other acceptable assurances that such obligations will be
met. The cost of such bonds or other surety can be substantial and there is no
assurance that bonds or other surety can be obtained in all cases. Under
certain circumstances, the MMS may require any Company operations on federal
leases to be suspended or terminated. Any such suspension or termination could
materially and adversely affect the Company's financial condition and
operations.
At the U.S. federal level, the FERC regulates interstate transportation of
natural gas under the Natural Gas Act and regulates the maximum selling prices
of certain categories of natural gas sold in "first sales" in interstate and
intrastate commerce under the Natural Gas Policy Act ("NGPA"). Effective
January 1, 1993, the Natural Gas Wellhead Decontrol Act deregulated natural
gas prices for all "first sales" of natural gas, which includes sales by
Barrett of its own production. As a result, all sales of the Company's natural
gas produced in the U.S. may be sold at market prices, unless otherwise
committed by contract. Congress could reenact price controls in the future.
See "--Natural Gas and Oil Marketing and Trading."
The Company's natural gas sales are affected by regulation of intrastate and
interstate natural gas transportation. In an attempt to promote competition,
the FERC has issued a series of orders which have altered significantly the
marketing and transportation of natural gas. The effect of these orders has
been to enable the Company to market its natural gas production to purchasers
other than the interstate pipelines located in the vicinity of its producing
properties. The Company believes that these changes have generally improved
the Company's access to transportation and have enhanced the marketability of
its natural gas production. To date, Barrett has not experienced any material
adverse effect on natural gas marketing as a result of these FERC orders;
however, the Company cannot predict what new regulations may be adopted by the
FERC and other regulatory authorities, or what effect subsequent regulations
may have on its future natural gas marketing.
The Company also is subject to laws and regulations concerning occupational
safety and health. It is not anticipated that the Company will be required in
the near future to expend amounts that are material in the aggregate to the
Company's overall operations by reason of occupational safety and health laws
and regulations, but inasmuch as such laws and regulations are frequently
changed, the Company is unable to predict the ultimate cost of compliance.
ENVIRONMENTAL MATTERS
The Company, as an owner or lessee and operator of natural gas and oil
properties, is subject to various federal, state and local laws and
regulations relating to discharge of materials into, and protection of, the
environment. These laws and regulations may, among other things, impose
liability and substantial penalties on the lessee under a natural gas and oil
lease for the cost of pollution clean-up resulting from operations, subject
the lessee to liability for pollution damages, require suspension or cessation
of operations in affected areas, and impose restrictions on the injection of
liquid into subsurface aquifers that may contaminate groundwater. The Oil
Pollution Act of 1990, as recently amended by the Coast Guard Authorization
Act of 1996, requires operators of offshore facilities to provide financial
assurance in the amount of $35 million to cover potential environmental
cleanup and restoration costs. This amount is subject to upward regulatory
adjustment.
16
<PAGE>
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 Matters", 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 Prospectus dated February 11, 1997 included
in the Company's Registration Statement on Form S-3 (File Number 333-19363).
All written and oral forward-looking statements attributable to the Company or
persons acting on its behalf subsequent to the date of this Annual Report on
Form 10-K are expressly qualified in their entirety by the Cautionary
Statements.
ITEM 3. LEGAL PROCEEDINGS
On November 29, 1996, the Company filed a petition with the United States
Tax Court to request a redetermination of a Notice Of Deficiency issued to the
Company by the Internal Revenue Service (the "IRS"). The IRS had examined the
federal tax returns of the Company's Plains subsidiary for the calendars years
of 1991, 1992 and 1993, which were prior to the merger of Plains and a
subsidiary of the Company. The IRS issued a Notice of Deficiency of $5.3
million, together with penalties of $1.1 million, and an undetermined amount
of interest. The IRS Notice Of Deficiency resulted primarily from the IRS's
disallowance of certain net operating loss deductions claimed during the
periods under examination. These net operating losses originally had been
incurred by a company that was acquired by Plains in 1986. The Company
currently has additional unused net operating loss carry forwards of
approximately $30 million related to the same acquisition.
17
<PAGE>
Management of the Company 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 carry forwards are
appropriate as supported by relevant authority. The Company will vigorously
contest these proposed adjustments and believes it will prevail in its
positions. It is anticipated that the final determination of this matter will
involve a lengthy process. The petition filed by the Company on November 29,
1996 with the United States Tax Court requests that the IRS Notice Of
Deficiency be redetermined by allowing the net operating losses deductions as
originally reported in the Plains tax returns.
At December 31, 1996, 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, 1996.
18
<PAGE>
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SECURITY HOLDERS
MATTERS.
(a) Market Information. The Company's common stock is listed on the New York
Stock Exchange under the symbol BRR. The range of high and low sales prices
for each quarterly period during the two most recent years, as reported by the
New York Stock Exchange, is as follows:
<TABLE>
<CAPTION>
QUARTER ENDED HIGH LOW
------------- ------ ------
<S> <C> <C>
March 31, 1995............................................... $21.75 $16.87
June 30, 1995................................................ 25.87 19.37
September 30, 1995........................................... 25.37 19.37
December 31, 1995............................................ 30.62 21.00
March 31, 1996............................................... $29.50 $22.00
June 30, 1996................................................ 29.87 22.50
September 30, 1996........................................... 36.75 28.00
December 31, 1996............................................ 43.00 33.00
</TABLE>
On March 20, 1997, the closing price for the Company's common stock was
$34.00 per share.
(b) Holders. The number of record holders of the Company's common stock as
of March 20, 1997, was 4,148.
(c) Dividends. The Company has not paid any cash dividends since its
inception. The Company's credit agreement restricts payment of dividends to
amounts that are less than 50 percent of net income. The Company anticipates
that all earnings will be retained for the development of its business and
that no cash dividends on its common stock will be declared in the foreseeable
future.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth certain selected financial data of the
Company for each of the last five years ended December 31:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------
1996 1995 1994 1993 1992
-------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C>
Revenues........................ $202,572 $128,016 $109,458 $106,072 $ 89,050
Net income (loss)............... 29,256 (2,240) 11,299 13,666 13,872
Per share....................... 1.02 (0.09) 0.46 0.55 0.47
Total assets at the end of each
period......................... 576,945 340,412 310,952 243,452 208,601
Long-term debt at the end of
each period.................... 70,000 89,000 53,000 13,500 20,000
</TABLE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following discussion should be read in conjunction with the Consolidated
Financial Statements and Notes thereto referred to in "Item 8. Financial
Statements and Supplemental Data", and "Items 1 and 2. Business and
Properties--Disclosure Regarding Forward-Looking Statements" of this Form 10-
K.
LIQUIDITY AND CAPITAL RESOURCES
At December 31, 1996, the Company had cash and short-term investments of
$14.5 million, working capital of $11.4 million, property and equipment of
$487.3 million and total assets of $576.9 million. Compared to
19
<PAGE>
December 31, 1995, cash and short-term investments increased $7.0 million,
working capital increased $7.7 million, property and equipment increased
$186.6 million, and total assets increased $236.5 million.
During 1996, the Company generated operating cash flow of $87.8 million
before working capital changes, which is $54.4 million greater than the amount
generated in 1995. After working capital changes, cash flow provided by
operations was $88.7 million, an increase of $53.2 million from 1995. The 1995
amounts were net of costs associated with the merger of Plains Petroleum
Company ("Plains").
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 was approximately $134.8 million after deducting issuance costs and
underwriting fees. Of the net proceeds from this offering, $110 million was
used to repay the balance of the Company's outstanding credit facility at that
date.
As of December 31, 1996 and 1995, respectively, the outstanding balance
under the Company's bank credit facility was $70 million and $89 million. The
Company's bank credit facility is an unsecured $200 million facility with a
consortium of six banks. The amount of the borrowing base under the bank
credit facility at any time is determined by the lenders with reference to the
Company's proved reserves and the Company's projected cash requirements. With
the issuance of the $150 million of senior notes discussed below, the current
borrowing base is $75 million until May 1, 1997, at which time the borrowing
base may be adjusted based on the lending banks' review of the Company's
December 31, 1996 reserves and projected cash requirements. At the time of
borrowing funds under the bank credit facility, interest begins to accrue on
those funds, at the Company's election, either at the London interbank
eurodollar rate (LIBOR) plus a spread ranging from 0.5 percent to 1.0 percent
(depending on the ratio of the Company's outstanding indebtedness to its
borrowing base) or at the U.S. prime rate of interest. The Company is required
to pay interest on a quarterly basis until the entire outstanding balance
matures on October 31, 2000.
In February 1997, the Company completed a public offering of $150 million of
7.55% Senior Notes due 2007 ("Notes"). A portion of the net proceeds from the
offering was used to repay in full the then outstanding balance of $85 million
of the Company's existing line of credit. The Notes are senior unsecured
obligations of the Company ranking equally in right of payment to all existing
and future senior indebtedness of the Company. The Company will pay interest
semi-annually on February 1 and August 1 of each year, beginning August 1,
1997.
Capital Expenditures
During 1996 the Company invested $234.7 million in oil and gas properties
and other equipment, including acquisitions of oil and gas property working
interests and related facilities principally in the Piceance and Uinta Basins,
and exploration and development programs principally in the Anadarko, Arkoma,
Piceance, Wind River and Uinta basins and in the Gulf of Mexico. These
drilling programs were primarily to develop and extend producing fields.
During the year the Company expanded its exploration programs with investments
in leases in the Gulf of Mexico, offshore Louisiana and Texas, and
international programs in Peru.
The Company's capital expenditure budget for 1997 has been established at
$279.9 million. This capital expenditure budget represents an increase of
$45.2 million over 1996 capital expenditures. During 1997, the Company expects
to spend approximately $113 million in exploring and developing its prospects
in the Gulf of Mexico Region. Other significant budgeted exploratory and
development capital expenditures include $92 million in the Rocky Mountain
Region with emphasis in the Wind River and Piceance Basins, $46 million in the
Mid-Continent Region, and $12 million in Peru. The Company's exploration and
development programs are discussed in "Business and Properties" under Items 1
and 2 of this Form 10-K.
On March 5, 1997, the Company was the high bidder and apparent winner on
seven tracts offered in the Federal Offshore Lease Sale #166 for the Central
Gulf of Mexico. All bids are subject to approval by the MMS.
20
<PAGE>
If approved, the Company will have a 100 percent working interest in all of
these blocks with net bonus obligations of approximately $14.9 million.
Reserves and Pricing
Proved reserves at year end 1996 were 814.3 billion cubic feet of natural
gas equivalents (Bcfe), a 38 percent increase over December 31, 1995 proved
reserves. Approximately 52 percent of the reserve additions were generated
through exploration and development projects and 48 percent of the reserve
additions were provided by acquisitions of properties. Proved reserves were
reduced by production of approximately 72.4 Bcfe, sales of properties with
reserves of 18.2 Bcfe, and downward revisions of previous estimates of 2.0
Bcfe. During 1996, as a result of its drilling and acquisition activities net
of sales and revisions, the Company's reserve replacement was 408 percent of
total production.
As of year-end 1996, the standardized measure of discounted future net cash
flows increased $454.9 million, or 147 percent, from 1995 primarily due to
reserve additions and increases in oil and gas prices. Reserve extensions and
discoveries added $230.8 million to the standardized measure, and purchases of
proved reserves, net of sales, added $167.2 million. The changes in year end
sales prices and production costs from 1995 to 1996 increased the standardized
measure of discounted future net cash flows by $415.9 million. These additions
were offset by a $110.3 million reduction due to reserves produced during the
year and $249.8 million for additional income taxes being deducted in the
computation. 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. Generally higher
natural gas prices prevail during the winter months of December through
February. As of December 31, 1996, the Company was receiving weighted average
prices of $24.12 per barrel of oil and $3.46 per Mcf of gas. These prices are
significantly above the average annual prices received during the past several
years. During the first three months of 1997, prices have declined from the
December 31, 1996 levels. A significant decline in prices would have a
material effect on the standardized measure of 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.
From time to time the Company uses swaps to hedge the sales price of its
natural gas and oil. In a typical swap agreement, the Company and a
counterparty will enter into an agreement whereby one party will pay a fixed
price and the other will pay an index price on a specified volume of
production during a specified period of time. Settlement is made by the
parties for the difference between the two prices at approximately the same
time as the physical transactions. The intent of hedging activities is to
reduce the volatility associated with the sales prices of the Company's
natural gas and oil production. Although hedging transactions associated with
the Company's production minimize the Company's exposure to reductions in
production revenue as a result of unfavorable price changes, these
transactions also limit the Company's ability to benefit from favorable price
changes. As of December 31, 1996, the Company held positions to hedge 8.8 Bcf
of the Company's future natural gas production at an average price of $1.87
per Mcf. Subsequent to December 31, 1996, the Company hedged an additional
43.8 Bcf of natural gas production, over a five year period beginning March
1998, at a weighted average price of $1.74 per Mcf. These positions are more
fully described in the notes to the financial statements. The Company
currently has no oil swaps in place for 1997.
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.
21
<PAGE>
RESULTS OF OPERATIONS
In 1995, the Company consummated a merger of a wholly owned subsidiary of
the Company with Plains by issuing 12.8 million shares of its common stock to
the former Plains stockholders. As a result of this merger, Plains became a
wholly owned subsidiary of the Company. In addition, in 1995, the Company
changed its fiscal year end from September 30 to December 31. The merger was
accounted for using the pooling of interests method. This method of accounting
for mergers combines previously reported results as though the combination had
occurred at the beginning of the periods being presented. Merger costs were
expensed during 1995. The financial statements of the Company and Plains for
1994 through 1995 have been restated and adjusted for the merger with Plains
and the change in fiscal year end. Due to this restatement, these financial
statements are not comparable to the financial statements for the same periods
as previously presented by the separate companies.
1996 vs. 1995
During 1996, the Company earned net income of $29.5 million ($1.02 per
share) compared to a net loss of $2.2 million ($.09 per share) in 1995. The
1995 results included $14.2 million for merger and reorganization costs.
Excluding the merger costs, the Company's net income after taxes in 1995 would
have been $9.5 million ($.38 per share).
Revenues increased 58 percent from 1995 to $202.6 million, and operating
expenses increased 23 percent to $158.1 million. Production revenues increased
56 percent to $151.7 million, and trading revenues increased 64 percent to
$46.9 million. Lease operating expenses increased $13.1 million, and
depreciation, depletion and amortization increased $12.3 million.
Production revenues increased $54.7 million due primarily to a 28 percent
increase in gas production to 60.9 Bcf (166,400 Mcf per day) coupled with a 28
percent increase in the average gas sales price to $1.88 per Mcf. Oil
production increased 12 percent to 1,913,000 barrels (5,226 barrels per day)
while the average oil prices increased 24 percent to $19.51 per barrel. Gas
production accounted for 84 percent of total production on an energy
equivalent basis. The Hugoton Embayment and Wind River Basin properties
accounted for 26 and 25 percent, respectively, of total gas production. The
Powder River and Permian Basins accounted for 44 and 26 percent, respectively,
of total oil production.
Lease operating expenses of $47.6 million averaged $.66 per Mcfe ($3.95 per
BOE) of production compared to $.60 per Mcfe ($3.58 per BOE) in 1995.
Depreciation, depletion, and amortization increased $12.3 million primarily
due to production increases. During 1996, depreciation, depletion, and
amortization on oil and gas production was provided at an average rate of $.59
per Mcfe ($3.54 per BOE) compared to an average rate of $.55 per Mcfe ($3.28
per BOE) in 1995.
The gross margin on trading activities increased to $2,826,000 from $943,000
in 1995. Gas trading volumes increased 35 percent to 29.9 Bcf in 1996.
The Company enters into the hedging arrangements to minimize its exposure to
price risks associated with commodities markets. Although hedging transactions
associated with its production minimize the Company's exposure to losses as a
result of unfavorable price changes, the transactions also limit the Company's
ability to benefit from favorable price changes. During 1996, the Company
hedged 14.1 Bcf (23 percent) of gas production for a net cost of $4.6 million
and hedged 182 MBbls (10 percent) of oil production for a net cost of $0.3
million.
General and administrative expenses of $16.9 million are 26 percent greater
than the previous year. The 1996 amount is net of $4.0 million of operating
fee recoveries compared to a $3.8 million recovery in 1995. General and
administrative costs increased during 1996 due to the continued growth and
expansion of the Company. Interest expense decreased from $4.6 million in 1995
to $3.7 million in 1996. This decline is attributed to a mid-year reduction of
the Company's debt as a result of application of proceeds of the Company's
June 1996 public equity offering to repay the outstanding balance of $110
million on the Company's bank credit facility at that time.
22
<PAGE>
Income tax expenses increased to $15.0 million from $1.8 million in 1995.
The Company's effective financial statement tax rate in 1996 was 33.6 percent,
compared to a combined federal and state statutory rate of approximately 38
percent.
The Company's results of operations depend primarily on the production of
natural gas which accounted for over 80 percent of the Company's reserves and
production during 1996. Therefore, the Company's future results will depend,
among other things, on both the volume of natural gas production and the sales
price for gas. The Company continues to explore for oil and gas to increase
its production. The lack of predictability of both production volumes and
sales prices may influence future operating results.
1995 vs. 1994
During 1995, the Company incurred a net loss of $2.2 million ($.09 per
share) compared to net income of $11.3 million ($.46 per share) in 1994. The
1995 results include merger and reorganization costs of $14.2 million.
Excluding the merger costs, the Company's net income after taxes for 1995
would have been $9.5 million ($.38 per share).
Revenues increased 17 percent from 1994 to $128.0 million. Operating
expenses, including $14.2 million of merger and reorganization costs,
increased 38 percent to $128.4 million. Oil and gas production revenue
increased 23 percent to $97.0 million. Lease operating expenses increased $6.3
million, and depreciation, depletion and amortization increased $10.7 million.
Production revenues increased $18.2 million from 1994 primarily due to a 43
percent increase in gas production to 47.7 Bcf (130,700 Mcf per day). Oil
production increased 32 percent to 1,702,000 barrels (4,660 barrels per day).
Average gas sales prices decreased 20 percent to $1.47 per Mcf, while average
oil prices increased 13 percent to $15.76 per barrel. Gas production accounted
for 82 percent of total production on an energy equivalent basis. The Hugoton
Embayment and Piceance Basin properties accounted for 37 and 14 percent,
respectively, of total gas production. The Powder River and Permian Basins
accounted for 43 and 32 percent, respectively, of total oil production. The
decreased gas sales price was due to an overall deterioration in gas markets
during most of the year.
Lease operating expenses of $34.5 million in 1995 averaged $.60 per Mcfe
($3.58 per BOE) of production compared to $.69 per Mcfe ($4.13 per BOE) in
1994. Depreciation, depletion and amortization increased $10.7 million
primarily due to production increases. During 1995, depreciation, depletion
and amortization on oil and gas production was provided at an average rate of
$.55 per Mcfe ($3.28 per BOE) compared to an average rate of $.52 per Mcfe
($3.14 per BOE) in 1994.
The gross margin on trading activities was virtually unchanged from 1994 at
$943,000. Gas trading volumes increased 26 percent to 22.2 Bcf in 1995.
The Company hedged 11.0 Bcf (23 percent) of gas production for a net gain of
$417,000. The hedging gain related to production is net of $1.2 million for an
expense recorded in the fourth quarter due to a lack of correlation of the
hedging instruments to the underlying commodity as of December 31, 1995. At
the end of December 1995, the basis differential between the commodities
markets and the market price of the Company's gas widened to historic levels.
Because the increase in the commodities price was not accompanied by a similar
increase in the market price of the Company's gas, the Company recorded an
expense for the difference due to the inefficient hedge and the positions that
did not qualify for hedge accounting treatment.
General and administrative expenses of $13.4 million for 1995 are one
percent greater than the previous year. The 1995 amount is net of $3.8 million
of operating fee recoveries compared to a $3.4 million recovery in 1994.
General and administrative expense in 1995 is generally a combination of the
separate expenses for the Company and Plains, since the integration of the two
entities did not occur until late in the year, and included costs for the
Company to expand its business in existing and new activity areas. Interest
expense increased
23
<PAGE>
significantly from $942,000 in 1994 to $4.6 million in 1995 as the Company
financed a portion of its growth with bank debt. The Company incurred a 1995
expense of $14.2 million to combine the Company and Plains and to integrate
the operations of the two companies. The costs consist primarily of $7.4
million of investment banker and other professional fees to evaluate and
consummate the merger and $5.6 million for employee termination and benefit
costs.
During 1995, the Company recorded a $1.8 million income tax expense even
though it incurred a loss before taxes due to non-deductible merger costs.
Excluding non-deductible merger costs, the Company would have had a $600,000
tax benefit.
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 ACCOUNTS ON ACCOUNTING AND FINANCIAL
DISCLOSURES
Not applicable.
24
<PAGE>
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY
The directors and executive officers of the Company, their respective ages
and positions, and the year in which each director was first elected, are set
forth in the following table. Additional information concerning each of these
individuals follows the table:
<TABLE>
<CAPTION>
DIRECTOR
AGE POSITION WITH THE COMPANY SINCE
--- ------------------------- --------
<S> <C> <C> <C>
William J. Barrett
(1)(2)(5)(7)(8)........ 68 Chief Executive Officer and Chairman of the 1993
Board
C. Robert Buford 1983
(1)(2)(3)(4)........... 63 Director
Derrill Cody (2)(3)(4).. 58 Director 1995
James M. Fitzgibbons 1987
(3)(4)(6).............. 62 Director
Hennie L.J.M. Gieskes 1985
(1)(3)(4).............. 58 Director
William W. Grant, III 1995
(3)(4)................. 64 Director
J. Frank Keller (5)..... 53 Chief Financial Officer, Executive Vice 1983
President, Secretary, and a Director
Paul M. Rady (2)(8)..... 43 President, Chief Operating Officer, and a 1994
Director
A. Ralph Reed........... 59 Executive Vice President--Operations and a 1990
Director
James T. Rodgers 1993
(3)(4)................. 62 Director
Philippe S.E. Schreiber 1985
(2)(3)(4).............. 56 Director
Harry S. Welch (3)(4)... 73 Director 1995
Joseph P. Barrett (7)... 43 Vice President--Land --
Peter A. Dea............ 43 Senior Vice President--Exploration --
Clifford S. Foss, Jr.... 49 Vice President and General Manager--Gulf of --
Mexico Region
Bryan G. Hassler........ 38 Vice President--Marketing --
Robert W. Howard........ 42 Senior Vice President--Finance and Treasurer --
Eugene A. Lang, Jr...... 43 Senior Vice President and General Counsel --
Donald H. Stevens....... 44 Vice President--Corporate Relations and Capital --
Markets
Maurice F. Storm........ 36 Vice President and General Manager--Mid- --
Continent Region
</TABLE>
- --------
(1) 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) Mr. Keller and Mr. Barrett are brothers-in-law.
(6) Mr. Fitzgibbons served as a Director of the Company from July 1987 until
October 1992. He was re-elected to the Board of Directors in January 1994.
(7) Joseph P. Barrett is the son of William J. Barrett.
(8) The Board of Directors has elected Paul M. Rady to serve as Chief
Executive Officer effective as of July 1, 1997, at which time William J.
Barrett will retire as Chief Executive Officer. Mr. Barrett's retirement
plans include remaining as Chairman of the Board until January 1999.
WILLIAM J. BARRETT has been Chief Executive Officer since December 1983 and
Chairman of the Board of Directors of the Company since March 1994. Mr.
Barrett was President of the Company from December 1983 through September
1994. From January 1979 to February 1982, Mr. Barrett was an independent oil
and gas operator in the western United States in association with Aeon Energy,
a partnership composed of four sole proprietorships. From 1971 to 1978, Mr.
Barrett served as Vice President--Exploration and a director of Rainbow
Resources, Inc., a publicly held independent oil and gas exploration company
that merged with a subsidiary of the Williams Companies in 1978. Mr. Barrett
served as President, Exploration Manager and
25
<PAGE>
Director for B&C Exploration from 1969 until 1971 and was a chief geologist
for Wolf Exploration Company, now known as Inexco Oil Co., from 1967 to 1969.
He was an exploration geologist with Pan-American Petroleum Corporation from
1963 to 1966 and worked as an exploration geologist, a petroleum geologist and
a stratigrapher for El Paso Natural Gas Co. at various times from 1958 to
1963. Mr. Barrett's retirement plans include remaining as Chairman of the
Board until January 1999 and remaining as Chief Executive Officer until July
1, 1997.
C. ROBERT BUFORD has been a director of the Company since December 1983 and
served as Chairman of the Board of Directors from December 1983 through March
1994. Mr. Buford has been President, Chairman of the Board and controlling
shareholder of Zenith Drilling Corporation ("Zenith"), Wichita, Kansas, since
February 1966. Zenith is engaged in the oil and gas business and owns
approximately 3% of the Company's common stock. Since 1993, Mr. Buford has
served as a director of Encore Energy, Inc., a wholly owned subsidiary of
Zenith engaged in the marketing of natural gas. Mr. Buford is also a member of
the Board of Directors of Intrust Financial Corporation, a bank holding
company. Mr. Buford served as a director of Lonestar Steakhouse & Saloon, Inc
from March 1992 until his resignation on January 3, 1997.
DERRILL CODY has been a director of the Company since July 1995. Mr. Cody
was a director of Plains from May 1990 through July 1995. Since January 1990,
Mr. Cody has been an attorney in private practice in Oklahoma City, Oklahoma.
From 1986 to 1990, he was Executive Vice President of Texas Eastern
Corporation, and from 1987 to 1990 he was the Chief Executive Officer of Texas
Eastern Pipeline Company. He has been a director of the general partner of
TEPPCO Partners, L.P. since January 1990.
JAMES M. FITZGIBBONS has been a director of the Company since January 1994,
and previously served as a director of the Company from July 1987 until
October 1992. Since October 1990, Mr. Fitzgibbons has been Chairman and Chief
Executive Officer of Fieldcrest Cannon, Inc., a manufacturer of home
furnishing textiles. From January 1986 until October 1990, Mr. Fitzgibbons was
President of Amoskeag Company in Boston, Massachusetts. Prior to 1986, he was
President of Howes Leather Company, a producer of leather. Mr. Fitzgibbons is
also member of the Board Of Directors of Lumber Mutual Insurance Company,
American Textile Manufacturers Institute and a Trustee of Dreyfus Laurel
Funds, a series of mutual funds.
HENNIE L.J.M. GIESKES has been a director of the Company since November
1985. Mr. Gieskes is the Managing Director of Spaarne Compagnie N.V., a
Netherlands company engaged in the investment business. From before 1976 until
December 1990, Mr. Gieskes was a Managing Director of Vitol Beheer B.V., a
Netherlands trading company engaged primarily in energy-related commodities.
WILLIAM W. GRANT, III has been a director of the Company since July 1995.
Mr. Grant was a director of Plains from May 1987 through July 1995. He has
been an advisory director of Colorado National Bankshares, Inc. and Colorado
National Bank since 1993. He was a director of Colorado National Bankshares,
Inc. from 1982 to 1993 and the Chairman of the Board of Colorado National Bank
from 1986 to 1993. He served as the Chairman of the Board of Colorado Capital
Advisors from 1989 through 1994.
J. FRANK KELLER has been Chief Financial Officer since July 1995 and an
Executive Vice President, the Secretary and a director of the Company since
December 1983. Mr. Keller was the President and a co-founder of Myriam Corp.,
an architectural design and real estate development firm beginning in 1976,
until it was reorganized as Barrett Energy in February 1982.
PAUL M. RADY has been President, Chief Operating Officer, and a director of
the Company since September 1994. The Board of Directors has elected Mr. Rady
to serve as Chief Executive Officer effective as of July 1, 1997, at which
time William J. Barrett will retire as Chief Executive Officer and remain as
Chairman of the Board. Prior to September 1994, Mr. Rady served as Executive
Vice President--Exploration of the Company beginning February 1993. From
August 1990 until July 1992, Mr. Rady served as Chief Geologist for the
Company, and from July 1992 until January 1993 he served as Exploration
Manager for the Company. From July 1980 until August 1990, Mr. Rady served in
various positions with the Denver, Colorado regional office of Amoco
Production Company ("Amoco"), the exploration and production subsidiary of
Amoco Corporation. While with Amoco, Mr. Rady's areas of responsibility
included the Rocky Mountain Basins, Utah-Wyoming Overthrust Belt, offshore
Alaska, Oklahoma, particularly with respect to the Arkoma Basin, and the New
Ventures Group, which concentrated on the western United States.
26
<PAGE>
A. RALPH REED has been an Executive Vice President of the Company since
November 1989 and a director since September 1990. From 1986 to 1989, Mr. Reed
was an independent oil and gas operator in the Mid- Continent region of the
United States, including the period from January 1988 to November 1989 when he
acted as a consultant to Zenith. From 1982 to 1986, Mr. Reed was President and
Chief Executive Officer of Cotton Petroleum Corporation ("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 October 1993. Mr.
Rodgers served as the President, Chief Operating Officer and a director of
Anadarko Petroleum Corporation ("Anadarko") from 1986 through 1992. Anadarko
is a Houston-based oil and gas exploration and production company. Prior to
1986, Mr. Rodgers was employed in other capacities by Anadarko and Amoco. Mr.
Rodgers taught Petroleum Engineering at the University of Texas in Austin in
1958 and at Texas Tech University in Lubbock from 1958 to 1961. Mr. Rodgers
currently serves as a Director of Louis Dreyfus Natural Gas Corporation and as
an advisor to Ural Petroleum Corporation, a privately held exploration and
production company operating exclusively in the former Soviet Union.
PHILIPPE S.E. SCHREIBER has been a director of the Company since November
1985. Mr. Schreiber is an independent lawyer and business consultant who also
is of counsel to the law firm of Walter, Conston, Alexander & Green, P.C. in
New York, New York. Mr. Schreiber has been affiliated with that law firm as
counsel or partner since August 1985. From 1988 to mid-1992, he also was the
Chairman of the Board and a principal shareholder of HSE, Inc., d/b/a
Manhattan Kids Limited, a privately owned corporation involved in catalogue
sales of American made children's clothing in Europe.
HARRY S. WELCH has been a director of the Company since July 1995. Mr. Welch
was a director of Plains from May 1986 to July 1995. Since August 1989, he has
been an attorney in private practice in Houston, Texas. He served as Vice
President and General Counsel of Texas Eastern Corporation from 1988 to July
1989.
JOSEPH P. BARRETT has been a Vice President since March 1995 and has been
with the Company in various positions in the Land Department since 1982.
PETER A. DEA has been Senior Vice President--Exploration of the Company
since June 1996. Mr. Dea served as Exploration Manager beginning August 1995.
Mr. Dea served as Chief Geologist from January 1995 to August 1995 and as
Senior Geologist from February 1994 to January 1995. Mr. Dea served as
President of Nautilus Oil and Gas Company in Denver, Colorado from 1992
through 1993. From 1982 until 1991, Mr. Dea served in various positions with
Exxon Company USA as a Geologist in the Production Department in Corpus
Christi, Texas and as a Senior Geologist and Supervisor in the Exploration
Department in Denver, Colorado. While with Exxon, Mr. Dea's areas of
responsibility included the Rocky Mountain Basins and South Texas Gulf Coast
and new ventures in the Special Trades Unit. Mr. Dea served as adjunct
Professor of Geology at Western State College, Gunnison, Colorado in the
spring semesters of 1980 and 1982.
CLIFFORD S. FOSS, JR. has been Vice President and General Manager of the
Gulf of Mexico Region for the Company since June of 1996 and General Manager
of the Gulf of Mexico Region for the Company since January 1996. Prior to
joining the Company, Mr. Foss served from January 1973 to 1996 in various
positions with Cockrell Oil Corporation as Geologist, District Geologist,
Exploration Manager and Vice President of Exploration and Exploitation. Mr.
Foss's primary areas of responsibility at Cockrell Oil Corporation included
the Gulf Coast and Gulf of Mexico. Prior to January 1973, Mr. Foss served as
an exploration geologist for Cities Services Oil Company in its Gulf of Mexico
Division.
BRYAN G. HASSLER has been Vice-President--Marketing of the Company since
December 1996 and has been with the Company as Director of Marketing since
August 1994. Prior to joining the Company, Mr. Hassler held various positions
with Questar Corporation's exploration and production, pipeline and marketing
groups.
27
<PAGE>
ROBERT W. HOWARD has been Senior Vice President of the Company since March
1992. Mr. Howard served as the Executive Vice President--Finance from December
1989 until March 1992 and served as Vice President-- Finance of the Company
from December 1983 until December 1989. Mr. Howard has been the Treasurer of
the Company since March 1986. During 1982, Mr. Howard was a Manager/Accountant
with Weiss & Co., a certified public accounting firm.
EUGENE A. LANG, JR. has been Senior Vice President and General Counsel of
the Company since September 1995. Mr. Lang served as Senior Vice President,
General Counsel and Secretary of Plains from May 1994 to July 1995, and from
October 1990 to May 1994 he served as Vice President, General Counsel and
Secretary of Plains. From 1986 to 1990 he was an associate with the Houston,
Texas law firm of Vinson & Elkins. From 1984 to 1986, he was General Attorney
and Assistant Secretary of K N. From 1978 to 1984, he was an attorney for K N.
DONALD H. STEVENS has been the Vice President--Corporate Relations and
Capital Markets for the Company since August 1992. From July 1989 until August
1992, Mr. Stevens served as Manager of Corporate and Tax Planning for
Kennecott Corporation, a mining company. From May 1986 until September 1989,
Mr. Stevens served as Corporate Planning Analyst in Corporate Acquisition and
Divestitures for BP America, Inc., formerly The Standard Oil Company. Prior to
May 1986, Mr. Stevens served in various finance, tax and analyst positions
with Seco Energy Corporation and Gulf Oil Corporation, both of which are oil
and gas companies.
MAURICE F. STORM has been Vice President and General Manager of the
Company's Mid-Continent Region 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,
1996, its officers, directors and holders of more than 10% of the Company's
common stock complied with all Section 16(a) filing requirements, with the
following exception: Donald H. Stevens, an executive officer of the Company,
reported on October 25, 1996 on a Form 4, the sale on September 24, 1996 of
3,750 shares. In making these statements, the Company has relied upon the
written representations of its directors and officers.
28
<PAGE>
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 years by the Chief Executive Officer
of the Company and by the four other most highly compensated executive
officers whose compensation exceeded $100,000 during the year ended December
31, 1996. Beginning with the year ended December 31, 1995, the Company changed
its fiscal year end from September 30 to December 31. The figures in the
following table are for each of the one year periods ended December 31, 1996,
1995, and 1994:
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
LONG TERM COMPENSATION
-----------------------------------
AWARDS PAYOUTS
----------------------- --------
RESTRICTED SECURITIES
OTHER ANNUAL STOCK UNDERLYING LTIP ALL OTHER
NAME AND PRINCIPAL FISCAL COMPENSATION AWARD(S) OPTIONS/SARS PAYOUTS COMPENSATION
POSITION YEAR SALARY ($) BONUS $(/1/) ($)(/2/) ($)(/3/) ($)(/4/) (#)(/5/) ($)(/6/)
------------------ ------ ---------- ------------ ------------ ---------- ------------ -------- ------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
William J. Barrett...... 1996 $255,417 $150,000 -0- -0- 100,000 -0- $7,913
Chief Executive 1995 $200,000 -0- -0- -0- -0- -0- $4,680
Officer, and
Chairman of the Board 1994 $200,000 $ 40,000 -0- -0- 100,000 -0- $4,560
Paul M. Rady............ 1996 $206,667 $ 63,000 -0- -0- 52,000 -0- $8,138
President, Chief 1995 $175,000 -0- -0- -0- -0-
Operating -0- $4,680
Officer, and a director 1994 $139,583 $ 30,000 -0- -0- 70,000 -0- $4,247
A. Ralph Reed........... 1996 $207,917 $ 54,000 -0- -0- 40,000 -0- $7,988
Executive Vice 1995 $200,000 -0- -0- -0- -0- -0- $4,680
President--
Operations, and a 1994 $164,583 $ 30,000 -0- -0- 100,000 -0- $4,705
director
J. Frank Keller......... 1996 $155,938 $ 40,000 -0- -0- 19,200 -0- $8,222
Executive Vice 1995 $150,000 -0- -0- -0- -0- -0- $4,560
President,
Chief Financial 1994 $128,750 $ 25,000 -0- -0- 55,000 -0- $3,922
Officer,
Secretary and a
director
Eugene A. Lang, Jr., ... 1996 $141,242 $ 25,000 -0- -0- 9,600 -0- $7,432
Senior Vice President 1995 $138,422 $ 8,000 -0- -0- -0- -0- $1,500
and General 1994 $127,560 -0- -0- -0- 25,460(/8/) -0- $1,500
Counsel(/7/)
</TABLE>
- --------
(1) The dollar value of bonus (cash and non-cash) paid during the year
indicated. In March 1997, cash bonuses were determined by the Compensation
Committee and paid by the Company based upon the Company's performance in
1996. These bonuses included $250,000 paid to Mr. Barrett, $160,000 paid
to Mr. Rady, $120,000 paid to Mr. Reed, $90,000 paid to Mr. Keller, and
$65,000 paid to Mr. Lang.
(2) During the period covered by the Table, the Company did not pay any other
annual compensation not properly categorized as salary or bonus, including
perquisites and other personal benefits, securities or property.
(3) During the period covered by the Table, the Company did not make any award
of restricted stock, including share units.
(4) The sum of the number of shares of common stock to be received upon the
exercise of all stock options granted. See "Option Grants Table".
(5) Except for stock option plans, the Company does not have in effect any
plan that is intended to serve as incentive for performance to occur over
a period longer than one fiscal year.
(6) Represents the Company's matching contribution under the Company's 401(k)
Plan for each named executive officer. The amounts for 1994 and 1995 for
Mr. Lang represent matching contributions under the Plains 401(k) Plan.
(7) Mr. Lang's compensation was paid by Plains during the period from January
1, 1994 through July 18, 1995 when Plains merged with a subsidiary of the
Company.
(8) Consists of options to purchase 25,460 shares of common stock of Plains
that became options to purchase 33,097 shares of common stock of the
Company upon the merger of Plains with a subsidiary of the Company.
29
<PAGE>
OPTION GRANTS IN LAST FISCAL YEAR
No stock appreciation rights were granted to any executive officers or
employees in the year ended December 31, 1996. The following table provides
information on stock option grants in the year ended December 31, 1996 to the
named executive officers.
OPTION GRANTS IN LAST FISCAL YEAR
<TABLE>
<CAPTION>
INDIVIDUAL GRANTS
----------------------------------------------
NUMBER OF % OF TOTAL
SECURITIES OPTIONS
UNDERLYING GRANTED TO
OPTIONS EMPLOYEES EXERCISE POTENTIAL REALIZABLE VALUE
GRANTED IN FISCAL PRICE EXPIRATION ---------------------------
NAME (#) YEAR ($/SHARE) DATE 5% 10%
---- ---------- ---------- --------- ------------- ------------ --------------
<S> <C> <C> <C> <C> <C> <C>
William J. Barrett...... 100,000(1) 14.13% $23.125 March 5, 2003 $ 942,119 $ 2,194,882
Paul M. Rady............ 52,000(2) 7.35% $23.125 March 5, 2003 $ 489,901 $ 1,141,338
A. Ralph Reed........... 40,000(2) 5.65% $23.125 March 5, 2003 $ 376,847 $ 877,952
J. Frank Keller......... 19,200(2) 2.71% $23.125 March 5, 2003 $ 180,886 $ 421,416
Eugene A. Lang, Jr...... 9,600(2) 1.36% $23.125 March 5, 2003 $ 90,443 $ 210,708
</TABLE>
- --------
(1) Half of these option shares became exercisable on March 5, 1997, and the
balance of these option shares are first exercisable on March 5, 1998.
(2) One-fourth of these option shares became exercisable on March 5, 1997, and
an additional one-fourth of these option shares are first exercisable on
each of March 5, 1998, March 5, 1999 and March 5, 2000.
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, 1996 by the Company's Chief
Executive Officer and the four other most highly compensated executive
officers of the Company whose compensation exceeded $100,000 during the year
ended December 31, 1996 and the fiscal year-end value of unexercised options
held by these persons:
AGGREGATED OPTION EXERCISES
FOR FISCAL YEAR ENDED DECEMBER 31, 1996
AND YEAR-END OPTION VALUES (1)
<TABLE>
<CAPTION>
NUMBER OF SECURITIES
UNDERLYING UNEXERCISED VALUE OF UNEXERCISABLE
OPTIONS AT FISCAL YEAR- IN-THE-MONEY OPTIONS AT
SHARES END(#)(4) FISCAL YEAR-END($)(5)
ACQUIRED ON VALUE REALIZED ------------------------- -------------------------
NAME EXERCISE(2) ($)(3) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
---- ----------- -------------- ----------- ------------- ----------- -------------
<S> <C> <C> <C> <C> <C> <C>
William J. Barrett..... 20,000 $230,000 5,000 150,000 $125,000 $3,370,000
Chief Executive
Officer, and Chairman
of the Board
Paul M. Rady........... -0- -0- 35,000 87,000 $951,500 $1,965,500
President, Chief
Operating Officer, and
a director
A. Ralph Reed.......... 14,952 $347,709 35,048 90,000 $904,454 $2,121,800
Executive Vice
President--Operations
and a director
J. Frank Keller........ -0- -0- 27,500 46,700 $760,600 $1,135,000
Executive Vice
President, Chief
Financial Officer,
Secretary, and a
director
Eugene A. Lang, Jr. ... 3,750 $ 45,825 40,860 9,600 $981,347 $ 187,200
Senior Vice President
and General Counsel
</TABLE>
30
<PAGE>
- --------
(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 fiscal
year ended December 31, 1996.
(3) With respect to options exercised during the Company's fiscal year ended
December 31, 1996, 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, 1996,
separated between those options that were exercisable and those options
that were not exercisable.
(5) For all unexercised options held as of December 31, 1996, 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, 1996. As
required, the price used to calculate these figures was the closing sale
price of the common stock at year's end, which was $42.625 per share on
December 31, 1996. On March 20, 1997, the closing sale price was $34.00
per share.
EMPLOYEE RETIREMENT PLANS, LONG-TERM INCENTIVE PLANS, AND PENSION PLANS
The Company has an employee retirement plan (the "401(k) Plan") that
qualifies under Section 401(k) of the Internal Revenue Code of 1986, as
amended. Employees of the Company are entitled to contribute to the 401(k)
Plan up to 15 percent of their respective salaries. For each pay period
through March 31, 1996, the Company contributed on behalf of each employee 50
percent of the contribution made by that employee, up to a maximum
contribution by the Company of three percent of that employees gross salary
for that pay period. Effective April 1, 1996, the Company's matching
contribution increased to 100 percent of each participating employee's
contribution, up to a maximum of six percent of base salary, with one-half of
the match paid in cash and one-half of the match paid in the Company's common
stock. The Company's match is subject to a vesting schedule. Benefits payable
to employees upon retirement are based on the contributions made by the
employee under the 401(k) Plan, the Company's matching contributions, and the
performance of the 401(k) Plans 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 $750 meeting attendance fee. Effective March 5, 1996, each Outside
Director receives $200 for each telephone meeting lasting more than 15
minutes. Effective April 1, 1997, the meeting attendance fee was increased to
$1,000, and the fee for telephone meetings lasting more than 15 minutes was
increased to $300. Also effective April 1, 1997, the Chairman of the
Compensation and Audit Committees will receive 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 500 shares of
common stock become exercisable. Although these options become exercisable
only at the rate of 500 for each meeting attended, each director will be
granted options to purchase 10,000 shares at the time the person initially
becomes a director. (The Board of Directors has approved, and recommended for
stockholder approval, amendments to the Non-Discretionary Stock Option Plan.
If the stockholders approve the proposed amendments to the Non-Discretionary
Stock Option Plan, options thereunder will become exercisable at the rate of
1,000 shares for each meeting attended.) 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,
31
<PAGE>
options to purchase an additional 10,000 shares will be granted to the
director and will be subject to the 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 fiscal year ended December 31, 1996, no
compensation was paid to directors of the Company other than pursuant to the
standard compensation arrangements described in the previous section.
EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT AND CHANGE-IN-CONTROL
ARRANGEMENTS
The Company does not have any written employment contracts with respect to
any of the executive officers named in the Summary Compensation Table, except
for Mr. Lang. Mr. Lang is a party to an agreement with Plains to which the
Company became bound as a result of the Barrett-Plains merger. That agreement
provides, among other things, that if, within three years after a "change in
control" (as defined in the agreement), Mr. Lang's employment is involuntarily
terminated or is terminated by Mr. Lang for "Good Reason", Mr. Lang is to be
paid a cash amount equal to (a) two times of the higher of (i) his then annual
compensation (including salary, bonuses and incentive compensation) or (ii)
the highest annual compensation (including salary, bonuses and incentive
compensation) paid or payable during any of the three calendar years ending
with the year of his termination, plus (b) an amount equal to any excise taxes
payable by Mr. Lang with respect to these amounts and any excise or income
taxes payable by Mr. Lang as a result of this reimbursement of excise taxes.
"Good Reason" is defined as a reduction in Mr. Lang's compensation or
employment responsibilities, a required relocation outside the greater Denver,
Colorado area or, generally, any conduct that renders Mr. Lang unable to
discharge his employment duties effectively. This agreement terminates on July
18, 1998. The Company has no other compensatory plan or arrangement that
results or will result from the resignation, retirement, or any other
termination of the employment with the Company and its subsidiaries of the
executive officers named in the Summary Compensation Table or from a change-
in-control of the Company or a change in such an executive officers
responsibilities following a change-in-control, except that (i) in January
1994, the Board of Directors approved a resolution allowing all options
outstanding under the Companys 1990 Stock Option Plan to become exercisable if
an announcement is made concerning a business combination with the Company;
and (ii) in September 1994, the Compensation Committee committed to Mr. Reed
that all stock options that had been granted to him as of September 10, 1994
would become exercisable upon termination of his employment provided that he
remains in the employment of the Company continuously until September 10,
1997, and further provided that the Compensation Committee, or its successor,
determines as of the date of his termination that his employment performance
has satisfied the Companys employment standards for executive officers.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
During the year ended December 31, 1996, each of C. Robert Buford, Derrill
Cody, James M. Fitzgibbons, Hennie L.J.M. Gieskes, James T. Rodgers, Philippe
S.E. Schreiber, and Harry S. Welch served as members of the Compensation
Committee of the Board of Directors. Mr. Schreiber served as the President of
Excel Energy Corporation ("Excel") prior to the 1985 merger of Excel with and
into the Company, and Mr. Gieskes served as Chairman of the Board of Excel at
the time of the merger 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, 1996 was, during that year, an officer or employee of the Company
or of any of its subsidiaries, or was formerly an officer of the Company or of
any of its subsidiaries. For a description of transactions involving Mr.
Buford and the Company, please see "Item 13. Certain Relationships and Related
Transactions".
32
<PAGE>
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table summarizes certain information as of March 20, 1997 with
respect to the ownership by each director, by each executive officer named in
the "Executive Compensation" section above, by all executive officers and
directors as a group, and by each other person known by the Company to be the
beneficial owner of more than five percent of the common stock:
<TABLE>
<CAPTION>
NAME OF AMOUNT/NATURE OF PERCENT OF CLASS
BENEFICIAL OWNER BENEFICIAL OWNERSHIP BENEFICIALLY OWNED
---------------- -------------------- ------------------
<S> <C> <C>
William J. Barrett................ 410,211 Shares(1) 1.3%
C. Robert Buford.................. 653,366 Shares(2) 2.1%
Derrill Cody...................... 13,560 Shares(3) *
James M. Fitzgibbons.............. 11,500 Shares(3) *
Hennie L.J.M. Gieskes............. 899,214 Shares(3) 2.9%
William W. Grant, III............. 26,150 Shares(3) *
J. Frank Keller................... 82,658 Shares(3) *
Eugene A. Lang, Jr................ 49,873 Shares(3) *
Paul M. Rady...................... 87,152 Shares(3) *
A. Ralph Reed..................... 91,158 Shares(4) *
James T. Rodgers.................. 12,000 Shares(3) *
Philippe S.E. Schreiber........... 20,507 Shares(3) *
Harry S. Welch.................... 19,800 Shares(3) *
All Directors and Executive
Officers as a Group (20
persons)......................... 2,476,119 Shares(5) 7.8%
Fidelity Management and Research
Corporation...................... 3,163,660 Shares(6) 10.1%
82 Devonshire Street
Boston, MA 02109
State Farm Mutual Automobile
Insurance Company and affiliates.. 2,278,233 Shares(6)(7) 7.3%
One State Farm Plaza
Bloomington, IL 61710
</TABLE>
- --------
* Less than 1% of the common stock outstanding.
(1) The number of shares indicated includes 36,292 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 62.92294
percent of the partnership interests, and 75,000 shares underlying options
that currently are exercisable or become exercisable within the next 60
days. Pursuant to Rule 16a-1(a)(4) under the Securities Exchange Act of
1934 (the "1934 Act"), Mr. Barrett disclaims ownership of all but 144,723
shares held by the Barrett Family L.L.L.P., which constitutes Mr. and Mrs.
Barrett's proportionate share of the shares held by the Barrett Family
L.L.L.P.
(2) C. Robert Buford is considered a beneficial owner of the 598,210 shares of
which Zenith is the record owner. Mr. Buford owns approximately 89 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 1934
Act. The number of shares indicated also includes 11,500 shares underlying
stock options are currently exercisable or that become exercisable within
the next 60 days.
(3) The number of shares indicated consists of or includes the following
number of shares underlying options that currently are exercisable or that
become exercisable within the next 60 days that are held by each of the
following persons: Derrill Cody, 13,300; James M. Fitzgibbons,9,500;
Hennie L.J.M. Gieskes, 10,000; William W. Grant, III, 16,400; J. Frank
Keller, 40,900; Eugene A. Lang, Jr., 43,259; Paul M. Rady, 57,000; James
T. Rodgers, 12,000; Philippe S.E. Schreiber, 10,500; and Harry S. Welch,
17,200.
(4) The number of shares indicated includes 10,150 shares owned by Mary C.
Reed, Mr. Reed's wife and 55,848 shares underlying options that currently
are exercisable or that become exercisable within the next 60 days.
33
<PAGE>
(5) The number of shares indicated includes the shares owned by Zenith that
are beneficially owned by Mr. Buford as described in note (2) and the
aggregate of 372,407 shares underlying the options described in notes (1),
(2), (3) and (4), an aggregate of 25,170 shares owned by seven executive
officers not named in the above table, and an aggregate of 73,800 shares
underlying options that currently are exercisable or that are exercisable
within 60 days that are held by those seven executive officers.
(6) Based on information included in a Schedule 13G filed with the Securities
and Exchange Commission by the named stockholders and from information
obtained from other sources.
(7) The number of shares indicated includes the shares owned by entities
affiliated with State Farm Mutual Automobile Insurance Company ("SFMAI").
Those entities and SFMAI may be deemed to constitute a "group" with regard
to the ownership of shares reported on a Schedule 13G under the Securities
Exchange Act of 1934, as amended.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
On April 10, 1996, the Company acquired all the Piceance Basin oil and gas
interests of Zenith for $2.7 million, and the Company, through a merger of GVC
into a subsidiary company, acquired all the stock of GVC in exchange for
350,000 shares of the Company's common stock. These transactions were
effective March 1, 1996. Pursuant to the respective agreements with Zenith and
GVC, Zenith and the shareholders of GVC are responsible for liabilities that
accrue on or before March 1, 1996 and the Company is responsible for
liabilities accruing after March 1, 1996.
The terms of these transactions were negotiated with Zenith and GVC by a
Special Committee of the Board of Directors of the Company consisting of
William W. Grant, III, James T. Rodgers, Philippe S.E. Schreiber, and Harry S.
Welch, each of whom is an outside director. The Company obtained an opinion
from an investment banking firm that the terms of these transactions were fair
to the Company.
Prior to the Company's acquisition of these interests as described above,
Zenith owned a working interest in many of the leases for which the Company is
the operator. For the period from January 1, 1996 through the effective date
of the acquisition, Zenith paid to the Company, as operator, approximately
$77,000 as Zenith's portion of the lease operating expenses and development
costs for those leases. Also as a result of its working interest, which ranged
from three to 50 percent in leases for which the Company is the operator,
Zenith received approximately $448,000 as its share of revenues. All terms and
arrangements between Zenith and the Company with respect to these working
interests are the same as those between the Company and the other working
interest owners in the leases. Zenith is 89 percent owned by Mr. Buford.
Mr. Buford also was a director of GVC which owned a 10.4 percent interest in
the pipeline gathering system and related facilities on the Company's Grand
Valley Gathering System. Until acquired by the Company, as described above,
ten percent of GVC was owned by Mr. Buford, and 90 percent of GVC was owned by
Mr. Buford's three adult children. From January 1, 1996, the effective date of
the acquisition, GVC's proportionate share of the pipeline gathering system's
expenses, not including depreciation, was approximately $33,000, and its share
of the pipeline gathering system's revenues was approximately $101,000. All
terms and arrangements between GVC and the Company with respect to this
gathering system are the same as those between the Company and the other
owners of the gathering system.
34
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL SCHEDULES, AND REPORTS ON FORM 8-K
(a)(1) and (a)(2) Financial Statements And Financial Statement Schedules
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
<TABLE>
<S> <C>
Report Of Independent Public Accountants.............................. F-1
Consolidated Balance Sheets at December 31, 1996 and 1995............. F-2
Consolidated Statements of Income for each of the three years in the
period ended December 31, 1996....................................... F-3
Consolidated Statements of Stockholders' Equity for each of the three
years in the period ended December 31, 1996.......................... F-4
Consolidated Statements of Cash Flows for each of the three years in
the period ended December 31, 1996................................... F-5
Notes to the Consolidated Financial Statements........................ F-6
Supplemental Oil And Gas Information.................................. F-21
</TABLE>
All other schedules are omitted because the required information is not
present in amounts sufficient to require submission of the schedule or because
the information required is included in the Consolidated Financial Statements
and Notes thereto.
(a)(3) Exhibits
See "EXHIBIT INDEX" on page 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, 1996. During the period from
January 1, 1997 through March 20, 1997, the Company filed three Current
Reports on Form 8-K reporting events that occurred on January 8, 1997,
February 7, 1997, and February 13, 1997, respectively.
35
<PAGE>
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT
-------
<C> <S>
2.1 Agreement And Plan of Merger, dated as of May 2, 1995, among Barrett
Resources Corporation ("Barrett" or "Registrant"), Barrett Energy Inc.
(formerly known as Vanilla Corporation), and Plains Petroleum Company
("Plains") is incorporated by reference from Annex I to the Joint
Proxy Statement/Prospectus of Barrett and Plains dated June 13, 1995.
3.1 Restated Certificate Of Incorporation of Barrett Resources
Corporation, a Delaware corporation, is incorporated herein by
reference from Exhibit 3.2 of Registrant's Registration Statement on
Form S-4 dated June 9, 1995.
3.6 Bylaws of Barrett, as amended, are incorporated herein by reference
from Exhibit 3.3 of Registrant's Registration Statement on Form S-4
dated June 9, 1995.
10.1 Non-Qualified Stock Option Plan Of Barrett Resources Corporation is
incorporated by reference from Registrant's Registration Statement on
Form S-8 dated November 15, 1989.
10.2 Registrant's 1990 Stock Option Plan, as amended, is incorporated by
reference from the Registrant's Registration Statement on Form S-8
dated March 15, 1995.
10.3 Registrant's Non-Discretionary Stock Option Plan is incorporated by
reference from Registrant's Annual Report on Form 10-K for the year
ended September 30, 1991.
10.4 1994 Stock Option Plan, as amended, is incorporated by reference from
the Registrant's Registration Statement on Form S-8 dated March 15,
1995.
10.5A Gas Purchase Contract, No. P-1090, dated April 20, 1984, as amended,
between Plains and KN Energy, Inc. is incorporated by reference from
Plains Petroleum Company's Registration Statement on Form 10 dated
August 21, 1985.
10.5B Letter Agreement dated December 19, 1996, amending the Gas Purchase
Contract, No. P-1090, dated April 20, 1984, between Plains and KN
Energy, Inc.
10.6A Revolving Credit Agreement dated as of July 19, 1995 among Barrett and
Texas Commerce Bank National Association, as Agent, and Texas Commerce
Bank National Association, Nations Bank of Texas, N.A., Bank of
Montreal, Houston Agency, Colorado National Bank, and The First
National Bank of Boston, as the "Banks" is incorporated by reference
from Exhibit 10.6 to Barrett's Annual Report on Form 10-K for the year
ended December 31, 1996.
10.6B First Amendment to Revolving Credit Agreement dated October 31, 1996
between and among Barrett, Agent and the Banks is incorporated by
reference from Exhibit 10.1 to Amendment No. 2 to Barrett's
Registration Statement on Form S-3 (File No. 333 -19363) dated
February 10, 1997.
10.6C Second Amendment to Revolving Credit Agreement dated February 10, 1997
between and among Barrett, the Agent, and the Banks is incorporated by
reference from Exhibit 10.2 to Amendment No. 2 to Barrett's
Registration Statement on Form S-3 (File No. 333 -19363) dated
February 10, 1997.
21 List of Subsidiaries.
23 Consent of Arthur Andersen LLP.
27 Financial Data Schedule.
</TABLE>
36
<PAGE>
REPORT OF ARTHUR ANDERSEN LLP
INDEPENDENT PUBLIC ACCOUNTANTS
The Board of Directors
Barrett Resources Corporation
Denver, Colorado 80202
We have audited the accompanying consolidated balance sheets of Barrett
Resources Corporation (a Delaware corporation) and subsidiaries as of December
31, 1996 and 1995, and the related consolidated statements of income,
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 1996. 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, 1996 and 1995, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 1996, in conformity with generally accepted
accounting principles.
Arthur Andersen LLP
Denver, Colorado
February 28, 1997
F-1
<PAGE>
BARRETT RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1996 AND 1995
(IN THOUSANDS)
<TABLE>
<CAPTION>
1996 1995
-------- --------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents................................. $ 14,539 $ 7,529
Receivables, net.......................................... 73,045 31,089
Inventory................................................. 947 554
Other current assets...................................... 1,156 574
-------- --------
Total current assets.................................... 89,687 39,746
Net property and equipment (full cost method)............... 487,258 300,666
-------- --------
$576,945 $340,412
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable.......................................... $ 41,617 $ 14,369
Amounts payable to oil and gas property owners............ 18,496 8,874
Production taxes payable.................................. 13,830 8,047
Accrued and other liabilities............................. 4,374 4,770
-------- --------
Total current liabilities............................... 78,317 36,060
Long term debt.............................................. 70,000 89,000
Deferred income taxes....................................... 50,908 23,524
Commitments and contingencies--Note 10
Stockholders' equity:
Preferred stock, $.001 par value: 1,000,000 shares
authorized, none outstanding............................. -- --
Common stock, $.01 par value: 35,000,000 shares
authorized, 31,330,361 outstanding (25,092,246 at
December 31, 1995)....................................... 313 251
Additional paid-in capital................................ 241,991 86,154
Retained earnings......................................... 135,416 105,890
Treasury stock, at cost................................... -- (467)
-------- --------
Total stockholders' equity.............................. 377,720 191,828
-------- --------
$576,945 $340,412
======== ========
</TABLE>
See accompanying notes.
F-2
<PAGE>
BARRETT RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
Revenues:
Oil and gas production.......................... $151,737 $ 96,996 $ 78,794
Trading revenues................................ 46,862 28,554 28,114
Revenue from gas gathering...................... 2,654 1,074 353
Interest income................................. 760 714 864
Other income.................................... 559 678 1,333
-------- -------- --------
202,572 128,016 109,458
Operating expenses:
Lease operating expenses........................ 47,642 34,525 28,223
Depreciation, depletion and amortization........ 45,775 33,480 22,760
Cost of trading................................. 44,036 27,611 27,190
General and administrative...................... 16,947 13,426 13,261
Interest expense................................ 3,684 4,631 942
Other expenses, net............................. -- 588 645
Merger and reorganization expense............... -- 14,161 --
-------- -------- --------
158,084 128,422 93,021
-------- -------- --------
Income (loss) before income taxes................. 44,488 (406) 16,437
Provision for income taxes........................ 14,962 1,834 5,138
-------- -------- --------
Net income (loss)................................. $ 29,526 $ (2,240) $ 11,299
======== ======== ========
Net income (loss) per common share and common
share equivalent................................. $ 1.02 $ (.09) $ .46
======== ======== ========
</TABLE>
See accompanying notes.
F-3
<PAGE>
BARRETT RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
(IN THOUSANDS)
<TABLE>
<CAPTION>
ADDITIONAL TOTAL
COMMON PAID-IN TREASURY RETAINED STOCKHOLDERS'
STOCK CAPITAL STOCK EARNINGS EQUITY
------ ---------- -------- -------- -------------
<S> <C> <C> <C> <C> <C>
Balance, January 1, 1994.... $246 $ 78,210 $(204) $100,358 $178,610
Exercise of stock
options.................. 1 970 (313) -- 658
Purchase of treasury
stock.................... -- -- (78) -- (78)
Retirement of treasury
stock.................... -- (552) 552 -- --
Cash dividends--Plains
common stock............. -- -- -- (2,353) (2,353)
Net income for the year
ended December 31, 1994.. -- -- -- 11,299 11,299
---- -------- ----- -------- --------
Balance, December 31, 1994.. 247 78,628 (43) 109,304 188,136
Exercise of stock
options.................. 4 7,690 (588) -- 7,106
Retirement of treasury
stock.................... (164) 164 -- --
Cash dividends--Plains
common stock............. -- -- -- (1,174) (1,174)
Net loss for the year
ended December 31, 1995.. -- -- -- (2,240) (2,240)
---- -------- ----- -------- --------
Balance, December 31, 1995.. 251 86,154 (467) 105,890 191,828
Exercise of stock
options.................. 2 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
==== ======== ===== ======== ========
</TABLE>
See accompanying notes.
F-4
<PAGE>
BARRETT RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
(IN THOUSANDS)
<TABLE>
<CAPTION>
1996 1995 1994
--------- -------- --------
<S> <C> <C> <C>
Cash flows from operations:
Net income (loss).............................. $ 29,526 $ (2,240) $ 11,299
Adjustments needed to reconcile to net cash
flow provided by operations:
Depreciation, depletion and amortization...... 45,775 33,480 22,760
Unrealized (gain) loss on trading............. (1,139) 1,139 58
Deferred income taxes......................... 13,655 1,798 4,788
Other......................................... -- (787) 70
--------- -------- --------
87,817 33,390 38,975
Change in current assets and liabilities:
Receivables................................... (41,956) 3,433 (8,436)
Other current assets.......................... (582) 525 (148)
Accounts payable.............................. 27,248 (524) 6,803
Amounts due oil and gas owners................ 9,622 (2,725) 623
Production taxes payable...................... 5,783 -- --
Accrued and other liabilities................. 742 1,439 (1,244)
--------- -------- --------
Net cash flow provided by operations............ 88,674 35,538 36,573
--------- -------- --------
Cash flows from investing activities:
Proceeds from sales of oil and gas properties.. 1,948 504 458
Short-term investments, net.................... -- -- 3,968
Acquisitions of property and equipment......... (202,610) (82,758) (95,589)
Other.......................................... -- -- 146
--------- -------- --------
Net cash flow used in investing activities...... (200,662) (82,254) (91,017)
--------- -------- --------
Cash flows from financing activities:
Proceeds from issuance of common stock, net.... 138,349 7,071 301
Purchase of treasury stock..................... (351) -- (78)
Borrowing under line of credit................. 91,000 115,000 44,000
Payments on line of credit..................... (110,000) (79,000) (4,500)
Dividends paid................................. -- (1,174) (2,353)
Other.......................................... -- -- (147)
--------- -------- --------
Net cash flow provided by financing activities.. 118,998 41,897 37,223
--------- -------- --------
Increase (decrease) in cash and cash
equivalents.................................... 7,010 (4,819) (17,221)
Cash and cash equivalents at beginning of year.. 7,529 12,348 29,569
--------- -------- --------
Cash and cash equivalents at end of year........ $ 14,539 $ 7,529 $ 12,348
========= ======== ========
</TABLE>
See accompanying notes.
F-5
<PAGE>
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Business
Barrett Resources Corporation (the "Company") is an independent natural gas
and oil exploration and production company with producing properties located
in the mid-continent states and Rocky Mountain region of the United States.
Barrett also operates gas gathering systems and related facilities in certain
areas in which the Company owns production. In addition, Barrett 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 and development project
in Peru.
Principles of consolidation
The consolidated financial statements include the accounts of the Company
and its subsidiaries, all of which are wholly-owned. All significant
intercompany transactions have been eliminated in consolidation.
Reclassifications
Certain reclassifications have been made to 1995 and 1994 amounts to conform
to the 1996 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.
F-6
<PAGE>
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
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 development costs of proved reserves but exclude the costs
of unevaluated oil and gas properties. Accumulated depreciation and
amortization is written off as assets are retired. Depletion and amortization
equaled approximately $.59, $.55 and $.52 per Mcfe ($3.54, $3.28 and $3.14 per
BOE) during the years ended December 31, 1996, 1995 and 1994, respectively.
The Company capitalizes interest costs on amounts expended on assets during
the period in which activities are occurring to place the asset in service.
Amounts spent to develop properties included in the full cost center of oil
and gas properties are excluded from the interest capitalization computation.
The Company acquires nonproducing acreage for its exploration and
development activities. The cost of these leases is included in unevaluated
oil and gas property costs recorded at the lower of cost or fair market value.
The Company operates many of the wells in which it owns an economic
interest. The operating agreements for these activities provide for a fee
structure to allow the Company to recover a portion of its direct and overhead
charges related to its operating activities. The fees collected under the
operating agreements are recorded as a reduction of general and administrative
expenses. Any amounts collected from a sale of oil and gas interests or earned
as a result of assembling oil and gas drilling activities are applied to
reduce the book value of oil and gas properties.
In 1995, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 121, "Accounting for the Impairment of
Long-Lived Assets to Be Disposed Of" (SFAS No. 121) with an effective date of
January 1, 1996. This pronouncement requires that impairment losses be
recorded on other long-lived assets used in operations when either the
undiscounted future cash flows estimated to be generated by those assets or
the fair market value are less than the assets net book value. Oil and gas
properties accounted for using the full cost method of accounting, a method
utilized by the Company, are excluded from this requirement, but will continue
to be subject to the ceiling test limitations.
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 buying and selling of natural gas.
The Company recognizes revenue and costs on gas trading transactions at the
point in time when gas is delivered to the purchaser.
The Company uses both commodity futures contracts and price swaps to hedge
the impact of price fluctuations on a portion of its production and trading
activities. The Company enters into a hedging position for
F-7
<PAGE>
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
specific transactions that management deems expose the Company to an
unacceptable market price risk. Price swaps or commodities transactions
without corresponding scheduled physical transactions (scheduled physical
transactions include committed trading activities or production from producing
wells) do not qualify for hedge accounting. The Company classifies these
positions as trading positions and records these instruments at fair value.
Gains and losses are recognized as fair values fluctuate from time to time
compared to cost.
Gains or losses on hedging transactions are deferred until the physical
transaction occurs for financial reporting purposes. Deferred gains and losses
and unrealized gains and losses are evaluated in connection with the physical
transaction underlying the hedge position. Hedging gains or losses
significantly exceeding the price movement of the underlying physical
transaction are recorded in the consolidated statements of income in the
period in which the lack of correlation occurred. Gains or losses on hedging
activities are recorded in the consolidated statements of income as
adjustments of the revenue or cost of the underlying physical transaction.
Hedging transactions are reported as operating activities in the consolidated
statements of cash flows.
Earnings per share
Per share amounts were computed using the weighted average number of shares
of common stock and common stock equivalents outstanding during each year:
1996--28,820,000; 1995--24,931,000; and 1994--24,967,000. Options to purchase
stock are included as common stock equivalents, when dilutive, using the
treasury stock method.
Change in fiscal year
On July 18, 1995, the Company changed its fiscal year-end from September 30
to December 31. A transition report for the period October 1, 1994 through
December 31, 1994 was filed with the Securities and Exchange Commission.
During the three months ended December 31, 1994, the Company reported revenues
of $15 million and net income of $207,000.
2. MERGER
On July 18, 1995 Plains Petroleum Company ("Plains") was merged with and
into a subsidiary of the Company, resulting in Plains becoming a wholly owned
subsidiary of the Company. Approximately 12.8 million shares of the Company's
common stock were issued in exchange for all of the outstanding common stock
of Plains. Additionally, outstanding options to acquire Plains common stock
were converted to options to acquire approximately 593,000 shares of the
Company's common stock. In connection with the merger, the Company's
authorized number of shares of common stock was increased to 35 million
shares. The merger was accounted for as a pooling of interests, and
accordingly, the accompanying financial statements have been restated to
include the accounts and operations of Plains for all periods prior to the
merger.
Plains used the successful efforts method of accounting for its oil and gas
exploration and development activities. In conjunction with the merger, Plains
adopted the full cost method used by the Company resulting in increases of net
property and equipment due to the capitalization of exploration costs,
reversal of impairment and adjustments of depreciation, depletion and
amortization expense for periods prior to the merger. The financial statements
for 1994 have been retroactively restated for the change in accounting method
which resulted in increased net income. Retained earnings and deferred income
taxes have been adjusted for the effect of the retroactive application of the
new method.
In connection with the merger, approximately $14.2 million of merger and
reorganization costs and expenses were incurred and have been charged to
expense in the Company's third and fourth quarters of fiscal 1995. These
nonrecurring costs and expenses consist of (1) investment banker and
professional fees of $7.4
F-8
<PAGE>
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
million; (2) severance and employee benefit costs of $5.6 million for
approximately 38 employees, terminated through consolidation of administrative
and operational functions; (3) a non-cash credit of approximately $.9 million
associated with the termination of Plains postretirement benefit plans and
other related benefit plans and (4) other merger and reorganization related
costs of $2.1 million.
3. RECEIVABLES
<TABLE>
<CAPTION>
1996 1995
------- -------
(IN THOUSANDS)
<S> <C> <C>
Oil and gas revenue and trading receivables................. $48,161 $21,200
Joint interest billings..................................... 21,497 7,652
Other accounts receivable................................... 3,387 2,237
------- -------
$73,045 $31,089
======= =======
</TABLE>
The Company's accounts receivable are primarily due from medium size oil and
gas entities in the Rocky Mountain region. Collection of joint interest
billings is generally secured by future production. The Company performs
periodic credit evaluations of customers purchasing production for which no
collateral is required. Historically, the Company has not experienced
significant losses related to these extensions of credit.
As of December 31, 1996 and 1995, receivables are recorded net of allowance
for doubtful accounts of $229,000 and $201,000, respectively.
4. PROPERTY AND EQUIPMENT
<TABLE>
<CAPTION>
1996 1995
-------- --------
(IN THOUSANDS)
<S> <C> <C>
Oil and gas properties, full cost method:
Unevaluated costs, not being amortized................. $ 82,126 $ 10,579
Evaluated costs........................................ 563,068 420,388
Gas gathering systems.................................. 28,219 13,168
Furniture, vehicles and equipment........................ 8,487 5,844
-------- --------
681,900 449,979
Less accumulated depreciation, depletion, amortization
and impairment.......................................... 194,642 149,313
-------- --------
$487,258 $300,666
======== ========
</TABLE>
The Company capitalized interest costs of $8,000 and $403,000 in 1996 and
1995, respectively, associated with qualifying properties. Total interest
costs incurred after recognition of the capitalized interest amount were $3.7
million and $4.6 million in 1996 and 1995, respectively.
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:
<TABLE>
<CAPTION>
COSTS INCURRED DURING
------------------------------------------------
1996 1995 1994 PRIOR PERIODS TOTAL
------- ------ ------ ------------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Acquisition costs
United States.................... $46,810 $5,623 $125 $14 $52,572
Peru............................. 1,229 -- -- -- 1,229
Exploration costs
United States.................... 27,908 417 -- -- 28,325
------- ------ ------ -------------- -------
$75,947 $6,040 $125 $14 $82,126
======= ====== ====== ============== =======
</TABLE>
F-9
<PAGE>
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
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
The Company has a reserve-based line of credit with a group of banks which
provides up to $200 million, maturing October 31, 2000. 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, 1996 (which was
based on the June 30, 1996 reserve report), the Company's borrowing limit was
$205 million. In connection with the sale of senior notes described below, the
borrowing base was limited to $75 million until May 1, 1997. The lenders are
currently reviewing the December 31, 1996 reserve report to determine current
collateral value at which time the borrowing base could increase. The Company
is required to pay interest only during the revolving period. At its option,
the Company has elected to use the London interbank eurodollar rate (LIBOR)
plus a spread ranging from .5 percent to 1.0 percent (depending on the
Company's borrowing relative to its borrowing base) for a substantial portion
of the outstanding balance. As of December 31, 1996 the Company's outstanding
balance under the line of credit was $70 million of which $55 million was
accruing interest at an average LIBOR based rate of 6.03 percent and $15
million was accruing interest on a prime based rate of 8.25 percent. 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. Based on the variable
borrowing rates and re-pricing terms currently available to the Company for
the line of credit, management believes the fair value of long-term debt
approximates the carrying value.
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 in full the balance of
$85 million of the Company's existing line of credit. The Notes are senior
unsecured obligations of the Company ranking equally in right of payment to
all existing and future senior indebtedness of the Company. At the option of
the Company, the Notes may be redeemed at any time, in whole or in part, by
paying an amount specified for a make-whole premium. The indenture of the
Notes limits the Company's ability to incur indebtedness secured by certain
liens, engage in certain sale/leaseback transactions, and engage in certain
merger, consolidation or reorganization transactions. Interest will be paid
semi-annually on February 1 and August 1 of each year, beginning August 1,
1997.
7. COMMON STOCK AND OPTIONS
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 two employee stock option plans, a 1990 Plan and a 1994
Plan, under which the Company's common stock may be granted to officers and
employees of the Company and subsidiaries. The 1990 Plan 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. In addition, the Company has a non-discretionary stock
option plan, as amended, under which options for an aggregate of 200,000
shares of the Company's common stock may be granted to non-employee directors.
In connection with the merger discussed in Note 2, the Company assumed
preexisting 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.
F-10
<PAGE>
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
The exercise price of each option is equal to the market price of the
Company's stock on the date of grant. Options generally become exercisable in
equal installments on each of the first four anniversaries of the date of
grant. The options expire, to the extent not exercised, between two and ten
years after the date of the grant, or within 30 days 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 equal market price at time of grant. Had compensation cost for these
plans 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:
<TABLE>
<CAPTION>
FOR THE YEAR ENDED
DECEMBER 31,
-------------------
1996 1995
--------- ---------
(IN THOUSANDS)
<S> <C> <C>
Net income (loss)
As reported.......................................... $ 29,526 $ (2,240)
Pro forma............................................ 27,277 (2,485)
Net income (loss) per share
As reported.......................................... $ 1.02 $ (.09)
Pro forma............................................ .95 (.10)
</TABLE>
Changes in outstanding stock options under these plans are summarized as
follows:
<TABLE>
<CAPTION>
1996 1995 1994
-------------------- -------------------- --------------------
WEIGHTED- WEIGHTED- WEIGHTED-
NUMBER OF AVERAGE NUMBER OF AVERAGE NUMBER OF AVERAGE
OPTION EXERCISE OPTION EXERCISE OPTION EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning
of year................ 986,546 $16.89 1,359,791 $16.06 929,111 $15.06
Granted................. 727,600 28.59 110,000 22.69 585,500 14.62
Exercised............... (230,897) 17.72 (425,969) 14.70 (141,820) 4.63
Forfeited............... (1,690) 23.96 (57,276) 24.48 (13,000) 4.25
--------- --------- ---------
Outstanding at end of
year................... 1,481,559 22.50 986,546 16.89 1,359,791 16.06
========= ========= =========
Options exercisable at
year end............... 392,959 417,121 721,041
Weighted-average fair
value of options
granted during the
year................... $ 17.74 $ 14.23
</TABLE>
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:
dividend yield of nil, expected volatility of 69.54 percent, risk-free
interest rates of 6.44 percent and 6.68 percent for 1996 and 1995
respectively, and expected lives of 4.9 years.
F-11
<PAGE>
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
The following table summarizes information about stock options outstanding
at December 31, 1996:
<TABLE>
<CAPTION>
STOCK OPTIONS OUTSTANDING STOCK OPTIONS EXERCISABLE
---------------------------------- ----------------------------
WEIGHTED-
AVERAGE WEIGHTED- WEIGHTED-
NUMBER REMAINING AVERAGE NUMBER AVERAGE
RANGE OF OUTSTANDING CONTRACTUAL EXERCISE EXERCISABLE EXERCISE
EXERCISE PRICES AT 12/31/96 LIFE PRICE AT 12/31/96 PRICE
- --------------- ----------- ------------ --------- ------------- ------------
<S> <C> <C> <C> <C> <C>
$ 5-16 346,996 2.17 $12.59 150,946 $ 11.92
16-21 299,064 3.82 18.74 186,114 18.83
21-30 579,499 5.66 24.56 55,399 24.00
30-43 256,000 6.71 35.67 500 37.50
--------- -------
1,481,559 22.50 392,959 16.92
========= =======
</TABLE>
8. RETIREMENT BENEFITS
The Company has a voluntary 401(k) employee savings plan. Under this plan,
as amended, the Company matches 100% of each of the participating employees
contributions, up to a maximum of 6% of base salary, with one-half of the
match paid in cash and one-half of the match paid in the Company's common
stock. Prior to April 1, 1996, the Company matched 50% of each of the
participating employees contributions, up to a maximum of 6% of base salary.
The employee's rights to the Company's matching contributions are subject to a
vesting schedule. Company contributions were $341,000, $239,000 and $179,000
in 1996, 1995 and 1994, respectively.
Plains had several employee benefit plans. Pursuant to the terms of the
merger agreement between Plains and the Company, these plans were terminated
in 1995 and plan assets were distributed to the participants as described
below. Plains defined benefit, profit-sharing and matching 401-K contributions
totaled $281,000 and $838,000 for the 1995 and 1994 plan years, respectively.
The Plains' profit-sharing and 401(k) plans were terminated July 1, 1995 and
the pension plan was terminated September 18, 1995. Internal Revenue Service
approval for termination of these plans was received in January 1996. Final
distribution of plan assets was made to participants during 1996.
Plains' executive deferred compensation plan and directors' deferred plan
permitted the deferral of current salary or directors' fees for the purpose of
providing funds at retirement or death for employees, directors and their
beneficiaries. These plans were terminated effective June 30, 1995. A final
distribution will be made to the participants by the trustee of the assets in
1998. Total accrued liability under these plans at December 31, 1995 was
$36,000.
Concurrently with the effective date of the merger, Plains' postretirement
healthcare benefit and salary continuation plans were terminated. Participants
in the salary continuation plan received (1) a lump sum benefit equal to the
present value of the remaining monthly payments if receiving Death Benefits
under the plan at the date of the termination, or (2) insurance policies, the
cost of which was limited to the cash values of the life insurance policies
owned by Plains. Benefits associated with the postretirement healthcare
benefit plan were terminated and, accordingly, accrued postretirement benefit
costs were relieved.
9. PRODUCTION HEDGING ACTIVITIES
The Company uses swap agreements to reduce the effect of oil and natural gas
price volatility on a portion of its oil and natural gas production. The
objective of its hedging activities is to achieve more predictable
F-12
<PAGE>
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
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.
The following is a summary of the Company's outstanding natural gas swaps in
effect as of December 31, 1996, all of which are associated with its Rocky
Mountain natural gas production:
<TABLE>
<CAPTION>
DURATION VOLUME FIXED PRICE
-------- ---------------- --------------
<S> <C> <C>
January-March 1997.......................... 50,000 MMBTU/day $1.45 to $2.01
April-October 1997.......................... 20,000 MMBTU/day $1.45 to $1.75
Subsequent to December 31, 1996, the Company entered into the following
additional natural gas swaps:
March 1998-February 2003.................... 10,000 MMBTU/day $1.735
March 1998-February 2003.................... 10,000 MMBTU/day $1.75
March 2000-February 2003.................... 5,000 MMBTU/day $1.75
March 2002-February 2003.................... 5,000 MMBTU/day $1.75
</TABLE>
Hedging gains and losses are recorded when the related gas or oil production
has been produced or delivered or the financial instrument expires, and 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, 1996, 1995 and 1994, the Company's gains (losses) under its
production swap agreements were $(5.0) million, $0.4 million and $0.1 million,
respectively. Included in 1995 is a hedging cost of approximately $1.2 million
relating to a portion of the Company's hedging positions at December 31, 1995
which did not qualify for hedge accounting due to reduced correlation between
the index price and the prices to be realized for certain physical gas
deliveries. The unrealized hedging costs were recorded as a liability in 1995
and offset realized hedging costs as the respective hedges were settled in
1996.
10. COMMITMENTS AND CONTINGENCIES
Lease Commitments
The minimum future payments under the terms of operating leases, principally
for office space, are as follows:
<TABLE>
<CAPTION>
(IN THOUSANDS)
<S> <C>
Year ended December 31,
1997.................................................. $1,061
1998.................................................. 1,056
1999.................................................. 959
2000.................................................. 827
2001.................................................. 276
------
$4,179
======
</TABLE>
Total minimum future rental payments have not been reduced by $363,000 of
sublease rentals to be received in the future. Rent expense was $990,000,
$956,000 and $859,000 for the years ended December 31, 1996, 1995 and 1994,
respectively.
F-13
<PAGE>
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
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 a company that was acquired by Plains in 1986. The Company
currently has additional unused net operating loss carryforwards of
approximately $30 million related to the same acquisition.
Management disagrees with the IRS position. In management's opinion, the
federal tax returns of Plains reflect the proper federal income tax liability
and the existing net operating loss carryforwards are appropriate as supported
by relevant authority. The Company will vigorously contest these proposed
adjustments and believes it will prevail in its positions. It is anticipated
that the final determination of this matter will involve a lengthy process.
At December 31, 1996, the Company was a party to certain other legal
proceedings which have arisen out of the ordinary course of business. Based on
the facts currently available, in management's opinion the liability,
individually or in the aggregate, if any, to the Company resulting from such
actions will not have a material adverse effect on the Company's consolidated
financial position or results of operations.
Environmental Controls
At year end 1996, there were no known environmental or other regulatory
matters related to the Company's operations which are reasonably expected to
result in a material liability to the Company. Compliance with environmental
laws and regulations has not had, and is not expected to have, a material
adverse effect on the Company's capital expenditures, earnings or competitive
position.
11. INCOME TAXES
The provision for income taxes consists of the following:
<TABLE>
<CAPTION>
1996 1995 1994
------- ------ ------
(IN THOUSANDS)
<S> <C> <C> <C>
Current:
Federal............................................. $ 513 $ 269 $ 233
State............................................... 794 (233) 117
------- ------ ------
1,307 36 350
Deferred:
Federal............................................. 12,833 2,039 4,511
State............................................... 822 (241) 277
------- ------ ------
13,655 1,798 4,788
------- ------ ------
$14,962 $1,834 $5,138
======= ====== ======
</TABLE>
F-14
<PAGE>
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
The difference between the provision for income taxes and the amounts which
would be determined by applying the statutory federal income tax rate to
income before provision for income taxes is analyzed below:
<TABLE>
<CAPTION>
1996 1995 1994
------- ------ -------
(IN THOUSANDS)
<S> <C> <C> <C>
Tax by applying the statutory federal income tax
rate to pretax accounting income (loss)........ $15,571 $ (138) $ 5,753
Increase (decrease) in tax from:
Change in valuation allowance................. -- 396 (2,148)
State income taxes............................ 1,616 (474) 394
Non-deductible merger costs................... -- 2,429 --
Other, net.................................... (2,225) (379) 1,139
------- ------ -------
$14,962 $1,834 $ 5,138
======= ====== =======
</TABLE>
Long-term deferred tax assets (liabilities) are comprised of the following
at December 31, 1996 and 1995:
<TABLE>
<CAPTION>
1996 1995
-------- --------
(IN THOUSANDS)
<S> <C> <C>
Deferred tax assets:
Allowance for losses.................................. $ 88 $ 81
Loss carryforwards and other.......................... 27,957 26,520
-------- --------
Gross deferred tax assets........................... 28,045 26,601
Deferred tax liabilities:
Deferred revenue--partnership activities.............. (1,182) (466)
Depreciation, depletion and amortization.............. (76,458) (48,460)
Capitalized interest on other assets.................. (120) (6)
-------- --------
Gross deferred tax liabilities...................... (77,760) (48,932)
-------- --------
Net deferred tax liability.............................. (49,715) (22,331)
Valuation allowance..................................... (1,193) (1,193)
-------- --------
$(50,908) $(23,524)
======== ========
</TABLE>
Valuation allowances of $1,193,000 were provided at both December 31, 1996
and 1995 based on carryforward amounts which may not be utilized before
expiration.
The Company has net operating loss and investment tax credit carryforwards
available totaling $63.5 million and $.5 million, respectively, which expire
in the years 1997 through 2010. A substantial portion of the net operating
losses were acquired in conjunction with purchased operations.
The 1990 public offering of common stock by the Company resulted in a change
in the Company's ownership as defined in Section 382 of the Internal Revenue
Code. The effect of this change in ownership limits the utilization of net
operating losses for income tax purposes to approximately $3,069,000 per year
which affects $13,590,000 of the net operating losses. The 1995 merger with
Plains also resulted in a change in the Company's and Plains' ownership as
defined by Section 382 of the Internal Revenue Code. The change effectively
limits the annual utilization of the Company's and Plains' remaining net
operating losses arising prior to the merger to approximately $14,000,000 for
each company. Portions of the above limitations which are not used each year
may be carried forward to future years.
F-15
<PAGE>
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
12. SUPPLEMENTAL CASH FLOW SCHEDULES AND INFORMATION
Cash paid during years
<TABLE>
<CAPTION>
1996 1995 1994
------ ------ ------
(IN THOUSANDS)
<S> <C> <C> <C>
Income tax...................................... $ 416 $ 65 $ 338
Interest........................................ 3,809 5,129 711
Supplemental information of noncash investing
and financing activities:
Issuance of common stock exchanged for
treasury shares in cashless option transactions... $ 527 $ 545 $ 313
</TABLE>
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
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 years ended December 31, 1996, 1995 and 1994, Zenith was billed
by the Company as operator, approximately $77,000, $1,062,000 and $1,853,000,
respectively, for Zenith's portion of lease operating expenses and development
costs in certain leases operated by the Company. Also, as a result of Zenith's
working interest in those leases, Zenith received approximately $448,000,
$942,000 and $936,000 as its share of revenues for 1996, 1995 and 1994,
respectively.
14. QUARTERLY INFORMATION (UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
----------------------------------------
1996 3/31/96 6/30/96 9/30/96 12/31/96
- ---- --------- --------- --------- ----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
Net revenues........................... $ 41,985 $ 46,910 $ 46,060 $ 66,298
Gross margin........................... 10,420 15,190 15,010 23,180
Income from operations................. 5,573 10,651 11,128 17,136
Net income.............. .............. 3,456 6,605 6,898 12,567
Net income per share................... .14 .25 .22 .41
</TABLE>
F-16
<PAGE>
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
-----------------------------------------
1995 3/31/95 6/30/95 9/30/95 12/31/95
- ---- --------- --------- --------- ----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
Net revenues......................... $ 33,060 $ 31,277 $ 27,217 $ 35,070
Gross margin......................... 8,611 8,039 6,476 7,882
Income (loss) from operations........ 4,327 3,997 (11,389) 2,659
Net income (loss).................... 3,014 2,957 (11,848) 3,637
Net income (loss) per share.......... .11 .13 (.47) .14
<CAPTION>
THREE MONTHS ENDED
-----------------------------------------
1994 3/31/94 6/30/94 9/30/94 12/31/94
- ---- --------- --------- --------- ----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
Net revenues......................... $ 25,543 $ 24,420 $ 24,222 $ 33,076
Gross margin......................... 8,572 7,499 6,027 6,990
Income from operations............... 5,217 3,869 2,834 4,517
Net income........................... 3,799 2,610 2,081 2,809
Net income per share................. .15 .12 .08 .11
</TABLE>
F-17
<PAGE>
SUPPLEMENTAL OIL AND GAS INFORMATION
The following information, pertaining to the Company's oil and gas producing
activities for the years ended December 31, 1996, 1995 and 1994, 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 1996, one natural gas purchaser accounted for 11 percent of the
Company's total revenue (15 percent of oil and gas revenues). Sales of gas to
this same purchaser represented 18 percent and 19 percent of total revenues in
1995 and 1994, respectively.
COST INCURRED IN OIL AND GAS EXPLORATION AND DEVELOPMENT ACTIVITIES
The following costs were incurred by the Company in oil and gas property
acquisition, exploration, and development activities during the years ended
December 31:
<TABLE>
<CAPTION>
1996 1995 1994
-------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Acquisition of evaluated properties............... $ 68,157 $ 7,429 $35,234
Acquisition of unevaluated properties:
United States................................... 45,051 8,383 8,446
Peru............................................ 1,229 -- --
Exploration costs................................. 32,086 23,272 36,232
Development costs................................. 69,651 33,029 20,190
Other, principally proceeds from mineral
conveyances...................................... (1,948) (426) (173)
-------- ------- -------
Total additions to oil and gas properties......... $214,226 $71,687 $99,929
======== ======= =======
</TABLE>
Property acquisition costs include costs incurred to purchase, lease, or
otherwise acquire a property. Exploration costs include the costs of
geological and geophysical activity, dry holes, and drilling and equipping
exploratory wells. Development costs include costs incurred to gain access to
and prepare development well locations for drilling, to drill and equip
development wells.
In addition, the Company incurred costs, including the acquisition of
additional interests in existing facilities, of $15.1 million in 1996 for
various supporting production facilities consisting principally of natural gas
gathering systems and processing plants. Production facility expenditures for
1995 and 1994 were $1.3 million and $5.5 million, respectively.
OIL AND GAS RESERVES (UNAUDITED)
The following reserve related information for 1996 is based on estimates
prepared by the Company. All of the Company's reserves are located in the
United States. The 1996 reserve information for the Company was reviewed by
Ryder Scott, an independent reservoir engineer. The Company's 1995 and 1994
reserves, exclusive of Plains, were prepared by the Company and reviewed by
Ryder Scott as of December 31, 1995 and September 30, 1994. The 1995 and 1994
proved developed reserve estimates of Plains were prepared by Netherland,
Sewell & Associates, Inc. whereas the proved undeveloped reserve estimates
were prepared by Plains. Reserve estimates are inherently imprecise and are
continually subject to revisions based on production history, results of
additional exploration and development, prices of oil and gas and other
factors.
F-18
<PAGE>
<TABLE>
<CAPTION>
1996 1995 1994
--------------------- --------------------- ---------------------
OIL (MBBL) GAS (MMCF) OIL (MBBL) GAS (MMCF) OIL (MBBL) GAS (MMCF)
---------- ---------- ---------- ---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
PROVED DEVELOPED AND
UNDEVELOPED RESERVES:
Beginning of year....... 12,967 513,531 11,444 458,820 6,947 364,791
Revisions of previous
estimates.............. (210) (778) 1,209 (3,805) 772 (5,640)
Purchase of minerals in
place.................. 6,628 95,914 831 3,983 2,533 38,717
Extensions and
discoveries............ 6,029 127,547 1,232 102,329 2,547 94,276
Production.............. (1,913) (60,883) (1,702) (47,692) (1,293) (33,282)
Sale of minerals in
place.................. (270) (438) (47) (104) (62) (42)
------ ------- ------ ------- ------ -------
End of year............. 23,231 674,893 12,967 513,531 11,444 458,820
====== ======= ====== ======= ====== =======
PROVED DEVELOPED
RESERVES:
Beginning of year....... 11,669 419,672 7,848 393,051 5,548 342,287
====== ======= ====== ======= ====== =======
End of year............. 15,773 511,645 11,669 419,672 7,848 393,051
====== ======= ====== ======= ====== =======
</TABLE>
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. The
effects of existing hedging swap agreements discussed in Note 9 were included
in determining future cash inflows. Estimated future gross revenues are
reduced by estimated future development and production costs, as well as
certain abandonment costs and by estimated future income tax expense. Future
income tax expenses have been computed considering the tax basis of the oil
and gas properties plus available carryforwards and credits.
The standardized measure of discounted future net cash flows should not be
construed to be an estimate of the fair market value of the Company's proved
reserves. Estimates of fair value would also take into account anticipated
changes in future prices and costs, the reserve recovery variances from
estimated proved reserves and a discount factor more representative of the
time value of money and the inherent risks in producing oil and gas.
Significant changes in estimated reserve volumes or product prices could have
a material effect on the Company's consolidated financial statements.
<TABLE>
<CAPTION>
1996 1995 1994
---------- ---------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows........................ $2,893,217 $1,132,711 $ 931,404
Future production costs.................... (773,233) (355,756) (310,485)
Future development costs................... (152,141) (46,888) (41,972)
Future income tax expenses................. (628,901) (207,922) (152,890)
---------- ---------- ---------
Future net cash flows.................... 1,338,942 522,145 426,057
10% annual discount for estimated timing
of cash flows............................. (574,139) (212,271) (183,436)
---------- ---------- ---------
Standardized measure of discounted future
net cash flows............................ $ 764,803 $ 309,874 $ 242,621
========== ========== =========
</TABLE>
F-19
<PAGE>
The following are the principal sources of changes in the standardized
measure of discounted future net cash flows:
<TABLE>
<CAPTION>
1996 1995 1994
--------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Net change in sales price and production
costs......................................... $ 415,937 $ 24,558 $(22,409)
Changes in estimated future development costs.. 16,288 10,301 14,492
Sales and transfers of oil and gas produced,
net of production costs....................... (110,341) (62,294) (50,571)
Net change due to extensions and discoveries... 230,797 85,524 60,613
Net change due to purchases and sales of
minerals in place............................. 167,235 7,424 32,726
Net change due to revisions in quantities...... (41,486) (1,393) (588)
Net change in income taxes..................... (249,836) (33,172) (10,202)
Accretion of discount.......................... 28,053 23,112 27,589
Other, principally revisions in estimates of
timing of production.......................... (1,718) 13,193 (12,115)
--------- -------- --------
Net changes.................................... 454,929 67,253 39,535
Balance, beginning of year..................... 309,874 242,621 203,086
--------- -------- --------
Balance, end of year........................... $ 764,803 $309,874 $242,621
========= ======== ========
</TABLE>
The December 31, 1996 weighted average prices utilized for purposes of
estimating the Company's proved reserves and future net revenues were $24.12
per barrel of oil and $3.46 per Mcf of natural gas. These prices are
significantly above the average annual prices received during the past several
years. In addition, during the first three months of 1997, prices have
declined from the December 31, 1996 levels.
F-20
<PAGE>
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES ACT OF
1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY
THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
BARRETT RESOURCES CORPORATION
Date: March 20, 1997
By: /s/ William J. Barrett
_________________________________
WILLIAM J. BARRETT
CHIEF EXECUTIVE OFFICER
Date: March 20, 1997
By: /s/ John F. Keller
_________________________________
JOHN F. KELLER
CHIEF FINANCIAL OFFICER,
SECRETARY, AND PRINCIPAL FINANCIAL
AND ACCOUNTING OFFICER
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<S> <C> <C>
/s/ William J. Barrett Director March 20, 1997
- -------------------------------------
WILLIAM J. BARRETT
/s/ C. Robert Buford Director March 20, 1997
- -------------------------------------
C. ROBERT BUFORD
/s/ Derrill Cody Director March 20, 1997
- -------------------------------------
DERRILL CODY
/s/ James M. Fitzgibbons Director March 20, 1997
- -------------------------------------
JAMES M. FITZGIBBONS
/s/ Hennie L.J.M. Gieskes Director March 20, 1997
- -------------------------------------
HENNIE L.J.M. GIESKES
/s/ William W. Grant, III Director March 20, 1997
- -------------------------------------
WILLIAM W. GRANT, III
</TABLE>
II-1
<PAGE>
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<S> <C> <C>
/s/ John F. Keller Director March 20, 1997
- -------------------------------------
JOHN F. KELLER
/s/ Paul M. Rady Director March 20, 1997
- -------------------------------------
PAUL M. RADY
/s/ A. Ralph Reed Director March 20, 1997
- -------------------------------------
A. RALPH REED
/s/ James T. Rodgers Director March 20, 1997
- -------------------------------------
JAMES T. RODGERS
/s/ Philippe S.E. Schreiber Director March 20, 1997
- -------------------------------------
PHILIPPE S.E. SCHREIBER
/s/ Harry S. Welch Director March 20, 1997
- -------------------------------------
HARRY S. WELCH
</TABLE>
II-2
<PAGE>
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT
-------
<C> <S>
2.1 Agreement And Plan of Merger, dated as of May 2, 1995, among Barrett
Resources Corporation ("Barrett" or "Registrant"), Barrett Energy Inc.
(formerly known as Vanilla Corporation), and Plains Petroleum Company
("Plains") is incorporated by reference from Annex I to the Joint
Proxy Statement/Prospectus of Barrett and Plains dated June 13, 1995.
3.1 Restated Certificate Of Incorporation of Barrett Resources
Corporation, a Delaware corporation, is incorporated herein by
reference from Exhibit 3.2 of Registrant's Registration Statement on
Form S-4 dated June 9, 1995.
3.6 Bylaws of Barrett, as amended, are incorporated herein by reference
from Exhibit 3.3 of Registrant's Registration Statement on Form S-4
dated June 9, 1995.
10.1 Non-Qualified Stock Option Plan Of Barrett Resources Corporation is
incorporated by reference from Registrant's Registration Statement on
Form S-8 dated November 15, 1989.
10.2 Registrant's 1990 Stock Option Plan, as amended, is incorporated by
reference from the Registrant's Registration Statement on Form S-8
dated March 15, 1995.
10.3 Registrant's Non-Discretionary Stock Option Plan is incorporated by
reference from Registrant's Annual Report on Form 10-K for the year
ended September 30, 1991.
10.4 1994 Stock Option Plan, as amended, is incorporated by reference from
the Registrant's Registration Statement on Form S-8 dated March 15,
1995.
10.5A Gas Purchase Contract, No. P-1090, dated April 20, 1984, as amended,
between Plains and KN Energy, Inc. is incorporated by reference from
Plains Petroleum Company's Registration Statement on Form 10 dated
August 21, 1985.
10.5B Letter Agreement dated December 19, 1996, amending the Gas Purchase
Contract, No. P-1090, dated April 20, 1984, between Plains and KN
Energy, Inc.
10.6A Revolving Credit Agreement dated as of July 19, 1995 among Barrett and
Texas Commerce Bank National Association, as Agent, and Texas Commerce
Bank National Association, Nations Bank of Texas, N.A., Bank of
Montreal, Houston Agency, Colorado National Bank, and The First
National Bank of Boston, as the "Banks" is incorporated by reference
from Exhibit 10.6 to Barrett's Annual Report on Form 10-K for the year
ended December 31, 1996.
10.6B First Amendment to Revolving Credit Agreement dated October 31, 1996
between and among Barrett, Agent and the Banks is incorporated by
reference from Exhibit 10.1 to Amendment No. 2 to Barrett's
Registration Statement on Form S-3 (File No. 333 -19363) dated
February 10, 1997.
10.6C Second Amendment to Revolving Credit Agreement dated February 10, 1997
between and among Barrett, the Agent, and the Banks is incorporated by
reference from Exhibit 10.2 to Amendment No. 2 to Barrett's
Registration Statement on Form S-3 (File No. 333 -19363) dated
February 10, 1997.
21 List of Subsidiaries.
23 Consent of Arthur Andersen LLP.
27 Financial Data Schedule.
</TABLE>
<PAGE>
[LETTERHEAD OF K N GAS APPEARS HERE]
December 19, 1996
Plains Petroleum Operating Company
1515 Arapahoe Street
Tower III
Suite 1000
Denver, CO 80202
Attn: Mr. Bryan Hassler
Vice President
RE: Gas Purchase Contract
Dated April 20, 1984, As Amended
(Contract No. P-1090)
Dear Mr. Hassler:
Plains Petroleum Operating Company ("Plains") and KN Gas Supply Services, Inc.
as the successor-in-interest to K N Energy, Inc. ("KNGSS") are parties to that
certain Gas Purchase Contract, dated April 20, 1984, as amended, hereinafter
referred to as "Contract P-1090". The purpose of this Letter Agreement is to set
forth the agreement reached between Plains and KNGSS with respect to the
quantity of gas to be purchased and the price to be paid for gas by KNGSS under
Contract P-1090, as well as the release of gas thereunder, during calendar year
1997.
The agreement is as follows:
A. (1) During calendar year 1997 only, the take-or-pay provisions of
Contract P-1090 are hereby suspended and both parties are hereby relieved of the
obligations to account for and track take-or-pay status during that period.
KNGSS, subject to an event of force majeure, will use good faith efforts to
purchase under Contract P-1090 all of the gas tendered and physically made
available by Plains to KNGSS at the Delivery Points during the period commencing
January 1, 1997 and ending December 31, 1997.
(2) Plains will advise KNGSS by the fifteenth (15th) business day
prior to a month, the quantity of gas Plains will make available for purchase by
KNGSS the following month, including any mid-month adjustments. Once the
quantity has been communicated to KNGSS, modifications to the quantity will only
be made be mutual agreement of the parties. Plains and KNGSS will use good faith
efforts to maintain, on a monthly basis, a balance between Plains' monthly
availability and the actual receipt and delivery of gas during a month. Any
imbalance between the quantity of gas made available for purchase by Plains for
a month and the quantity
<PAGE>
Plains Petroleum Operating Company
12/19/96
Page 2
actually received by KNGSS shall be corrected as soon as possible in a manner
mutually agreed to by the parties. If at the end of a month, Plains delivers, or
causes to be delivered for Plains' account, a quantity of gas that is greater or
less than that made available and scheduled for receipt and delivery, and such
deliveries cause Plains or KNGSS to incur a penalty, cashout, or other charge
levied by the gatherer and/or transporter, Plains agrees to bear and pay, or if
required to reimburse KNGSS, for such penalty, cashout or charge. If at the end
of a month, KNGSS receives, or causes to be received for KNGSS' account, a
quantity of gas that is greater or less than that made available and scheduled
for receipt and delivery, and such deliveries cause Plains or KNGSS to incur a
penalty, cashout, or other charge levied by the gatherer and/or transporter,
KNGSS agrees to bear and pay, or if required to reimburse Plains, for such
penalty, cashout or charge. Plains and KNGSS agree to provide one another all
information necessary to determine what event, or which party caused the
imbalance.
B. (1) The price to be paid under Contract P-1090 for each MMBtu of gas
purchased during calendar year 1997 will be a price equal to the average of the
first of the month index prices as published by McGraw-Hill in the first of each
month's publication of Inside F.E.R.C.'s Gas Market Report under "Prices of Spot
-----------------------------------
Gas Delivered to Pipelines" for Williams Natural Gas Co. (Texas, Oklahoma,
Kansas), Panhandle Eastern Pipe Line Co. (Texas, Oklahoma), Northern Natural Gas
Co. (Texas, Oklahoma, Kansas), and Natural Gas Pipeline Company of America
(Mid-Continent zone), hereinafter referred to as the "Average Index Price", less
Fifteen Cents ($0.15) per MMBtu, hereinafter referred to as the "subtrahend",
less one percent (1%) fuel to be provided in-kind by Plains. The price is a full
price inclusive of any and all costs and reimbursements.
(2) In calculating the monthly price to be paid for gas, as provided
for in Paragraph B(1) above, the subtrahend will be subject to adjustment,
either upward or downward, depending on the actual calculated Average Index
Price as follows:
If the Average Index Price is: then the Subtrahend is:
- ------------------------------ -----------------------
less than $0.75 $0.11
$0.75 up to $1.04 $0.13
$1.05 up to $1.95 $0.15
$1.96 up to $2.25 $0.18
$2.26 or higher $0.20
C. During calendar year 1997, gas which flows south through the valve
identified below to the Panhandle Eastern Pipe Line Co. ("Panhandle"), Grant
County No. 2 Interconnect, not to exceed a total quantity of 3 Bcf, is hereby
temporarily released from Contract P-1090, on a month-to-month basis; provided,
however, if KNGSS can flow at least ninety percent (90%) of the quantity
released during a month, then KNGSS shall have the preferential right to recall,
also on a monthly basis, all gas released during a month for purchase under
Contract P-1090
<PAGE>
Plains Petroleum Operating Company
12/19/96
Page 3
at the price provided for in this Letter Agreement. If KNGSS intends to recall
released gas it shall be required to recall all the gas released for the
particular month. KNGSS, at least ten (10) business days before the succeeding
month, will notify Plains of the recall of the released gas for purchase by
KNGSS the succeeding month.
D. During calendar year 1997 only, KNGSS agrees not to exercise its
right under Article IV, Section 8 of Contract P-1090 to market out.
E. During calendar year 1997, KNGSS can temporarily release up to
25% of the gas made available by Plains pursuant to Paragraph A of this Letter
Agreement, on a month to month basis. If KNGSS desires to release a quantity of
gas, KNGSS desires to release the gas. Plains shall have the right to market any
released gas for the period of the release. K N has the right to exercise this
release option in any five (5) of the twelve months in calendar year 1997. The
gathering of this released gas will be covered by separate agreement with K N
Gas Gathering, Inc.
F. Except as specifically provided for herein, all other terms and
conditions of Contract P-1090 shall remain in full force and effect.
If the foregoing reflects Plains' understanding of the agreement
reached between Plains and KNGSS, please so indicate by properly executing both
copies of this Letter Agreement in the space provided for below and return one
executed original to my attention.
Very truly yours,
K N Gas Supply Services, Inc.
/s/ Daniel E. Watson
Vice President
ACCEPTED AND AGREED to this 19th day of December, 1996 by Plains Petroleum
Operating Company
BY: /s/ Bryan Hassler
-----------------
Bryan Hassler
Vice President
<PAGE>
BARRETT RESOURCES CORPORATION Exhibit 21
Subsidiaries of the Registrant
<TABLE>
<CAPTION>
Name of Company State of Incorporation
- --------------- ----------------------
<S> <C>
Alarado Corporation..............................................Delaware
Alarado (Denver) Company.........................................Colorado
Bargath, Inc.....................................................Colorado
Barrett Fuels Corporation........................................Delaware
Barrett Resources International Corporation......................Delaware
Barrett Resources (PAC I) Corporation............................Kansas
Barrett Resources (PAC II) Corporation...........................Kansas
Barrett Resources (Peru) Corporation.............................Delaware
BGP Inc. ........................................................Delaware
Grand Valley Gathering System (joint venture)....................Colorado
Plains Petroleum Company.........................................Delaware
Plains Petroleum Gathering Company...............................Delaware
Plains Petroleum Operating Company...............................Delaware
</TABLE>
All of the subsidiaries named above are included in the consolidated financial
statements of the Registrant included herein.
<PAGE>
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation by
reference in each of the Registration Statements and related prospectuses on
Form S-8 (No. 333-18311) pertaining to the 1990 Stock Option Plan, 1994 Stock
Option Plan and Non-Discretionary Stock Option Plan of Barrett Resources
Corporation, on Form S-8 (No. 333-02529) pertaining to the Retirement Savings
Plan of Barrett Resources Corporation, and on Form S-8 (No. 33-61097) pertaining
to the 1985 Stock Option Plan, 1985 Stock Option Plan For Non-Employee
Directors, 1989 Stock Option Plan, and 1992 Stock Option Plan of Plains
Petroleum Company (a wholly-owned subsidiary of Barrett Resources Corporation)
of our report dated February 28, 1997, with respect to the consolidated
financial statements of Barrett Resources Corporation included in the Annual
Report (Form 10-K) for the year ended December 31, 1996.
/s/Arthur Andersen LLP
ARTHUR ANDERSEN LLP
Denver, Colorado
March 27, 1997
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C> <C>
<PERIOD-TYPE> 12-MOS 12-MOS
<FISCAL-YEAR-END> DEC-31-1996 DEC-31-1995
<PERIOD-START> JAN-01-1996 JAN-01-1995
<PERIOD-END> DEC-31-1996 DEC-31-1995
<CASH> 14,539 7,529
<SECURITIES> 0 0
<RECEIVABLES> 73,274 31,290
<ALLOWANCES> 229 201
<INVENTORY> 947 554
<CURRENT-ASSETS> 89,687 39,746
<PP&E> 681,900 449,979
<DEPRECIATION> 194,642 149,313
<TOTAL-ASSETS> 576,945 340,412
<CURRENT-LIABILITIES> 78,317 36,060
<BONDS> 0 0
0 0
0 0
<COMMON> 313 251
<OTHER-SE> 377,407 191,577
<TOTAL-LIABILITY-AND-EQUITY> 576,945 340,412
<SALES> 198,599 125,550
<TOTAL-REVENUES> 202,572 128,016
<CGS> 137,453 95,616
<TOTAL-COSTS> 137,453 95,616
<OTHER-EXPENSES> 16,947 28,175
<LOSS-PROVISION> 0 0
<INTEREST-EXPENSE> 3,684 4,631
<INCOME-PRETAX> 44,488 (406)
<INCOME-TAX> 14,962 1,834
<INCOME-CONTINUING> 29,526 (2,240)
<DISCONTINUED> 0 0
<EXTRAORDINARY> 0 0
<CHANGES> 0 0
<NET-INCOME> 29,526 (2,240)
<EPS-PRIMARY> 1.02 (0.09)
<EPS-DILUTED> 1.02 (0.09)
</TABLE>
