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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, 1997
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (D) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NO. 1-13446
BARRETT RESOURCES CORPORATION
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 84-0832476
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER IDENTIFICATION NO.)
INCORPORATION OR ORGANIZATION)
1515 ARAPAHOE STREET, TOWER 3, SUITE
1000 DENVER, COLORADO 80202
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
(303) 572-3900
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
TITLE OF EACH CLASS NAME OF EXCHANGE ON WHICH REGISTERED
-------------------------------- -----------------------------
COMMON STOCK ($.01 PAR VALUE) NEW YORK STOCK EXCHANGE
PREFERRED STOCK PURCHASE RIGHTS NEW YORK STOCK EXCHANGE
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
(NONE)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes [X] No [_]
Indicate by check mark if there are no delinquent filers to disclose herein
pursuant to Item 405 of Regulation S-K, and there will not be any delinquent
filers to disclose, to the best of registrant's knowledge, in definitive proxy
or information statements incorporated by reference in Part III of this Form
10-K or any amendment to this Form 10-K. [X]
As of March 3, 1998, the Registrant had 31,417,828 common shares
outstanding, and the aggregate market value of the common shares held by non-
affiliates was approximately $956,112,713. This calculation is based upon the
closing sale price of $31.5625 per share for the stock on March 3, 1998.
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TABLE OF CONTENTS
ITEM PAGE
---- ----
PART I
1 and 2. Business and Properties........................................ 1
3. Legal Proceedings.............................................. 17
4. Submission of Matters to Vote of Security Holders.............. 18
PART II
5. Market for the Registrant's Common Stock and Related Security
Holders Matters ............................................... 19
6. Selected Financial Data ....................................... 19
7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.......................................... 19
8. Financial Statements and Supplemental Data .................... 24
9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosures ......................................... 24
PART III
10. Directors and Executive Officers of the Company................ 25
11. Executive Compensation ........................................ 29
12. Security Ownership of Certain Beneficial Owners and
Management..................................................... 33
13. Certain Relationships and Related Transactions ................ 34
PART IV
14. Exhibits, Financial Schedules, and Reports on Form 8-K ........ 35
i
PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
Barrett Resources Corporation (the "Company" or "Barrett", which reference
shall include the Company's wholly owned subsidiaries) was incorporated in
December 1980 as an oil and gas company under the name AIMEXCO Inc. and became
publicly owned with a $5.8 million common stock offering in May 1981. In
December 1983, AIMEXCO acquired all the common stock of Barrett Energy
Company, which owned a number of oil and gas properties, in exchange for 71.5
percent of the common stock of AIMEXCO that was outstanding after the
transaction. In January 1984, the Company changed its name to Barrett
Resources Corporation.
In November 1985, the Company acquired Excel Energy Corporation, a Utah
corporation that owned oil and gas interests, in exchange for approximately
1,425,000 shares of the Company's common stock. In June 1987, the Company
acquired all the outstanding stock of Finance For Energy, Ltd., whose assets
consisted primarily of cash and mortgages, in exchange for 1,174,100 shares of
the Company's common stock.
In September 1987, the Company effected a one-for-twenty reverse stock split
of the Company's common shares and changed the par value of its common stock
to $.01 per share. All prior references in this Item to numbers of shares of
the Company's common stock have been adjusted for the effect of this one-for-
twenty reverse stock split.
In May 1990, the Company completed the public offering of 3,565,000 shares
of its common stock for $21.3 million, net of the underwriting discount. In
March 1993, the Company completed the public offering of an additional two
million shares of its common stock for $19.2 million, net of the underwriting
discount.
In July 1995, the Company completed the merger of the Company and Plains
Petroleum Company ("Plains") pursuant to which Plains became a wholly owned
subsidiary of the Company. The Company issued 12.8 million shares of common
stock in exchange for all the outstanding shares of Plains.
In June 1996, the Company completed the public offering of 5.4 million
shares of its common stock for $135 million, net of the underwriting discount.
In February 1997, the Company completed the public offering of $150 million
of its 7.55% Senior Notes due 2007.
OIL AND GAS EXPLORATION AND DEVELOPMENT
Barrett is an independent natural gas and crude oil exploration and
production company with core areas of activity in the Rocky Mountain Region of
Colorado, Wyoming and Utah; the Mid-Continent Region of Kansas, Oklahoma, New
Mexico and Texas; and the Gulf of Mexico Region of offshore Texas and
Louisiana. At December 31, 1997, the Company's estimated proved reserves were
963.2 Bcfe (88% natural gas and 12% crude oil) with an implied reserve life of
10.7 years based on 1997 total production of 90 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 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, the Powder River Basin in Wyoming and
the Uinta Basin of northeastern Utah. At December 31, 1997, these principal
areas of focus represented approximately 96% of the Company's estimated proved
reserves.
The Company continues to experience significant growth in its proved
reserves, production volumes, revenues and cash flow, particularly in the Wind
River, Piceance, Anadarko, Arkoma and Uinta Basins. The Company currently is
pursuing development projects in the Wind River, Piceance, Anadarko and Arkoma
Basins,
1
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 247 MMcfe for the year ended December 31, 1997 from 198 MMcfe for
the year ended December 31, 1996.
As of December 31, 1997, the Company owned interests in 2,541 producing
wells and operated 1,368 of these wells. These operated wells contributed
approximately 81% of the Company's natural gas and oil production for the year
ended December 31, 1997. 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 207 full time employees, including 12 officers
(five of whom are geologists and three of whom are petroleum engineers), 14
geologists, six geophysicists, 15 engineers, one environmental manager, 13
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. The Company maintains regional offices in Tulsa, Oklahoma and Houston,
Texas.
CORE AREAS OF ACTIVITY
The following table sets forth certain information concerning these core
areas of activity:
AVERAGE DAILY
ESTIMATED PROVED ESTIMATED PROVED PRODUCTION FOR
RESERVES AT RESERVES AT YEAR ENDED
DECEMBER 31, DECEMBER 31, DECEMBER 31,
BASIN OR FIELD 1996 1997 1997
-------------- ---------------- ---------------- --------------
(BCFE) (BCFE) (MMCFE)
Rocky Mountain Region
Wind River............... 96.8 118.4 55.0
Piceance................. 201.0 339.6 45.5
Powder River............. 32.1 24.2 16.5
Powder River-CBM......... 0 18.7 1.4
Green River.............. 14.8 9.8 1.9
Uinta ................... 92.2 82.3 10.0
Mid-Continent Region
Arkoma................... 26.5 28.8 13.7
Anadarko................. 17.6 33.8 20.3
Hugoton Embayment........ 240.4 195.8 45.6
NE Colorado-Niobrara..... 25.3 23.6 4.3
Permian.................. 31.8 20.9 12.4
Gulf of Mexico Region...... 23.8 59.2 18.4
Other Natural Gas and Oil
Activities(1)............. 12.1 8.0 1.7
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Total.................. 814.3 963.2 246.7
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(1) The only significant property in this category is the Meeteetse Field in
the Big Horn Basin, Wyoming.
2
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 Central Wyoming, particularly along the Owl Creek Thrust fault.
Cave Gulch Area. 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. Since August 1994,
the Company has acquired additional interests in the area and currently owns
working interests ranging from 5% to 100% in 17,283 gross leasehold acres,
constituting 10,478 net leasehold acres in the Cave Gulch area, including a
94% working interest in the 440 acre Cave Gulch Federal Unit covering the Fort
Union and Lance Sandstones.
In August 1997, the Bureau of Land Management ("BLM") completed an
Environmental Impact Statement ("EIS") for the greater Cave Gulch area by
signing a Record of Decision ("ROD") that allowed operators to continue with
drilling and completion operations. Subsequent to the signing of the ROD, the
Company drilled five successful Lance wells, and unsuccessfully attempted a
Frontier Formation completion in a wellbore purchased from a prior operator.
Through December 1997, the Company has operated and completed a total of 18
Lance wells (17 producing and 1 shut-in), drilled 2 additional Lance wells
that are waiting on completion and has one producing Mesaverde well and one
producing Frontier well.
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 Frontier, Muddy,
Lakota, Morrison and Sundance Formations. The well encountered these
formations approximately 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. In August 1997, the Cave Gulch #16
well was completed in the Third Frontier Sandstone with a stabilized flow rate
of 10.2 MMCFD of gas. It is currently producing 5.5 MMCFD. Two Frontier zones
and one Muddy zone still remain behind pipe. The Company owns an 85.3% working
interest in this well.
In September 1997, the Company began drilling a deep development well and an
ultradeep exploratory well. The first of those, the Cave Gulch Federal 1-29
LAK, spud in September 1997 to drill to 18,625 feet as a Frontier-Muddy-Lakota
development test. While drilling at a depth of 18,175 feet, a gas flow was
encountered. With the assistance of expert well and pressure control
personnel, the well was placed on production on February 20, 1998. It is
currently producing at the rate of 30 MMCF of natural gas per day. It is the
Company's intent to continue this production until the pressures in the well
decrease sufficiently to allow reentry into the well. The second well, the
Cave Gulch Federal 3-29 MAD, also spud in September 1997 as an exploratory
test to drill to 21,300 feet to test the Mississippian Madison Formation. The
Company owns a 70% working interest in the Cave Gulch Federal 1-29 LAK test
and a 97% working interest in the Cave Gulch Federal 3-29 MAD test.
Two interstate pipelines serving the Cave Gulch area completed expansions
during 1997 that increased take-away capacity from the area. Subsequent to the
signing of the ROD, the Company installed a centralized compressor and wet gas
conditioning facility on its gathering system, which enables the Company to
transport increased volumes of gas to the interstate pipelines.
Owl Creek Thrust. The Company continues to evaluate additional exploration
prospects in the Owl Creek Thrust, along the northern margins of the Wind
River Basin. In July 1997, the Company entered into a definitive Exploration
and Area of Mutual Interest Agreement with an oil and gas industry partner to
explore for oil and gas along the Owl Creek Thrust. The partner was assigned
45% of the Company's interest in 77,127 net acres. To date, the Company has
participated in two exploratory tests that were plugged and abandoned.
Additional exploratory tests are planned for 1998.
At December 31, 1997, the Wind River Basin represented 12% of the Company's
estimated proved reserves, and 22% of the Company's total 1997 production. In
1998, the Company intends to spend 19% of its capital
3
expenditure budget in the Wind River Basin for development, leasehold
acquisition, seismic surveys and exploration, including participating in the
drilling of up to 10 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.
The Company drilled its first well in the Piceance Basin in 1984, and as of
December 31, 1997, the Company owned interests in 365 wells and operated 333
of these wells.
In November 1996, the Company requested and received approval from the
Colorado Oil and Gas Conservation Commission ("COGCC") for two four-well pilot
drilling programs on 20-acre well density in the Rulison and Grand Valley
Fields. On January 8, 1998, the Company gained approval from the COGCC for
20-acre well density on 2,830 net acres, approximately 4% of its net acreage,
in the Piceance Basin. This COGCC approval allows for 107 additional 20-acre
infill locations associated with the approved acreage.
In April 1997, the Company acquired from a third party additional interests
in the Piceance Basin, increasing the Company's average working interest to
62% in the Piceance Basin properties.
At December 31, 1997, the Piceance Basin represented 35% of the Company's
estimated proved reserves, and 18% of the Company's total 1997 production. The
Company is currently operating four drilling rigs in the Basin. In 1998, the
Company intends to spend 17% of its capital expenditure budget in the Piceance
Basin for development and exploration, including participating in drilling up
to 58 wells and 25 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 64%. As of December
31, 1997, the Grand Valley Gathering System was connected to 275 producing
natural gas wells. The system now has the flexibility to deliver natural gas
to three interstate pipelines and one intrastate pipeline. In December 1994,
the Company completed the construction of a 90 MMcf per day natural gas
processing plant to extract liquid hydrocarbons from the natural gas stream.
In 1997, the Company looped the main 8-inch pipeline adding 20 miles of new
16-inch pipeline and associated compression. Following these improvements and
depending on the take-away capacity from time-to-time of these four pipeline
systems, the gathering system has the capability of delivering over 150 MMcf
of gas per day.
UINTA BASIN. As an extension of its Piceance Basin operations, the Company
entered the Uinta Basin of Duchesne and Uintah Counties, in northeastern Utah,
in 1995. The Douglas Creek Arch separates the Uinta Basin from the Piceance
Basin.
Brundage Canyon Field. Beginning in December 1995, the Company made
acquisitions in the Brundage Canyon Field. As a result of these acquisitions
and new drilling, the Company currently owns working interests ranging from
75% to 100% in 32 producing wells, a gathering and transmission system, and
35,610 gross acres, covering approximately 34,854 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.
Altamont-Bluebell Field. 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
107,669 gross and 88,427 net acres of leasehold interests. The Company's
production in this area is
4
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
consisting of 16 non-operated wells, with an average working interest of 42%,
together with approximately 10,000 gross and 4,600 net acres of leasehold
interests.
At December 31, 1997, the Uinta Basin represented 9% of the Company's
estimated proved reserves, and 4% of the Company's total 1997 production. In
1997, the Company completed 20 wells as part of a recompletion/restimulation
program, and drilled 11 wells as development and extension wells in the Uinta
Basin.
In the second half of 1997 the Company attempted to divest its Uinta Basin
properties, but did not obtain an acceptable purchase offer. In 1998, capital
spending in the Basin will be less than $1 million.
POWDER RIVER BASIN. The Powder River Basin in Wyoming is primarily an oil
province, with production from Cretaceous and Permian Age Formations. One of
the reservoir targets in this Basin is the Permian Minnelusa Formation. This
Basin contributes approximately 40% of the Company's daily oil production.
On September 12, 1997, the Company completed a Minnelusa Upper "B" Sand well
that was drilled, based on 3-D seismic, as an extension to the Bracken
Minnelusa Unit in Campbell County. Since its completion, this well has
produced over 50,000 barrels of oil, with a current production rate of
approximately 268 BOPD. The results of this well confirm that the reservoir is
larger than previously mapped and additional drilling, based on newly acquired
3-D seismic, is planned for 1998. The Company owns an 84% working interest in
this well.
On May 9, 1997 the Company completed a Minnelusa "A" Sand exploratory well,
the Hoffman #13-31, north of the Halverson Field in Campbell County. This well
is currently producing approximately 252 BOPD and since being completed has
produced over 95,000 barrels of oil. The Company owns a 54% working interest
in this well. It is anticipated that a newly acquired 3-D seismic survey will
delineate additional "A" Sand development locations.
In October 1997, the Company entered into a joint development agreement with
another party to participate, with a 50% working interest, in a coal bed
methane project covering approximately 250,000 gross acres located north and
south of Gillette, Wyoming. The joint venture includes an area of mutual
interest ("AMI") covering 2.1 million acres of potential prospectivity. The
coal seams lie 500-1,500 feet below the surface and, therefore, the cost to
drill and complete these wells is low. In addition to the acreage in the joint
venture, the Company has obtained an interest in 224 existing wells,
approximately 130 of which are producing at a combined rate of 24 MMCFD. An
additional 42 wells are currently dewatering, while the remaining 52 wells are
awaiting completion or pipeline hook-up. In addition, within the existing AMI,
the Company has acquired a 50% interest in 32,000 gross acres in the Hilight
Area, located in Campbell County, Wyoming, along with an interest in the
existing Muddy formation oil production from the four waterfloods that
comprise the field.
At December 31, 1997, the Powder River Basin represented 4% of the Company's
estimated proved reserves and 7% of the Company's total 1997 production. In
1998, the Company intends to spend 7% of its capital expenditure budget in the
Basin.
MID-CONTINENT REGION
ARKOMA BASIN. In 1997, the Company participated in the drilling of 18 wells,
in four areas of the Arkoma Basin in Oklahoma: South Panola, Retherford,
Wilburton, and Alderson. Of the 18 gas wells drilled, 14 were completed as
producers and four were dry holes. 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.
5
At December 31, 1997, the Arkoma Basin represented 3% of the Company's
estimated proved reserves and 6% of the Company's total 1997 production. The
Company intends to spend 2% of its 1998 capital expenditure budget for
drilling 11 wells, seismic surveys and land acquisitions.
ANADARKO BASIN. In 1997, the Company participated in the drilling of 59
wells in the Anadarko Basin with working interests ranging from 1% to 100%. Of
the 59 gas wells drilled, 41 wells completed as producers and 18 were dry
holes. The Company has become increasingly active in the Mountain Front
Granite Wash and Springer plays, and is currently acquiring 3-D seismic to
help evaluate its substantial acreage position.
At December 31, 1997, the Anadarko Basin represented 4% of the Company's
estimated proved reserves, and 8% of the Company's total 1997 production. The
Company plans to spend 11% of its 1998 capital expenditure budget in the
Anadarko Basin for development and exploration drilling of up to 45 wells,
leasehold acquisitions and seismic surveys.
HUGOTON EMBAYMENT. The third largest producing area for the Company is the
Hugoton Embayment, which is one of the largest natural gas producing areas in
the United States. It is located in southwest Kansas, the Oklahoma panhandle
and the Texas panhandle. The Company produces natural gas from three fields in
the Hugoton Embayment: the Hugoton, the Guymon-Hugoton and Panoma Fields.
Hugoton and Guymon-Hugoton Fields. In the Hugoton and Guymon-Hugoton Fields,
the Company has working interests in 378 gross wells and operates 323 of them.
The Hugoton and the Guymon-Hugoton Fields produce from the Chase Formation.
Eleven wells were drilled in the Hugoton Field in 1997, nine of which have
been placed on production and two are awaiting completion.
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 56 gross Panoma wells and operates 52 of those
wells. Two Panoma wells were drilled in 1997, one of which was unproductive in
the Council Grove Formation and is currently being completed as a Hugoton
infill (Chase) well. The other well is being completed in the Council Grove
Formation.
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, the price was calculated each month by
using the average of four Mid-Continent index prices less a variable amount
ranging from $0.11 for an average index price less than $0.75 to a maximum of
$0.20 for an average index price of $2.26 or higher per MMBtu. The volume of
natural gas for which the Company receives payment is reduced by one percent
of the volume as an in-kind fuel charge for moving the natural gas. By a
letter agreement dated December 18, 1997, natural gas sold under this contract
between January 1, 1998 and December 31, 2000 will be priced in the same
manner as in 1997.
Net Profit Agreements. The Company produces natural gas in the Guymon-
Hugoton Field and the nearby Camrick Field under a Dry Gas Agreement with
Chevron U.S.A. Inc. ("Chevron"). This agreement allows the Company to expend
funds for the operation of the properties (including the cost of drilling
wells) and to recoup the funds so expended from current production income.
Eighty percent of net operating income generated by the natural gas production
(after operational costs are recouped, including the cost of drilling and
equipping wells) is then paid to Chevron. As of December 31, 1997, the Company
had interests in 56 wells subject to the terms of this agreement. The Company
also produces natural gas in the Hugoton and Panoma Fields under various
agreements similar to the Chevron agreement, except that net operating income
is allocated 15% to the Company and 85% to other parties. At December 31,
1997, the Company had interests in an aggregate of 54 Chase Formation wells
and eight Council Grove Formation wells under these other agreements.
The payments made pursuant to the net profit agreements are treated as lease
operating expenses by the Company. Additional or replacement wells drilled on
the properties would be operated under the same terms and
6
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 payment of $0.06
per Mcf for natural gas produced from the acreage. Quarterly payments are made
by the Company to the Hugoton Gas Trust, a publicly held trust created in
1955. Payments terminate when the estimated gross recoverable natural gas
reserves decline to 50 Bcf or less. As of December 31, 1997, the gross proved
natural gas reserves attributable to the leases burdened by this agreement
were estimated to be 127.1 Bcf. The natural gas payments are treated as lease
operating expenses by the Company. At December 31, 1997, the Company had
working interests in 196 wells that were subject to these payments. Any
additional natural gas wells drilled on this acreage also will be subject to
the $0.06 per Mcf payment of natural gas produced.
At December 31, 1997, the Hugoton Embayment represented 20% of the Company's
estimated proved reserves, and 18% of the Company's total 1997 production. The
Company intends to spend $1 million in 1998 in the Hugoton Embayment for
drilling seven wells and adding compression.
PERMIAN BASIN. The Permian Basin, located in west Texas and southeast New
Mexico, is primarily an oil province. As of December 31, 1997, the Company had
an interest in 140 gross wells (114 net wells) located in the Permian Basin.
These wells produced approximately 1,248 barrels of oil per day, net to the
Company's interests, during 1997. The Company participated in drilling nine
gross (4.19 net) wells during 1997.
At December 31, 1997, the Permian Basin represented 2% of the Company's
estimated proved reserves, and 5% of the Company's total 1997 production. The
Company intends to spend less than 1% of its 1998 capital expenditure budget
in the Permian Basin.
GULF OF MEXICO REGION
The Company increased Gulf Coast production 281% during 1997, with net daily
volumes increasing from 7.5 MMcfed to 28.6 MMcfed at year end 1997. The
increased production was due to 15 new wells and 34 acquired wells having been
added during the year. Proved reserves increased 123% from 23.6 Bcfe to
52.7 Bcfe.
The Company participated in drilling 23 wells in the Gulf of Mexico during
1997, resulting in 12 gas wells, three oil wells, six unsuccessful wells, and
two wells which were still drilling at year-end. The South Timbalier 146 #1,
which the Company operates and owns a 50% working interest in, logged 153 feet
of net pay and is scheduled to be placed on production during the second
quarter of 1998. The Company participated with a 22.22% working interest in
the West Cameron 528 #1 which logged 86 feet of net gas. It is scheduled to be
placed on production in June 1998. The Company also participated with a 33.33%
working interest in the West Cameron 56 #15, which encountered 78 feet of net
gas pay and is scheduled for first sales near the end of the first quarter of
1998. At High Island A-545, the Company owns a 40% working interest in the #2
well, which logged 53 feet of net gas pay. It is scheduled to be completed in
the third quarter of 1998.
The Company currently owns an interest in 126 leases in the Gulf of Mexico,
72 offshore Texas and 54 offshore Louisiana, half of which remain untested.
The Company intends to sell down its interest in many of these leases to a
level which is more consistent with its overall plan of building a
diversified, lower risk portfolio of properties in the Gulf of Mexico.
During 1997, the Company participated in two Outer Continental Shelf Federal
Lease Sales, acquiring 13 blocks at interest levels ranging from 25% to 100%,
at a net cost of $17.8 million. Included in these 13 blocks are two deep-water
leases in the Garden Banks Area. The Company owns a 25% interest in these two
leases. These are the Company's first deep water leases.
7
In the fourth quarter of 1997, the Company acquired interests in 56 leases
and 34 producing wells in the Gulf of Mexico. The net daily production from
these 34 producing wells, at closing, was approximately 8.2 MMcfed. It is
believed that a significant portion of the properties included in this
acquisition are under-evaluated and, therefore, present further exploration
and development opportunities.
At December 31, 1997, the Gulf of Mexico represented 6% of the Company's
estimated proved reserves, and 8% of the Company's total 1997 production. In
1998, the Company intends to spend $43 million, or 23% of its 1998 capital
budget, to drill 15 wells.
INTERNATIONAL OPERATIONS
In late January 1997, the Company entered into an agreement with industry
partners that provided the Company with a working interest in Block 67,
covering approximately two million gross acres in the Maranon Basin of
northeastern Peru. The Company and its partners acquired and interpreted 300
miles of seismic data which confirmed the presence of three prospects. The
drilling of at least two exploratory wells will begin in the second quarter of
1998. The Company currently owns a 45% working interest in Block 67. However,
the Company has executed an agreement to acquire an additional 15% working
interest held by a co-venturer in exchange for 260,938 shares of the Company's
common stock. This transaction is currently scheduled to close on March 24,
1998. The Company estimates that its total net cost with a 60% working
interest participation in the drilling of three exploratory wells will be
approximately $15.4 million in 1998. The Company was designated operator for
operations in Block 67 in January 1998.
In November 1996, the Company obtained, with an industry partner, a license
to evaluate, explore and develop Block 55 (A, B, and C), which encompasses
approximately 820,000 acres in the Maranon Basin. 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, the Company and its
partner conducted seismic reprocessing, environmental impact and engineering
feasibility studies regarding the viability of developing the Bretana Field,
which was discovered in 1974 by another company. A field party mobilized to
survey a potential drilling location was unable to locate the original
Bretana-1X wellbore. The Company and its partner declared Force Majeure, which
was agreed to by Perupetro on August 8, 1997, to allow time to renew efforts
to locate the well.
Pursuant to the licenses for both Block 67 and 55, the Republic of Peru
receives a variable royalty payment on production that can range from 18% to
38% based on an investment to revenue ratio. Estimated capital expenditures
for international operations for 1998 constitute approximately 12% of the
Company's 1998 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 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, "BOPD" means barrels of oil per day, "MMcfd" means million cubic feet
of natural gas per day, "Mcfe" means thousand cubic feet equivalent, "Mcfed"
means thousand cubic feet equivalent per day, "MMcfe" means million cubic feet
equivalent, and "MMBtu" means million British thermal units, "MMcfed" means
million cubic feet equivalent per day, "Bcfe" means billion cubic feet
equivalent.
With respect to information concerning the Company's working interests in
wells or drilling locations, "gross" natural gas and oil wells or "gross"
acres is the number of wells or acres in which the Company has an interest,
and "net" gas and oil wells or "net" acres are determined by multiplying
"gross" wells or acres by
8
the Company's working interest in those wells or acres. A working interest in
an oil and natural gas lease is an interest that gives the owner the right to
drill, produce, and conduct operating activities on the property and to
receive a share of production of any hydrocarbons covered by the lease. A
working interest in an oil and gas lease also entitles its owner to a
proportionate interest in any well located on the lands covered by the lease,
subject to all royalties, overriding royalties and other burdens, to all costs
and expenses of exploration, development and operation of any well located on
the lease, and to all risks in connection therewith.
"Capital expenditures" means costs associated with exploratory and
development drilling (including exploratory dry holes); leasehold
acquisitions; seismic data acquisitions; geological, geophysical and land
related overhead expenditures; delay rentals; producing property acquisitions;
and other miscellaneous capital expenditures. "Capital expenditure budget"
means an estimate prepared by management for the total expenditures
anticipated to be incurred during the subject time period. This amount can
deviate or fluctuate due to the timing of drilling of wells, environmental
considerations, acquisition of important fee, state and federal leases, and
natural gas and oil prices.
A "development well" is a well drilled as an additional well to the same
horizon or horizons as other producing wells on a prospect, or a well drilled
on a spacing unit adjacent to a spacing unit with an existing well capable of
commercial production and which is intended to extend the proven limits of a
prospect. An "exploratory well" is a well drilled to find commercially
productive hydrocarbons in an unproved area, or to extend significantly a
known prospect.
A "farmout" is an assignment to another party of an interest in a drilling
location and related acreage conditional upon the drilling of a well on that
location. A "farm-in" is an assignment by the owner of a working interest in
an oil and gas lease of the working interest or a portion thereof to another
party who desires to drill on the leased acreage. Generally, the assignee is
required to drill one or more wells in order to earn its interest in the
acreage. The assignor usually retains a royalty or reversionary working
interest in the lease. The assignee is said to have "farmed-in" the acreage.
"Present value of estimated future net revenues" means the present value of
estimated future revenues to be generated from the production of proved
reserves calculated in accordance with the Securities and Exchange Commission
guidelines, net of estimated production and future development costs, using
prices and costs as of 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.
9
PRODUCTION
The table below sets forth information with respect to the Company's net
interests in producing natural gas and oil properties for each of its last
three years, respectively:
NATURAL GAS AND OIL
PRODUCTION
--------------------
YEAR ENDED
DECEMBER 31,
--------------------
1995 1996 1997
------ ------ ------
Quantities Produced and Sold
Natural gas (Bcf)....................................... 47.7 60.9 76.6
Oil and condensate (MMBbls)............................. 1.7 1.9 2.2
Average Sales Price
Natural gas ($/Mcf)..................................... $ 1.47 $ 1.88 $ 2.18
Oil and condensate ($/Bbl).............................. 15.76 19.51 17.69
Average Production Costs/Mcfe............................. $ 0.60 $ 0.66 $ 0.63
PRODUCTIVE WELLS
The productive wells in which the Company owned a working interest as of
December 31, 1997 are described in the following table:
PRODUCTIVE WELLS(1)
-------------------------
GAS WELLS OIL WELLS
------------ ------------
GROSS NET GROSS NET
----- ------ ----- ------
Rocky Mountain Region
Wind River.......................................... 51 22.92 31 8.77
Piceance............................................ 365 207.88 0 0.00
NE Colorado-Niobrara................................ 125 85.06 0 0.00
Powder River........................................ 18 2.31 374 80.14
Powder River-CBM.................................... 247 120.38 0 0
Green River......................................... 27 19.07 0 0
Uinta............................................... 1 1.00 209 180.32
Mid-Continent Region
Arkoma.............................................. 151 34.52 0 0.00
Anadarko............................................ 246 86.50 35 18.86
Hugoton Embayment................................... 434 367.54 0 0.00
Permian............................................. 13 9.42 127 105.05
Gulf of Mexico Region................................. 31 9.45 6 2.00
Other................................................. 17 17.24 33 1.53
----- ------ --- ------
Total............................................... 1,726 983.29 815 396.67
===== ====== === ======
- --------
(1) Each well completed to more than one producing zone is counted as a single
well. The Company has royalty interests in certain wells that are not
included in this table.
10
DRILLING ACTIVITY
The following table summarizes the Company's natural gas and oil drilling
activities, all of which were located in the United States, during the last
three years:
WELLS DRILLED
------------------------------------
YEAR ENDED DECEMBER 31,
------------------------------------
1995 1996 1997
----------- ----------- ------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- ------
Development
Natural gas........................... 88 39.03 94 46.24 224 117.76
Oil................................... 22 11.68 43 30.48 37 25.04
Non-productive........................ 10 3.51 17 8.03 20 11.28
--- ----- --- ----- --- ------
Total............................... 120 54.22 154 84.75 281 154.08
=== ===== === ===== === ======
Exploratory
Natural gas........................... 0 0.00 8 4.05 9 4.19
Oil................................... 1 0.33 3 1.00 1 .33
Non-productive........................ 8 2.65 6 3.66 8 5.09
--- ----- --- ----- --- ------
Total............................... 9 2.98 17 8.71 18 9.61
=== ===== === ===== === ======
In addition, the Company was participating in 18 gross (8.29 net) wells,
which were in the process of being drilled, at December 31, 1997.
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 and 1997 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.
ESTIMATED PROVED
RESERVES
----------------------
DECEMBER 31,
----------------------
1995 1996 1997
------ -------- ------
(DOLLARS IN MILLIONS,
EXCEPT SALES PRICE
DATA)
Estimated Proved Reserves
Natural gas (Bcf).................................. 513.5 674.9 851.2
Oil and condensate (MMBbls)........................ 13.0 23.2 18.7
Total (Bcfe)..................................... 591.3 814.3 963.2
Proved developed reserves (Bcfe)..................... 489.7 606.3 618.3
Natural gas price as of December 31 ($/Mcf).......... $ 1.77 $ 3.46 $ 2.19
Oil price as of December 31 ($/Bbl).................. $17.35 $ 24.12 $15.52
Present value of estimated future net revenues before
future income taxes discounted at 10%(1)............ $432.6 $1,121.5 $745.0
Standardized measure of discounted net cash flows(2). $309.9 $ 764.8 $564.1
- --------
(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 $1.77
per Mcf of natural gas and $17.35 per Bbl of oil at December 31,
11
1995; $3.46 per Mcf of natural gas and $24.12 per Bbl of oil at December
31, 1996; and $2.19 per Mcf of natural gas and $15.52 per Bbl of oil at
December 31, 1997.
(2) The Standardized measure of discounted net cash flows prepared by the
Company represents the present value of estimated future net revenues
after income taxes discounted at 10%.
In accordance with applicable requirements of the Securities and Exchange
Commission (the "Commission"), estimates of the Company's proved reserves and
future net revenues are made using sales prices estimated to be in effect as
of the date of such reserve estimates and are held constant throughout the
life of the properties (except to the extent a contract specifically provides
for escalation). Estimated quantities of proved reserves and future net
revenues therefrom are affected by natural gas and oil prices, which have
fluctuated widely in recent years. There are numerous uncertainties inherent
in estimating natural gas and oil reserves and their estimated values,
including many factors beyond the control of the producer. The reserve data
set forth in this document represents only estimates. Reservoir engineering is
a subjective process of estimating underground accumulations of natural gas
and oil that cannot be measured in an exact manner. The accuracy of any
reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment. As a result, estimates
of different engineers, including those used by the Company, may vary. In
addition, estimates of reserves are subject to revision based upon actual
production, results of future development and exploration activities,
prevailing natural gas and oil prices, operating costs and other factors,
which revisions may be material. Accordingly, reserve estimates are often
different from the quantities of natural gas and oil that are ultimately
recovered and are highly dependent upon the accuracy of the assumptions upon
which they are based.
In general, the volume of production from natural gas and oil properties
owned by the Company declines as reserves are depleted. Except to the extent
the Company acquires additional properties containing proved reserves or
conducts successful exploration and development activities, or both, the
proved reserves of the Company will decline as reserves are produced. Volumes
generated from future activities of the Company are therefore highly dependent
upon the level of success in acquiring or finding additional reserves and the
costs incurred in doing so.
Reference should be made to "Supplemental Gas and Oil Information" on pages
F-20 through F-22 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.
12
DEVELOPED AND UNDEVELOPED ACREAGE
The gross and net acres of developed and undeveloped natural gas and oil
leases held by the Company as of December 31, 1997 are summarized in the
following table. "Undeveloped Acreage" includes leasehold interests that
already may have been classified as containing proved undeveloped reserves.
DEVELOPED UNDEVELOPED
ACREAGE ACREAGE(1)
--------------- -------------------
GROSS NET GROSS NET
------- ------- --------- ---------
Rocky Mountain Region
Wind River............................. 13,889 6,561 120,943 71,309
Piceance............................... 46,080 28,902 122,143 57,071
Powder River........................... 84,924 41,647 349,731 125,395
Green River............................ 14,977 5,254 26,517 20,055
Uinta.................................. 84,240 70,004 93,362 77,518
Mid-Continent Region
Arkoma................................. 44,749 33,256 35,702 26,050
Anadarko............................... 123,566 54,688 114,248 62,081
Hugoton Embayment...................... 91,532 85,779 0 0
Permian................................ 20,595 11,010 4,044 978
Gulf of Mexico Region.................... 164,721 66,040 209,156 131,043
International............................ 0 0 2,867,281 1,371,604
Other.................................... 33,551 26,938 51,218 28,892
------- ------- --------- ---------
Total................................ 722,825 430,080 3,994,345 1,971,996
======= ======= ========= =========
- --------
(1) Undeveloped acreage is leased acreage on which wells have not been drilled
or completed to a point that would permit the production of commercial
quantities of natural gas and oil regardless of whether such acreage
contains proved reserves. Of the aggregate 3,994,345 gross and 1,971,996
net undeveloped acres, 170,632 gross and 61,624 net acres are held by
production from other leasehold acreage.
Substantially all the leases summarized in the preceding table will expire
at the end of their respective primary terms unless the existing leases are
renewed or production has been obtained from the acreage subject to the lease
prior to that date, in which event the lease will remain in effect until the
cessation of production. The following table sets forth the gross and net
acres subject to leases summarized in the preceding table that will expire
during the periods indicated:
ACRES EXPIRING GROSS NET
-------------- --------- -------
Twelve Months Ending:
December 31, 1998........................................ 43,677 30,227
December 31, 1999........................................ 896,821 511,936
December 31, 2000........................................ 2,144,595 974,514
December 31, 2001 and later.............................. 723,101 385,939
OVERRIDING ROYALTY INTERESTS
The Company owns overriding royalty interests covering in excess of 114,913
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
The Company markets all of its own natural gas and oil production from wells
that it operates. In addition, the Company engages in natural gas trading
activities, which involve purchasing natural gas from third parties and
selling natural gas to other parties at prices and volumes that management
anticipates will result in profits to
13
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, 1997, less than 3% of the
Company's production was committed to natural gas sales contracts that had
fixed prices or price ceilings. With the exception of two contracts covering
approximately 8,100 MMBtu per day of natural gas production from the Piceance
Basin through 2011, none of the contracts provides for fixed prices or price
ceilings beyond May 1998. 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, 1998, these
transportation arrangements had terms ranging from seven months to nine years.
These transportation agreements provide the Company the opportunity to
transport a portion of its Rocky Mountain natural gas production into the Mid-
Continent area. These agreements in total provide transportation of
approximately 46% of the Company's current daily Rocky Mountain production.
A majority of the Company's Hugoton and Panoma Fields natural gas production
is sold under a long term (life-of-field contract) with KNGSS. The price is
calculated each month by using the average of four Mid-Continent index prices
less a variable amount ranging from $0.11 per MMBtu for an average index price
less than $0.75 to a maximum of $0.20 for an average index price of $2.26 or
higher. The volume of natural gas for which the Company receives payment was
reduced by one percent of the volume as an in-kind fuel charge for moving the
natural gas. By a letter agreement dated December 18, 1997, natural gas sold
between January 1, 1998 and December 31, 2000 under this contract will be
priced in the same manner as in 1997.
During the year ended December 31, 1997, there was one natural gas
purchaser, KNGSS, which accounted for approximately 8.2% 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 President and Chief Executive Officer, the Chief Financial
Officer, Senior Vice President--Finance 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, 1997, the Company had entered into financial transactions
to hedge approximately 5.64 Bcf of natural gas production for the period from
January 1998 through March 1998. In an effort to eliminate price volatility
from its Piceance Basin development program, the Company entered into a series
of hedges throughout 1997 to hedge an aggregate of 123.5 Bcf of natural gas
production from the Rocky Mountain Region for the five-year period from March
1998 through February 2003.
For the year ended December 31, 1997, revenues from trading activities,
which includes the cost of natural gas purchased or sold for trading purposes,
were $171.14 million, which constituted 44.7% of the Company's consolidated
revenues and generated a gross margin of $5.92 million. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations."
14
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 1997. Oil
revenues totaled $39.5 million for the year ended December 31, 1997 and
represented 10% 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 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.
Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act
deregulated natural gas prices for all "first sales" of natural gas, which
includes sales by the Company of its own production. As a result, all sales of
the Company's natural gas produced in the U.S. may be sold at market prices,
unless otherwise committed by contract. Congress could reenact price controls
in the future. See "--Natural Gas and Oil Marketing and Trading."
At the U.S. federal level, the Federal Energy Regulatory Commission ("FERC")
regulates interstate transportation of natural gas under the Natural Gas Act.
The Company's natural gas sales are affected by regulation of intrastate and
interstate natural gas transportation. In an attempt to promote competition,
the FERC has issued a series of orders that have altered significantly the
marketing and transportation of natural gas. The effect of these orders has
been to enable the Company to market its natural gas production to purchasers
other than the interstate pipelines located in the vicinity of its producing
properties. The Company believes that these changes have generally improved
the Company's access to transportation and have enhanced the marketability
15
of its natural gas production. To date, the Company has not experienced any
material adverse effect on natural gas marketing as a result of these FERC
orders; however, the Company cannot predict what new regulations may be
adopted by the FERC and other regulatory authorities, or what effect
subsequent regulations may have on its future natural gas marketing.
The Company also is subject to laws and regulations concerning occupational
safety and health. It is not anticipated that the Company will be required in
the near future to expend amounts that are material in the aggregate to the
Company's overall operations by reason of occupational safety and health laws
and regulations, but inasmuch as such laws and regulations are frequently
changed, the Company is unable to predict the ultimate cost of compliance.
ENVIRONMENTAL MATTERS
The Company, as an owner or lessee and operator of natural gas and oil
properties, is subject to various federal, state and local laws and
regulations relating to discharge of materials into, and protection of, the
environment. These laws and regulations may, among other things, impose
liability and substantial penalties on the lessee under a natural gas and oil
lease for the cost of pollution clean-up resulting from operations, subject
the lessee to liability for pollution damages, require suspension or cessation
of operations in affected areas, and impose restrictions on the injection of
liquid into subsurface aquifers that may contaminate groundwater. The Oil
Pollution Act of 1990, as recently amended by the Coast Guard Authorization
Act of 1996, requires operators of offshore facilities to provide financial
assurance in the amount of $35 million to cover potential environmental
cleanup and restoration costs. This amount is subject to upward regulatory
adjustment.
The Company has made, and will continue to make, expenditures in its efforts
to comply with these requirements, which it believes are necessary business
costs in the oil and gas industry. The Company believes it is in substantial
compliance with applicable environmental laws and requirements and to date
such compliance has not had a material adverse effect on the earnings or
competitive position of the Company, although there can be no assurance that
significant costs for compliance will not be incurred in the future. The
Company maintains insurance coverages which it believes are customary in the
industry although it is not fully insured against many environmental risks.
TITLE TO PROPERTIES
Title to properties is subject to royalty, overriding royalty, carried, net
profits, working and other similar interests and contractual arrangements
customary in the oil and gas industry, to liens for current taxes not yet due
and to other encumbrances. As is customary in the industry in the case of
undeveloped properties, little investigation of record title is made at the
time of acquisition (other than a preliminary review of local records). The
Company reviews information concerning federal and state offshore lease blocks
prior to acquisition. Drilling title opinions are always prepared before
commencement of drilling operations; however, as is customary in the industry,
the Company does not obtain drilling title opinions on offshore leases it has
received directly from the MMS.
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K includes "forward-looking statements" within
the meaning of Section 27A of the Securities Act of 1933, as amended (the
"Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as
amended (the "Exchange Act"). All statements other than statements of
historical facts included in this Annual Report on Form 10-K, including
without limitation statements under "Items 1 and 2. Business and Properties--
Core Areas of Activity", "--Reserves", "--Natural Gas and Oil Marketing and
Trading", and "--Government Regulation of the Oil and Gas Industry", "Item 3.
Legal Proceedings", and "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations", regarding the Company's
financial position, reserve quantities and net present values, business
strategy, plans and objectives of management of the Company for future
operations and capital expenditures, are forward-looking statements. Although
the Company believes that the expectations reflected in the forward-looking
statements and
16
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
PLAINS PETROLEUM TAX CASE
The Internal Revenue Service (IRS) has examined the federal tax returns of
Plains, a subsidiary of Barrett Resources Corporation, for pre-merger calendar
years 1991, 1992 and 1993. The IRS issued a "Notice of Deficiency" of $5.3
million together with penalties of $1.1 million, and an undetermined amount of
interest. The IRS Notice of Deficiency resulted primarily from the IRS's
disallowance of certain net operating loss deductions claimed during the
periods under examination. These net operating losses originally had been
incurred by companies that were acquired by Tri-Power Petroleum, Inc. which
was then acquired by Plains in 1986. For years following 1993, the Company has
additional net operating loss carryforwards of approximately $30 million
related to the same acquisition.
Management disagrees with the IRS position. In management's opinion, the
federal tax returns of Plains reflect the proper federal income tax liability
and the existing net operating loss carryforwards are appropriate as supported
by relevant authority. The Company is vigorously contesting these proposed
adjustments and believes it will prevail in its positions. In this connection,
the Company filed a petition on November 29, 1996 with the United States Court
requesting a redetermination of the IRS's Notice of Deficiency. A May 4, 1998
trial date has been set.
KANSAS AD VALOREM TAX REFUND
The Natural Gas Policy Act of 1978 ("NGPA") permitted producers to receive
from the gas purchaser reimbursement of "severance, production or similar
taxes" on top of the regulated maximum lawful price ("MLP") permitted under
the NGPA. For a number of years the Federal Energy Regulatory Commission
("FERC") and its predecessor, the Federal Power Commission, had ruled that the
Kansas ad valorem tax was similar to a severance tax and, therefore, was
properly payable under the NGPA to a producer. Following an adverse court
decision, the FERC reversed its earlier ruling, finding that the Kansas ad
valorem tax was not similar to a severance tax and, therefore, a producer
could not receive Kansas ad valorem tax reimbursement as an add-on to the MLP.
However, the FERC determined that its later ruling should only apply to
natural gas sold after June 28, 1988. In August 1996, the United States Court
of Appeals for the District of Columbia Circuit upheld the FERC's ruling that
the Kansas ad valorem tax was not similar to a severance tax, but the Court of
Appeals reversed the FERC's decision as to the effective date. Specifically,
the Court of Appeals held that, beginning with October 4, 1983 natural gas
production, a producer could not receive Kansas ad valorem tax reimbursement
as an add-on to the MLP, and, therefore, must refund the ad valorem taxes it
so collected as an add-on to the MLP. On May 12, 1997, the United States
Supreme Court declined to review the Court of Appeals decision. Various
petitions for adjustments were filed with the FERC requesting the FERC waive
all interest which otherwise might be due on the ad valorem taxes to be
refunded and certain portions of the principal amount to be refunded. On
September 10, 1997, the FERC issued an order denying all requests for waiver
of principal and interest. However, the FERC indicated that it will entertain
requests by individual producers for adjustment relief from the refund
requirement if they can show that the payment of refunds will cause "special
hardship, inequity or an unfair distribution of burdens" under the NGPA. The
FERC's order also established certain refund procedures, including a
requirement that pipelines send producers a statement of refunds by
17
November 10, 1997. Requests for rehearing, clarification and stay of the
September 10 order were filed. By an order issued November 10, 1997, the FERC
denied all requests for stay of the September 10 order. On January 28, 1998,
the FERC denied the requests for rehearing and clarification.
On February 4, 1998, Plains received a corrected refund statement for $2.7
million (principal and interest) related to sales to KN Energy, Inc. ("KN")
for the years 1986 to mid-1988. Of this amount, approximately, $2.0 million is
attributable to Plains' working interest. The balance is attributable to other
working interest owners in wells operated by Plains, net profit interest
owners and royalty interest owners. In the fourth quarter of 1997, $2.7
million was recorded as a payable, and a receivable of $700,000 was recorded.
On March 9, 1998, Plains paid $725,000. The week of March 9, 1998, Plains will
place another $1.3 million in escrow pending further orders from the FERC or
the appellate courts. The $500,000 attributable to the royalty interest
owners, has been retained by Plains, pursuant to the FERC's January 28, 1998
order pending collection from the royalty owners. The FERC has stated that, if
a producer is unable to recover the amounts due from the royalty owners, the
producer can apply to the FERC for relief from the uncollectible amounts.
On March 4, 1998, Plains received a second refund statement for $2.85
million (principal and interest) for the 1984-85 period during which Plains
was a subsidiary of KN. Plains has initiated a proceeding at the FERC
requesting a ruling that KN, not Plains, is responsible for refunding this
amount. The FERC has yet to rule on this request. If the FERC denies this
request, Plains will be required to refund $2.02 million (plus additional
interest accruing after March 9, 1998) of this amount and the balance would be
attributable to other working interest, net profit interest and royalty
interest owners in Plains' operated wells. Plains would seek to recover this
$830,000 from the third parties.
At December 31, 1997, 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, 1997.
18
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SECURITY HOLDERS
MATTERS
(a) Market Information. The Company's common stock is listed on the New York
Stock Exchange under the symbol BRR. The range of high and low sales prices
for each quarterly period during the two most recent years, as reported by the
New York Stock Exchange, is as follows:
QUARTER ENDED HIGH LOW
------------- ------ ------
March 31, 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
March 31, 1997............................................... $46.00 $29.87
June 30, 1997................................................ 34.37 26.62
September 30, 1997........................................... 38.93 25.37
December 31, 1997............................................ 41.06 27.93
On March 3, 1998, the closing price for the Company's common stock was
$31.5625 per share.
(b) Holders. The number of record holders of the Company's common stock as
of March 3, 1998, was 3,924.
(c) Dividends. The Company has not paid any cash dividends since its
inception. The Company's credit agreement restricts payment of dividends to
amounts that are less than 50 percent of net income. The Company anticipates
that all earnings will be retained for the development of its business and
that no cash dividends on its common stock will be declared in the foreseeable
future.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth certain selected financial data of the
Company for each of the last five years ended December 31:
YEAR ENDED DECEMBER 31,
---------------------------------------------
1997 1996 1995 1994 1993
-------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
Revenues......................... $382,600 $202,572 $128,016 $109,458 $106,072
Net income (loss)................ 29,261 29,526 (2,240) 11,299 13,666
Per share--assuming dilution..... 0.92 1.02 (0.09) 0.46 0.55
Total assets at the end of each
period.......................... 872,701 576,945 340,412 310,952 243,452
Long-term debt at the end of each
period.......................... 266,437 70,000 89,000 53,000 13,500
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, 1997, the Company had cash and short-term investments of
$14.5 million, negative working capital of $3.2 million, property and
equipment of $747.2 million and total assets of $872.7 million. Compared to
December 31, 1996, cash and short-term investments were unchanged, working
capital decreased $14.6 million, property and equipment increased $259.9
million, and total assets increased $295.8 million.
19
During 1997, the Company generated operating cash flow of $120.1 million
before working capital changes, which is $32.3 million greater than the amount
generated in 1996. After working capital changes, cash flow provided by
operations was $135.4 million, an increase of $46.8 million from 1996.
As of December 31, 1997 and 1996, respectively, the outstanding balance
under the Company's bank credit facility was $100 million and $70 million. The
Company's bank credit facility is an unsecured $250 million facility with a
consortium of six banks. As of December 31, 1997, the Company's borrowing base
was $150 million. 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. At
the time of borrowing funds under the bank credit facility, interest begins to
accrue on those funds, at the Company's election, at either the London
Interbank Eurodollar Rate (LIBOR) plus a spread ranging from 0.185 percent to
0.625 percent (depending on the Company's senior debt rating and the ratio of
the Company's outstanding indebtedness to its earnings before interest, taxes
and depreciation, depletion and amortization) or at the United States prime
rate of interest. The Company is required to pay interest on a quarterly basis
until the entire outstanding balance matures on September 30, 2002.
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. Interest is paid semi-annually
on February 1 and August 1 of each year.
In April 1997, the Company acquired through a subsidiary additional
interests in properties located in the Piceance Basin of Colorado. The
subsidiary is a limited liability company in which the Company owns a
99 percent interest. In connection with this transaction, the Company issued a
put option to the owner of the one percent minority interest of the
subsidiary. If exercised, the put obligates the Company to purchase the one
percent minority interest in the subsidiary. This put option can be exercised
by the holder at any time prior to January 31, 2012. The Company has the right
to require the minority interest to sell its interest in the subsidiary to the
Company after January 1, 2002 but prior to January 31, 2012. Should either the
minority interest or the Company exercise its rights, the Company will issue
150,000 shares of its common stock as consideration.
In November 1997, the Company sold its interest in certain Colorado
properties to an investment group which includes a Company subsidiary. For
accounting purposes, the Company has treated the sale as a non-recourse
monetary production payment reflected as long-term debt on the balance sheet.
Net of transaction costs, the proceeds from the sale were approximately $15.5
million in cash. Payments of the production payment liability are funded from
operating cash flow of the affected properties, less funds required for
working capital purposes. The liability is expected to be fully repaid in
2003.
As of December 31, 1997, the Company recorded a liability of $2.7 million,
including principal and interest, for the refund of Kansas ad valorem tax
reimbursements received in 1986. This liability is the result of a United
States Court of Appeals decision that reversed a Federal Energy Regulatory
Commission's decision with respect to producer reimbursement of Kansas ad
valorem tax as an add-on to the maximum lawful price under the Natural Gas
Policy Act of 1978. Of the $2.7 million refund liability, approximately
$700,000 of it is recoverable from other working, royalty and net profits
interest owners. A receivable has been established for this recoverable
amount. The Company has received an additional refund statement of $2.85
million ($2.02 million net to the Company) for Kansas ad valorem tax
reimbursements relating to the period of October 1984 through September 1985.
The Company believes that it is not responsible for this refund and is
disputing the claim. See "Item 3. Legal Proceedings" of this Form 10-K.
The Company is currently evaluating its information technology
infrastructure for Year 2000 compliance. The Company does not expect that the
cost, if any, to modify its information technology infrastructure to be Year
2000 compliant will be material to its financial condition or results of
operations. The Company does not anticipate any material disruption in its
operations as a result of any failure by the Company, its customers or
suppliers to be in compliance.
20
Capital Expenditures
During 1997 the Company invested $333.9 million in oil and gas properties
and other equipment, including acquisitions and exploration and development
programs. Acquired oil and gas property working interests were located
principally in the Gulf of Mexico and the Powder River and Uinta Basins.
Exploration and development programs were concentrated in the Anadarko,
Arkoma, Piceance, Powder River, Wind River and Uinta Basins, the Gulf of
Mexico and the Republic of Peru. During the year the Company continued to
expand its exploration programs with investments in leases in the Gulf of
Mexico, offshore Louisiana and Texas, and international programs in the
Republic of Peru.
The Company's capital expenditure budget for 1998 has been established at
$190.0 million. In response to lower product prices and the desire to maintain
debt levels, the Company decreased its 1998 capital expenditure budget by
$143.9 million from the 1997 capital expenditure level. During 1998, the
Company expects to spend approximately $43.1 million in exploring and
developing its prospects in the Gulf of Mexico Region. Other significant
budgeted exploratory and development capital expenditures include $79.9
million in the Rocky Mountain Region with emphasis in the Wind River and
Piceance Basins, $27.4 million in the Mid-Continent Region, and $23.9 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.
Reserves and Pricing
Proved reserves at year end 1997 were 963.2 billion cubic feet of natural
gas equivalents (Bcfe), an 18 percent increase over December 31, 1996 proved
reserves. Approximately 83 percent of the reserve additions were generated
through exploration and development projects and 17 percent of the reserve
additions were provided by property acquisitions. Proved reserves were reduced
by production of approximately 90.0 Bcfe, sales of properties with reserves of
8.2 Bcfe, and downward revisions of previous estimates of 124.9 Bcfe. Lower
year end prices and lower than expected performance of certain properties
contributed to the adjustments of previous estimates. During 1997, as a result
of its drilling and acquisition activities net of sales and revisions, the
Company's reserve replacement was 265 percent of total production.
As of year end 1997, the standardized measure of discounted future net cash
flows decreased $201 million, or 26 percent, from 1996 primarily due to
reserve revisions and decreases in oil and gas prices offset by reserve
quantity additions. Reserve extensions and discoveries added $196 million to
the standardized measure, and purchases of proved reserves, net of sales,
added $32 million. The changes in year end sales prices and production costs
from 1996 to 1997 decreased the standardized measure of discounted future net
cash flows by $457 million. Reserves produced during the year reduced the
standardized measure by $153 million. The Company's standardized measure of
discounted future net cash flows is sensitive to gas prices in the current
volatile commodities market.
Oil and natural gas prices fluctuate throughout the year. Higher natural gas
prices generally prevail during the winter months of December through
February. As of December 31, 1997, the Company was receiving weighted average
prices of $15.52 per barrel of oil and $2.19 per Mcf of gas. A 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
21
changes. As of December 31, 1997, the Company held positions to hedge 129.1
Bcf of the Company's future natural gas production through February 2003. 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.
RESULTS OF OPERATIONS
In 1997, the Company adopted Statement of Financial Accounting Standards No.
128, "Earnings Per Share" (SFAS No. 128). As prescribed by SFAS No. 128,
earnings per share amounts for 1996 and 1995 have been restated. References to
per share amounts are based on diluted shares outstanding.
1997 vs. 1996
During 1997, the Company earned net income of $29.3 million ($.92 per share)
compared to $29.5 million ($1.02 per share) in 1996.
Revenues increased $180 million (89 percent) to $382.6 million in 1997.
Operating expenses increased 112 percent to $335.4 million. In 1997, oil and
gas production revenue increased 36 percent to $206.9 million, and trading
revenues increased 265 percent to $171.1 million. Lease operating expenses
increased $10.3 million and depreciation, depletion and amortization increased
$26.6 million.
Production revenues increased $55.2 million to $206.9 million primarily due
to a 46 percent increase in gas revenues. The increased gas revenues are a
result of an increase in the average gas price from $1.88 per Mcf in 1996 to
$2.18 per Mcf in 1997 and an increase in gas production of 15.7 Bcf (26
percent) for 1997. Gas production accounted for 85 percent of total production
on an energy equivalent basis. The Wind River Basin and Piceance Basin
properties accounted for 26 percent and 21 percent, respectively, of total gas
production. The Powder River Basin and Uinta Basin properties accounted for 40
percent and 23 percent, respectively, of total oil production.
Lease operating expenses of $57.9 million averaged $.64 per Mcfe ($3.86 per
BOE) compared to $.66 per Mcfe ($3.95 per BOE) in 1996. Depreciation,
depletion and amortization increased $26.6 million primarily due to production
increases. During 1997, depletion and amortization on oil and gas production
was provided at an average rate of $.77 per Mcfe ($4.60 per BOE) compared to
an average rate of $.59 per Mcfe ($3.54 per BOE) in 1996.
The gross margin on trading activities increased $3,096,000 to $5,922,000 in
1997. Gas trading volumes increased 183 percent to 84.8 Bcf in 1997.
The Company enters into 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 1997, the Company
hedged 18.6 Bcf (24 percent) of its gas production for a net cost of $4.3
million. No oil was hedged during 1997.
General and administrative expenses of $24.9 million reflect an increase of
47 percent over the previous year. The 1997 amount is net of $5.0 million of
operating fee recoveries compared to a $4.0 million recovery in
22
1996. The 1997 increase in general and administrative expenses is a result of
the Company's continued growth and expansion. Interest expense increased
significantly from $3.7 million in 1996 to $13.2 million in 1997 due primarily
to the issuance of $150 million of long term bonds in February 1997.
Income tax expense increased by 20 percent in 1997 to $17.9 million. The
Company's effective financial statement tax rate in 1997 was 38.0 percent
compared to 33.6 percent in 1996.
1996 vs. 1995
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.
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, 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 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.
23
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.
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.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
The Consolidated Financial Statements and schedules that constitute Item 8
are attached at the end of this Annual Report on Form 10-K. An index to these
Consolidated Financial Statements and Schedules is also included in Item 14(a)
of this Annual Report on Form 10-K.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURES
Not applicable.
24
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY
The directors and executive officers of the Company, their respective ages
and positions, and the year in which each director was first elected, are set
forth in the following table. Additional information concerning each of these
individuals follows the table:
DIRECTOR
AGE POSITION WITH THE COMPANY SINCE
--- ------------------------- --------
William J. Barrett (1)(2)(5)(7)... 69 Chairman of the Board 1983
C. Robert Buford (1)(2)(3)(4)..... 64 Director 1983
Derrill Cody (2)(3)(4)............ 59 Director 1995
James M. Fitzgibbons (3)(4)(6).... 63 Director 1987
William W. Grant, III (3)(4)...... 65 Director 1995
J. Frank Keller (5)............... 54 Executive Vice President,
Chief Financial Officer, and
a Director 1983
Paul M. Rady (1)(2)............... 44 President, Chief Executive
Officer, and a Director 1994
A. Ralph Reed..................... 60 Executive Vice President--
Operations and a Director 1990
James T. Rodgers (3)(4)........... 63 Director 1993
Philippe S.E. Schreiber (2)(3)(4). 57 Director 1985
Harry S. Welch (3)(4)(8).......... 74 Director 1995
Joseph P. Barrett (7)............. 44 Vice President--Land --
Peter A. Dea...................... 44 Senior Vice President--
Onshore Exploration --
Clifford S. Foss, Jr.............. 50 Senior Vice President and
General Manager--Gulf of
Mexico Region --
Bryan G. Hassler.................. 39 Vice President--Marketing --
Robert W. Howard.................. 43 Senior Vice President--
Finance and Treasurer --
Eugene A. Lang, Jr................ 44 Senior Vice President and
General Counsel; and
Secretary --
Logan Magruder, III............... 41 Vice President--Corporate
Relations and Capital
Markets --
Maurice F. Storm.................. 37 Vice President and General
Manager--Mid-Continent
Region --
- --------
(1) Member of the Executive Committee of the Board of Directors.
(2) Member of the Board Planning and Nominating Committee of the Board of
Directors.
(3) Member of the Audit Committee of the Board of Directors.
(4) Member of the Compensation Committee of the Board of Directors.
(5) J. Frank Keller and William J. 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) Mr. Welch will retire as a director at the April 30, 1998 Annual Meeting
of Stockholders. The size of the Board of Directors will be reduced from
11 to 10 members at that time.
WILLIAM J. BARRETT has served as Chairman of the Board since September 1994.
From September 1994 through June 30, 1997, he was Chairman of the Board and
Chief Executive Officer. Mr. Barrett also was President and Chief Executive
Officer of the Company from December 1983 through September 1994. From January
1979 to February 1982, Mr. Barrett was an independent oil and gas operator in
the western United States in association with Aeon Energy, a partnership
composed of four sole proprietorships. From 1971 to 1978, Mr. Barrett served
as Vice President--Exploration and a director of Rainbow Resources, Inc., a
publicly held independent oil and gas exploration company that merged with a
subsidiary of the Williams Companies in 1978. Mr. Barrett served as President,
Exploration Manager and Director for B&C Exploration from 1969 until 1971 and
was 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
25
an exploration geologist, a petroleum geologist and a stratigrapher for El
Paso Natural Gas Co. at various times from 1958 to 1963. Mr. Barrett intends
to retire as Chairman of the Board in January 1999.
C. ROBERT BUFORD has been a director of the Company since December 1983 and
served as Chairman of the Board of Directors from December 1983 through March
1994. Mr. Buford has been President, Chairman of the Board and controlling
shareholder of Zenith Drilling Corporation ("Zenith"), Wichita, Kansas, since
February 1966. Zenith owns approximately 1.9 percent of the Company's Common
Stock. Since 1993, Mr. Buford has served as a director of Encore Energy, Inc.,
a wholly-owned subsidiary of Zenith engaged in the marketing of natural gas.
Mr. Buford is also a member of the Board of Directors of Intrust Financial
Corporation, a bank holding company. Mr. Buford served as a director of
Lonestar Steakhouse & Saloon, Inc. from March 1992 until January 1997.
DERRILL CODY has been a director of the Company since July 1995. From May
1990 until July 1995, Mr. Cody served as a director of Plains, which merged
with a subsidiary of the Company on July 18, 1995. Since January 1990, Mr.
Cody has been an attorney in private practice in Oklahoma City, Oklahoma. From
1986 to 1990, he was Executive Vice President of Texas Eastern Corporation,
and from 1987 to 1990 he was the Chief Executive Officer of Texas Eastern
Pipeline Company. He has been a director of the General Partner of TEPPCO
Partners, L.P. since January 1990.
JAMES M. FITZGIBBONS has been a director of the Company since January 1994,
and previously served as a director of the Company from July 1987 until
October 1992. From October 1990 through December 1997, Mr. Fitzgibbons was
Chairman and Chief Executive Officer of Fieldcrest Cannon, Inc. From January
1986 until October 1990, Mr. Fitzgibbons was President of Amoskeag Company.
Prior to 1986, he was President of Howes Leather Company. Mr. Fitzgibbons is
also member of the Board of Directors of Lumber Mutual Insurance Company and
of American Textile Manufacturers Institute, and he is a Trustee of Dreyfus
Laurel Funds, a series of mutual funds.
WILLIAM W. GRANT, III has served as a director of the Company since July
1995. From May 1987 until July 1995, Mr. Grant served as a director of Plains.
He has been an advisory director of Colorado National Bank since 1993. He was
a director of Colorado National Bankshares, Inc. from 1982 to 1993 and the
Chairman of the Board of Colorado National Bank of Denver from 1986 to 1993.
He served as the Chairman of the Board of Colorado Capital Advisors from 1989
through 1994.
J. FRANK KELLER has been an Executive Vice President, and a director of the
Company since December 1983 and Chief Financial Officer of the Company since
July 1995. From December 1983 through June 1997, he also served as Secretary.
Mr. Keller was the President and a co-founder of Myriam Corp., an
architectural design and real estate development firm beginning in 1976, until
it was reorganized as Barrett Energy in February 1982.
PAUL M. RADY had been President, Chief Operating Officer, and a director of
the Company since September 1994. Effective as of July 1, 1997, Mr. Rady
became Chief Executive Officer. From February 1993 to September 1994, Mr. Rady
served as Executive Vice President--Exploration of the Company. 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.
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 natural gas operator in the Mid-Continent region of
the United States, including the period from January 1988 to November 1989
when he acted as a consultant to Zenith. From 1982 to 1986, Mr. Reed was
President and Chief Executive Officer of Cotton Petroleum Corporation
("Cotton"), a wholly owned exploration and production subsidiary of United
Energy Resources, Inc. Prior to joining Cotton in 1980, Mr. Reed was employed
by Amoco from 1962, holding various positions including Manager of
International Production, Division Production Manager and Division Engineer.
26
JAMES T. RODGERS has been a director of the Company since November 1993. Mr.
Rodgers served as the President, Chief Operating Officer and a director of
Anadarko Petroleum Corporation ("Anadarko") from 1986 through 1992. Prior to
1986, Mr. Rodgers was employed in other capacities by Anadarko and Amoco.
Mr. Rodgers taught Petroleum Engineering at the University of Texas in Austin
in 1958 and at Texas Tech University in Lubbock from 1958 to 1961. Mr. Rodgers
served as a Director of Louis Dreyfus Natural Gas Corporation until October
1997, and he currently serves as a director of Khanty-Mansysr Oil Corporation,
a privately held exploration and production company operating in the former
Soviet Union.
PHILIPPE S.E. SCHREIBER has been a director of the Company since November
1985. Mr. Schreiber is an independent lawyer and business consultant 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. Mr. Schreiber is a
Director of the United States affiliates of The Mayflower Corporation plc., a
British publicly traded company involved in the business of supplying parts
and components to auto and truck manufacturers.
JOSEPH P. BARRETT has been Vice President--Land since March 1995 and has
been with the Company in various positions in the Company's Land Department
since 1982.
PETER A. DEA has been Senior Vice President--Onshore 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. Mr. Dea served as adjunct Professor of
Geology at Western State College, Gunnison, Colorado in the spring semesters
of 1980 and 1982.
CLIFFORD S. FOSS, JR. has been General Manager of the Gulf of Mexico Region
for the Company since January 1996 and Senior Vice President--General Manager
of the Gulf of Mexico Region for the Company since July of 1996. Prior to
joining the Company, Mr. Foss served from January 1973 to 1996 in various
positions with Cockrell Oil Corporation as Geologist, District Geologist,
Exploration Manager and Vice President of Exploration and Exploitation. 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 was Marketing
Coordinator for Questar Corporation's Marketing Group and Mr. Hassler held
various engineering positions with Questar Corporation's exploration and
production and pipeline groups.
ROBERT W. HOWARD has been Senior Vice President of the Company since March
1992. Mr. Howard served as the Executive Vice President--Finance from December
1989 until March 1992 and served as Vice President--Finance of the Company
from December 1983 until December 1989. Mr. Howard has been the Treasurer of
the Company since March 1986. During 1982, Mr. Howard was a Manager/Accountant
with Weiss & Co., a certified public accounting firm.
EUGENE A. LANG, JR. has been Senior Vice President--General Counsel of the
Company since September 1995. In June 1997, Mr. Lang was also elected
Secretary. Mr. Lang served as Senior Vice President, General Counsel and
Secretary of Plains from May 1994 to July 1995, and from October 1990 to May
1994 he served as Vice President, General Counsel and Secretary of Plains.
From September 1986 to September 1990 he was an associate with the Houston,
Texas law firm of Vinson & Elkins. From 1984 to 1986, he was General Attorney
and Assistant Secretary of K N. From 1978 to 1984, he was an attorney with K
N.
27
LOGAN MAGRUDER III was elected Vice President--Corporate Relations and
Business Development in October 1997. From December 1996 through October 1997
he served as Manager of Operations in the Company's Gulf of Mexico Division.
From November 1995 to December 1996, Mr. Magruder served as Director of
Engineering and Operations for Scana Petroleum and from 1991 to 1993, Mr.
Magruder served as a Vice President of Torch Energy. From 1980 to 1991, Mr.
Magruder held petroleum engineering and corporate relations positions with
other exploration and production companies.
MAURICE F. STORM has been Vice President and General Manager of the
Company's Mid-Continent Division since July 1996. From October 1991 to July
1996 Mr. Storm was retained by the Company as a consultant to develop drilling
opportunities in the Anadarko and Arkoma Basins. From September 1984 through
October 1991 Mr. Storm worked for other independent exploration and production
companies in various exploration geologist and management positions.
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Securities Exchange Act of 1934, as amended (the
"Exchange Act"), requires the Company's directors, executive officers and
holders of more than 10% of the Company's common stock to file with the
Securities and Exchange Commission initial reports of ownership and reports of
changes in ownership of common stock and other equity securities of the
Company. The Company believes that during the fiscal year ended December 31,
1997, its officers, directors and holders of more than 10% of the Company's
common stock complied with all Section 16(a) filing requirements. In making
these statements, the Company has relied upon the written representations of
its directors and officers.
28
ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
The following table sets forth in summary form the compensation received
during each of the Company's last three completed years by the Chief Executive
Officer of the Company and by the four other most highly compensated executive
officers whose compensation exceeded $100,000 during the year ended December
31, 1997. The figures in the following table are for fiscal years ended
December 31, 1997, 1996, and 1995:
SUMMARY COMPENSATION TABLE
LONG TERM COMPENSATION
--------------------------------
AWARDS PAYOUTS
----------------------- --------
RESTRICTED SECURITIES
OTHER ANNUAL STOCK UNDERLYING LTIP ALL OTHER
NAME AND PRINCIPAL FISCAL COMPENSATION AWARD(S) OPTIONS/SARS PAYOUTS COMPENSATION
POSITION YEAR SALARY ($) BONUS ($)(/1/) ($)(/2/) ($)(/3/) (#)(/4/) ($)(/5/) ($)(/6/)
------------------ ------ ---------- -------------- ------------ ---------- ------------ -------- ------------
William J. Barrett...... 1997 $215,000 $250,000 -0- -0- 50,000 -0- $9,500
Chairman of the Board 1996 $255,417 $150,000 -0- -0- 100,000 -0- $7,913
1995 $200,000 -0- -0- -0- -0- -0- $4,680
Paul M. Rady............ 1997 $266,252 $160,000 -0- -0- 50,000 -0- $9,500
President, Chief 1996 $206,667 $ 63,000 -0- -0- 52,000 -0- $8,138
Executive Officer, 1995 $175,000 -0- -0- -0- -0- -0- $4,680
and a director
A. Ralph Reed........... 1997 $217,500 $120,000 -0- -0- -0- -0- $9,500
Executive Vice 1996 $207,917 $ 54,000 -0- -0- 40,000 -0- $7,988
President-- 1995 $200,000 -0- -0- -0- -0- -0- $4,680
Operations, and a
director
J. Frank Keller......... 1997 $165,768 $ 90,000 -0- -0- 26,700 -0- $9,500
Executive Vice 1996 $155,938 $ 40,000 -0- -0- 19,200 -0- $8,222
President, Chief 1995 $150,000 -0- -0- -0- -0- -0- $4,560
Financial Officer,
and a director
Peter A. Dea............ 1997 $153,750 $ 65,000 -0- -0- 7,500 -0- $8,838
Senior Vice President-- 1996 $134,625 $ 25,000 -0- -0- 30,000 -0- $7,224
Onshore Exploration 1995 $ 97,292 -0- -0- -0- -0- -0- $2,249
- --------
(1) The dollar value of bonus (cash and non-cash) paid during the year
indicated. In February 1998, cash bonuses were determined by the
Compensation Committee based upon the Company's performance in 1997. These
bonuses, which will be paid on March 31, 1998, include $150,000 for Mr.
Barrett, $95,000 for Mr. Rady, $70,000 for Mr. Reed, $50,000 for Mr.
Keller, and $35,000 for Mr. Dea. See "Compensation Committee Report on
Executive Compensation--Cash Bonus Awards".
(2) During the period covered by the Table, the Company did not pay any other
annual compensation not properly categorized as salary or bonus, including
perquisites and other personal benefits, securities or property.
(3) During the period covered by the Table, the Company did not make any award
of restricted stock, including share units.
(4) The sum of the number of shares of Common Stock to be received upon the
exercise of all stock options granted.
(5) Except for stock option plans, the Company does not have in effect any
plan that is intended to serve as incentive for performance to occur over
a period longer than one fiscal year.
(6) Represents the Company's matching contribution under the Company's 401(k)
Plan for each named executive officer.
29
OPTION GRANTS IN LAST FISCAL YEAR
No stock appreciation rights were granted to any executive officers or
employees in the year ended December 31, 1997. The following table provides
information on stock option grants in the year ended December 31, 1997 to the
named executive officers.
OPTION GRANTS IN LAST FISCAL YEAR
NUMBER OF % OF TOTAL POTENTIAL REALIZABLE VALUE
SECURITIES OPTIONS AT ASSUMED ANNUAL RATES
UNDERLYING GRANTED TO OF STOCK PRICE APPRECIATION
OPTIONS EMPLOYEES EXERCISE FOR OPTION TERM
GRANTED IN FISCAL PRICE EXPIRATION ---------------------------
NAME (#) YEAR ($/SHARE) DATE 5% 10%
- ---- ---------- ---------- --------- -------------- ---------------------------
William J. Barrett...... 50,000(1) 7.0% $32.875 March 21, 2004 $ 669,250 $ 1,559,250
Paul M. Rady............ 50,000(2) 7.0% $32.875 March 21, 2004 $ 669,250 $ 1,559,250
A. Ralph Reed........... -- -- -- -- -- --
J. Frank Keller......... 26,700(2) 3.7% $32.875 March 21, 2004 $ 357,380 $ 832,640
Peter A. Dea............ 7,500(2) 1.0% $32.875 March 21, 2004 $ 100,388 $ 233,888
- --------
(1) These option shares become exercisable on March 21, 1998.
(2) One-fourth of these option shares become exercisable on each of March 21,
1998, March 21, 1999, March 21, 2000, and March 21, 2001.
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, 1997 by the Company's Chief
Executive Officer and the four other most highly compensated executive
officers of the Company whose compensation exceeded $100,000 during the year
ended December 31, 1997 and the year-end value of unexercised options held by
these persons:
AGGREGATED OPTION EXERCISES
FOR FISCAL YEAR ENDED DECEMBER 31, 1997
AND YEAR-END OPTION VALUES (/1/)
NUMBER OF SECURITIES
UNDERLYING UNEXERCISED VALUE OF UNEXERCISED
OPTIONS AT FISCAL YEAR- IN-THE-MONEY OPTIONS AT
END (#)(4) FISCAL YEAR-END($)(5)
------------------------- -------------------------
SHARES
ACQUIRED ON VALUE REALIZED
NAME EXERCISE(2) ($)(3) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
---- ----------- -------------- ----------- ------------- ----------- -------------
William J. Barrett...... 7,476 $164,939 72,524 125,000 $693,843 $756,875
Chairman of the Board
Paul M. Rady............ -- -- 65,500 106,500 $870,187 $537,063
President, Chief
Executive Officer,
and a director
A. Ralph Reed........... -- -- 70,048 55,000 $903,510 $575,275
Executive Vice
President--
Operations and a
director
J. Frank Keller......... -- -- 46,050 54,850 $664,631 $312,744
Executive Vice
President, Chief
Financial Officer, and
a director
Peter A. Dea............ -- -- 22,500 35,000 $302,812 $148,438
Senior Vice President--
Onshore Exploration
- --------
(1) No stock appreciation rights are held by any of the named executive
officers.
(2) The number of shares received upon exercise of options during the year
ended December 31, 1997.
30
(3) With respect to options exercised during the Company's year ended December
31, 1997, 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, 1997,
separated between those options that were exercisable and those options
that were not exercisable.
(5) For all unexercised options held as of December 31, 1997, 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, 1997. As
required, the price used to calculate these figures was the closing sale
price of the Common Stock at year's end, which was $30.25 per share on
December 31, 1997. On March 3, 1998, the closing sale price was $31.5625
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 employee's 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 matching contribution paid in cash and one-half paid in the Company's
common stock. The Company's matching contribution is subject to a vesting
schedule. Benefits payable to employees upon retirement are based on the
contributions made by the employee under the 401(k) Plan, the Company's
matching contributions, and the performance of the 401(k) Plan's investments.
Therefore, the Company cannot estimate the annual benefits that will be
payable to participants in the 401(k) Plan upon retirement at normal
retirement age. Excluding the 401(k) Plan, the Company has no defined benefit
or actuarial or pension plans or other retirement plans.
Excluding the Company's stock option plans, the Company has no long-term
incentive plan to serve as incentive for performance to occur over a period
longer than one fiscal year.
COMPENSATION OF DIRECTORS
Standard Arrangements. Pursuant to the Company's standard arrangement for
compensating directors, no compensation for serving as a director is paid to
directors who also are employees of the Company, and those directors who are
not also employees of the Company ("Outside Directors") receive an annual
retainer of $20,000 paid in equal quarterly installments. In addition, for
each Board of Directors or committee meeting attended, each Outside Director
receives a $1,000 meeting attendance fee. Each Outside Director also receives
$300 for each telephone meeting lasting more than 15 minutes. The Chairman of
the Compensation and Audit Committees receives a $1,500 meeting attendance fee
for each committee meeting. The Company also reimburses directors for out-of-
pocket expenses incurred in attending meetings. For each Board of Directors or
committee meeting attended, each Outside Director will have options to
purchase 1,000 shares of Common Stock become exercisable. Although these
options become exercisable only at the rate of 1,000 for each meeting
attended, each director will be granted options to purchase 10,000 shares at
the time the individual initially becomes a director. Any options that have
not become exercisable at the time of termination of a director's service will
expire at that time. At such time that the options to purchase all 10,000
shares have become exercisable, options to purchase an additional 10,000
shares will be granted to the director and will be subject to the same
restrictions on exercise as the previously received options. The options are
granted to the Outside Directors pursuant to the Company's Non-Discretionary
Stock Option Plan, and 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.
31
Other Arrangements. During the year ended December 31, 1997, no compensation
was paid to directors of the Company other than pursuant to the standard
compensation arrangements described in the previous section.
EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT AND CHANGE-IN-CONTROL
ARRANGEMENTS
The Company has entered into severance agreements (the "Agreements") with
Messrs. Barrett, Rady, Reed, Keller, and Dea. Generally, the Agreements of
Messrs. Rady, Reed, Keller and Dea provide, among other things, that if,
within three years after a Change-in-Control (as defined in the Agreement) the
employee's employment is terminated by the employee for "Good Reason" or by
the Company other than for "Cause" (as such terms are defined in the
Agreement), the employee will be entitled to a lump sum cash payment equal to
three times (two times in the case of Mr. Dea) the employee's annual
compensation (which includes annual salary and bonus) in addition to
continuation of certain benefits for three years (two years in the case of
Mr. Dea) from the date of termination. Mr. Barrett's Agreement provides that,
if his employment is terminated by him for Good Reason or by the Company other
than for Cause prior to January 31, 1999, he will receive a lump sum cash
amount equal to the compensation that would have been paid from his
termination dated through January 31, 1999, in addition to continued benefits
through January 31, 1999.
In addition, the Company's stock option plans and option agreements
thereunder provide for the acceleration of option exercisability in the event
of a change-in-control.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
During the year ended December 31, 1997, each of Messrs. Buford, Cody,
Fitzgibbons, Gieskes (through September 7, 1997), Grant, Rodgers, Schreiber,
and 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, 1997 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.
32
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table summarizes certain information as of March 3, 1998 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:
AMOUNT/NATURE OF
NAME OF BENEFICIAL PERCENT OF CLASS
BENEFICIAL OWNER OWNERSHIP BENEFICIALLY OWNED
---------------- ------------------ ------------------
William J. Barrett................... 521,509 Shares(1) 1.6%
C. Robert Buford..................... 658,366 Shares(2) 2.1%
Derrill Cody......................... 17,560 Shares(3) *
Peter A. Dea......................... 33,616 Shares(3) *
James M. Fitzgibbons................. 16,500 Shares(3) *
William W. Grant, III................ 31,150 Shares(3) *
J. Frank Keller...................... 108,024 Shares(3) *
Paul M. Rady......................... 121,302 Shares(3) *
A. Ralph Reed........................ 123,620 Shares(4) *
James T. Rodgers..................... 17,000 Shares(3) *
Philippe S.E. Schreiber.............. 22,507 Shares(3) *
Harry S. Welch....................... 24,800 Shares(3) *
All Directors and Executive Officers
as a Group (19 persons)............. 1,869,804 Shares(5) 5.8%
State Farm Mutual Automobile
Insurance Company and affiliates.... 2,934,133 Shares(6)(7) 9.3%
One State Farm Plaza
Bloomington, IL 61710
Franklin Resources, Inc.............. 3,824,536 Shares(6) 12.2%
777 Mariners Island
San Mateo, CA 94403
- --------
* Less than 1% of the Common Stock outstanding.
(1) The number of shares indicated includes 25,292 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 192,524 shares underlying
options that currently are exercisable or become exercisable within 60
days following March 3, 1998. Pursuant to Rule 16a-1(a)(4) under the
Exchange Act, Mr. Barrett disclaims ownership of all but 144,722 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
Exchange Act. The number of shares indicated also includes 16,500 shares
underlying stock options are currently exercisable or that become
exercisable within 60 days following March 3, 1998.
(3) The number of shares indicated consists of or includes the following
number of shares underlying options that currently are exercisable or that
become exercisable within 60 days following March 3, 1998 that are held by
each of the following persons: Derrill Cody, 17,300; Peter A. Dea, 31,875;
James M. Fitzgibbons, 14,500; William W. Grant, III, 18,800; J. Frank
Keller, 66,125; Paul M. Rady, 100,000; James T. Rodgers, 17,000; Philippe
S.E. Schreiber, 15,500; and Harry S. Welch, 22,200.
(4) The number of shares indicated includes 7,800 shares owned by Mary C.
Reed, Mr. Reed's wife and 90,848 shares underlying options that currently
are exercisable or that become exercisable within 60 days following March
3, 1998.
33
(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 603,172 shares underlying the options described in notes (1),
(2), (3) and (4), an aggregate of 32,366 shares owned by seven executive
officers not named in the above table, and an aggregate of 141,484 shares
underlying options that currently are exercisable or that are exercisable
within 60 days following March 3, 1998 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.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
During 1997, there were no transactions between the Company and its
directors, executive officers or known holders of greater than five percent of
the Company's Common Stock in which the amount involved exceeded $60,000 and
in which any of the foregoing persons had or will have a material interest.
34
PART IV
ITEM 14. EXHIBITS, FINANCIAL SCHEDULES, AND REPORTS ON FORM 8-K
(a)(1) and (a)(2) Financial Statements And Financial Statement Schedules
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
Report Of Independent Public Accountants............................... F-1
Consolidated Balance Sheets at December 31, 1997 and 1996.............. F-2
Consolidated Statements of Income for each of the three years in the
period ended December 31, 1997........................................ F-3
Consolidated Statements of Stockholders' Equity for each of the three
years in the period ended December 31, 1997........................... F-4
Consolidated Statements of Cash Flows for each of the three years in
the period ended December 31, 1997.................................... F-5
Notes to Consolidated Financial Statements............................. F-6
Supplemental Oil And Gas Information................................... F-20
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 in 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, 1997.
35
BARRETT RESOURCES CORPORATION
ANNUAL REPORT ON FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 1997
EXHIBIT INDEX
EXHIBIT DESCRIPTION
- ------- -----------
2.1 Agreement And Plan of Merger, dated as of May 2, 1995, among Barrett Resources
Corporation ("Barrett" or "Registrant"), Barrett Energy Inc. (formerly known as
Vanilla Corporation), and Plains Petroleum Company ("Plains") is incorporated by
reference from Annex I to the Joint Proxy Statement/Prospectus of Barrett and
Plains dated June 13, 1995.
3.1 Restated Certificate Of Incorporation of Barrett Resources Corporation, a Delaware
corporation, is incorporated herein by reference from Exhibit 3.2 of Registrant's
Registration Statement on Form S-4 dated June 9, 1995.
3.2 Certificate of Amendment to Certificate of Incorporation of Barrett dated June 17,
1997.
3.3 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.
4.1 Form of Rights Agreement dated as of August 5, 1997 between the Company and Bank
Boston, N.A., which includes, as Exhibit A thereto, the form of Certificate of
Designations specifying the terms of the Series A Junior Participating Preferred
Stock, and as Exhibit B thereto, the form of Rights Certificate, is incorporated by
reference from Exhibit 1 to the Company's Registration Statement on Form 8-A filed
August 11, 1997.
4.2 Revised Form of Indenture between the Company and Bankers Trust Company, as
trustee, with respect to Senior Notes including specimen of 7.55% Senior Notes is
incorporated by reference from Exhibit 4.1 to the Company's Amendment No. 1 to
Registration Statement on Form S-3 filed February 10, 1997, File No. 333-19363.
10.1 Non-Qualified Stock Option Plan Of Barrett Resources Corporation is incorporated by
reference from Registrant's Registration Statement on Form S-8 dated November 15,
1989.
10.2 Registrant's 1990 Stock Option Plan, as amended, is incorporated by reference from
the Registrant's Registration Statement on Form S-8 dated March 15, 1995.
10.3 Registrant's Non-Discretionary Stock Option, as amended, is incorporated by
reference from Exhibit 99.2 of the Registrant's Proxy Statement dated April 24,
1997.
10.4 Registrant's 1994 Stock Option Plan, as amended, is incorporated by reference from
the Registrant's Registration Statement on Form S-8 dated March 15, 1995.
10.5 Registrant's 1997 Stock Option Plan is incorporated by reference from Exhibit 99.1
of the Registrant's Proxy Statement dated April 24, 1997.
10.6A Gas Purchase Contract, No. P-1090, dated April 20, 1984, as amended, between Plains
and KN Energy, Inc. is incorporated by reference from Plains Petroleum Company's
Registration Statement on Form 10 dated August 21, 1985.
10.6B Letter Agreement dated January 11, 1996, amending the Gas Purchase Contract, No. P-
1090, dated April 20, 1984, between Plains and KN Energy, Inc. is incorporated by
reference from Exhibit 10.5B of the Registrant's Annual Report on Form 10-K for the
year ended December 31, 1996.
36
10.7A Revolving Credit Agreement dated as of July 19, 1995 among Barrett and Texas
Commerce Bank National Association, as Agent, and Texas Commerce Bank National
Association, Nations Bank of Texas, N.A., Bank of Montreal, Houston Agency,
Colorado National Bank, and The First National Bank of Boston, as the "Banks", is
incorporated by reference from Exhibit 10.6 to Barrett's Annual Report on Form 10-K
for the year ended December 31, 1995.
10.7B First Amendment to Revolving Credit Agreement dated October 31, 1996 between and
among Barrett, Agent and the Banks is incorporated by reference from Exhibit 10.1
to Amendment No. 2 to Barrett's Registration Statement on Form S-3 (File No. 333 -
19363) dated February 10, 1997.
10.7C Second Amendment to Revolving Credit Agreement dated February 10, 1997 between and
among Barrett, the Agent, and the Banks is incorporated by reference from Exhibit
10.2 to Amendment No. 2 to Barrett's Registration Statement on Form S-3 (File No.
333 -19363) dated February 10, 1997.
10.7D Amended and Restated Credit Agreement dated November 12, 1997 between and among
Barrett, the Agent, the Banks, and The Chase Manhattan Bank as the "Competitive Bid
Auction Agent".
10.7E First Amendment to Amended and Restated Credit Agreement dated December 19, 1997
between and among Barrett, the Agent, the Banks, and the Competitive Bid Auction
Agent.
10.8 Severance Protection Agreement dated February 6, 1998 between Barrett and William
J. Barrett.
10.9A Form of Severance Protection Agreement between Barrett and each of Paul R. Rady, A.
Ralph Reed, J. Frank Keller, and Peter A. Dea.
10.9B Schedule Identifying Material Differences Among Severance Protection Agreements
between Barrett and each of Paul R. Rady, A. Ralph Reed, J. Frank Keller, and Peter
A. Dea.
21 List of Subsidiaries.
23.1 Consent of Arthur Andersen LLP.
23.2 Consent of Ryder Scott Company.
23.3 Consent of Netherland, Sewell & Associates, Inc.
27 Financial Data Schedule.
37
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Barrett Resources Corporation
We have audited the accompanying consolidated balance sheets of Barrett
Resources Corporation (a Delaware corporation) and subsidiaries as of December
31, 1997 and 1996, and the related consolidated statements of income,
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 1997. 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, 1997 and 1996, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 1997, in conformity with generally accepted
accounting principles.
Arthur Andersen LLP
Denver, Colorado
March 9, 1998
F-1
BARRETT RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1997 AND 1996
(IN THOUSANDS)
1997 1996
-------- --------
ASSETS
Current assets:
Cash and cash equivalents.................................. $ 14,479 $ 14,539
Receivables, net........................................... 102,934 73,045
Inventory.................................................. 2,579 947
Other current assets....................................... 1,701 1,156
-------- --------
Total current assets..................................... 121,693 89,687
Net property and equipment (full cost method)................ 747,175 487,258
Other assets, net............................................ 3,833 --
-------- --------
$872,701 $576,945
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable........................................... $ 61,870 $ 41,617
Amounts payable to oil and gas property owners............. 27,174 18,496
Production taxes payable................................... 17,945 13,830
Accrued and other liabilities.............................. 17,917 4,374
-------- --------
Total current liabilities................................ 124,906 78,317
Long term debt............................................... 266,437 70,000
Deferred income taxes........................................ 68,977 50,908
Commitments and contingencies--Note 10
Stockholders' equity:
Preferred stock, $.001 par value: 1,000,000 shares
authorized, none outstanding.............................. -- --
Common stock, $.01 par value: 45,000,000 shares authorized,
31,415,528 outstanding (31,330,361 at December 31, 1996).. 314 313
Additional paid-in capital................................. 247,390 241,991
Retained earnings.......................................... 164,677 135,416
-------- --------
Total stockholders' equity............................... 412,381 377,720
-------- --------
$872,701 $576,945
======== ========
See accompanying notes.
F-2
BARRETT RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
(IN THOUSANDS, EXCEPT PER SHARE DATA)
1997 1996 1995
-------- -------- --------
Revenues:
Oil and gas production........................... $206,907 $151,737 $ 96,996
Trading revenues................................. 171,140 46,862 28,554
Interest income.................................. 1,573 760 714
Other income..................................... 2,980 3,213 1,752
-------- -------- --------
382,600 202,572 128,016
Operating expenses:
Lease operating expenses......................... 57,904 47,642 34,525
Depreciation, depletion and amortization......... 72,389 45,775 33,480
Cost of trading.................................. 165,218 44,036 27,611
General and administrative....................... 24,890 16,947 13,426
Interest expense................................. 13,243 3,684 4,631
Other expenses, net.............................. 1,770 -- 588
Merger and reorganization expense................ -- -- 14,161
-------- -------- --------
335,414 158,084 128,422
-------- -------- --------
Income (loss) before income taxes.................. 47,186 44,488 (406)
Provision for income taxes......................... 17,925 14,962 1,834
-------- -------- --------
Net income (loss).................................. $ 29,261 $ 29,526 $ (2,240)
======== ======== ========
Earnings (loss) per common share
Basic............................................ $ .93 $ 1.04 $ (.09)
======== ======== ========
Assuming dilution................................ $ .92 $ 1.02 $ (.09)
======== ======== ========
See accompanying notes.
F-3
BARRETT RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
(IN THOUSANDS)
ADDITIONAL TOTAL
COMMON PAID-IN TREASURY RETAINED STOCKHOLDERS'
STOCK CAPITAL STOCK EARNINGS EQUITY
------ ---------- -------- -------- -------------
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
Exercise of stock options. 1 1,389 (207) -- 1,183
Purchase of treasury
stock.................... -- -- (2) -- (2)
Retirement of treasury
stock.................... -- (209) 209 -- --
Fair value of put option
issued in connection with
property acquisitions.... -- 4,219 -- -- 4,219
Net income for the year
ended December 31, 1997.. -- -- -- 29,261 29,261
---- -------- ------ -------- --------
$314 $247,390 $ -- $164,677 $412,381
==== ======== ====== ======== ========
See accompanying notes.
F-4
BARRETT RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
(IN THOUSANDS)
1997 1996 1995
--------- --------- --------
Cash flows from operations:
Net income (loss)............................ $ 29,261 $ 29,526 $ (2,240)
Adjustments needed to reconcile to net cash
flow provided by operations:
Depreciation, depletion and amortization... 72,743 45,775 33,480
Unrealized (gain) loss on trading.......... -- (1,139) 1,139
Deferred income taxes...................... 18,069 13,655 1,798
Other........................................ -- -- (787)
--------- --------- --------
120,073 87,817 33,390
Change in current assets and liabilities:
Receivables.................................. (29,889) (41,956) 3,433
Other current assets......................... (545) (582) 525
Accounts payable............................. 20,253 27,248 (524)
Amounts due oil and gas owners............... 8,678 9,622 (2,725)
Production taxes payable..................... 4,115 5,783 --
Accrued and other liabilities................ 12,749 742 1,439
--------- --------- --------
Net cash flow provided by operations........... 135,434 88,674 35,538
--------- --------- --------
Cash flows from investing activities:
Proceeds from sales of oil and gas
properties.................................. 14,233 1,948 504
Acquisitions of property and equipment....... (341,167) (202,610) (82,758)
--------- --------- --------
Net cash flow used in investing activities..... (326,934) (200,662) (82,254)
--------- --------- --------
Cash flows from financing activities:
Proceeds from issuance of common stock, net.. 1,183 138,349 7,071
Purchase of treasury stock................... (2) (351) --
Proceeds from long-term borrowing............ 130,577 91,000 115,000
Payments on long-term debt................... (86,131) (110,000) (79,000)
Proceeds from Senior Notes, net of offering
costs....................................... 145,963 -- --
Dividends paid............................... -- -- (1,174)
Other........................................ (150) -- --
--------- --------- --------
Net cash flow provided by financing activities. 191,440 118,998 41,897
--------- --------- --------
Increase (decrease) in cash and cash
equivalents................................... (60) 7,010 (4,819)
Cash and cash equivalents at beginning of year. 14,539 7,529 12,348
--------- --------- --------
Cash and cash equivalents at end of year....... $ 14,479 $ 14,539 $ 7,529
========= ========= ========
See accompanying notes.
F-5
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Business
Barrett Resources Corporation (the "Company") is an independent natural gas
and oil exploration and production company with producing properties located
principally in the Mid-Continent states, the Gulf of Mexico and Rocky Mountain
region of the United States. The Company also operates gas gathering systems
and related facilities in certain areas in which the Company owns production.
In addition, the Company engages in natural gas trading activities, which
involve purchasing natural gas from third parties and selling natural gas to
other parties. In 1996, the Company commenced international activities with an
exploration project in the Republic of Peru.
Principles of consolidation
The consolidated financial statements include the accounts of the Company
and its subsidiaries, all of which are wholly owned. All significant
intercompany transactions have been eliminated in consolidation.
Reclassifications
Certain reclassifications have been made to 1996 and 1995 amounts to conform
to the 1997 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
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. Oil and gas properties accounted for
using the full cost method of accounting, a method utilized by the Company,
are excluded from the long-lived asset impairment test requirement of
Financial Accounting Standards No. 121, but will continue to be subject to the
ceiling test limitations. Accumulated depreciation is written off as assets
are retired. Depletion and amortization equaled approximately $.77, $.59 and
$.55 per Mcfe ($4.60, $3.54 and $3.28 per BOE) during the years ended December
31, 1997, 1996 and 1995, respectively.
The Company leases nonproducing acreage for its exploration and development
activities. The cost of these leases is included in unevaluated oil and gas
property costs recorded at the lower of cost or fair market value.
The Company operates many of the wells in which it owns an economic
interest. The operating agreements for these activities provide for a fee
structure to allow the Company to recover a portion of its direct and overhead
charges related to its operating activities. The fees collected under the
operating agreements are recorded as a reduction of general and administrative
expenses. Any amounts collected from a sale of oil and gas interests or earned
as a result of assembling oil and gas drilling activities are applied to
reduce the book value of oil and gas properties.
Other property and equipment
Other property and equipment is recorded at cost. Renewals and betterments
which substantially extend the useful life of the assets are capitalized.
Maintenance and repairs are expensed when incurred. Depreciation is provided
using accelerated and straight-line methods over the estimated useful lives,
ranging from five to ten years, of the assets.
Amounts payable to oil and gas property owners
Amounts payable to oil and gas property owners consist of cash calls from
working interest owners to pay for development costs of properties being
currently developed 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 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
F-7
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
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
The Company adopted Statement of Financial Accounting Standards No. 128,
"Earnings Per Share" (SFAS No. 128) effective December 15, 1997. This
pronouncement requires the presentation of the earnings per share ("EPS")
based on the weighted-average number of common shares outstanding (referred to
as basic earnings per share) and earnings per share giving effect to all
dilutive potential common shares that were outstanding during the reporting
period (referred to as diluted earnings per share or earnings per share-
assuming dilution). In addition, this pronouncement requires restatement of
earnings per share for all prior periods presented. As a result, the Company's
reported earnings per share for 1996 and 1995 were restated.
The following data show the amounts used in computing earnings per share and
the effect on income and the weighted average number of shares of dilutive
potential common stock.
FOR THE YEARS ENDED
DECEMBER 31,
-----------------------
1997 1996 1995
------- ------- -------
(IN THOUSANDS)
Income (loss) available to common stockholders....... $29,261 $29,526 $(2,240)
======= ======= =======
Weighted average number of common shares used in
basic EPS........................................... 31,367 28,388 24,858
Effect of dilutive securities (see Note 7):
Stock options...................................... 466 432 --
Written put option................................. 107 -- --
------- ------- -------
Weighted number of common shares and dilutive
potential common stock used in EPS assuming
dilution............................................ 31,940 28,820 24,858
======= ======= =======
Options on 986,546 shares of common stock were not included in computing
diluted EPS for 1995 because their effects were antidilutive. The written put
option was issued in 1997.
CHANGE IN FISCAL YEAR
On July 18, 1995, the Company changed its fiscal year-end from September 30
to December 31.
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.
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
F-8
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
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.
In connection with the merger, approximately $14.2 million of merger and
reorganization costs and expenses were incurred and have been charged to
expense in the Company's third and fourth quarters of fiscal 1995. These
nonrecurring costs and expenses consist of (1) investment banker and
professional fees of $7.4 million; (2) severance and employee benefit costs of
$5.6 million for approximately 38 employees, terminated through consolidation
of administrative and operational functions; (3) a non-cash credit of
approximately $.9 million associated with the termination of Plains'
postretirement benefit plans and other related benefit plans and (4) other
merger and reorganization related costs of $2.1 million.
3. RECEIVABLES
1997 1996
-------- -------
(IN THOUSANDS)
Oil and gas revenue and trading receivables.............. $ 78,962 $48,161
Joint interest billings.................................. 22,672 21,497
Other accounts receivable................................ 1,300 3,387
-------- -------
$102,934 $73,045
======== =======
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, 1997 and 1996, receivables are recorded net of allowance
for doubtful accounts of $694,000 and $229,000, respectively.
4. PROPERTY AND EQUIPMENT
1997 1996
---------- --------
(IN THOUSANDS)
-------------------
Oil and gas properties, full cost method:
Unevaluated costs, not being amortized.............. $ 119,737 $ 82,126
Evaluated costs..................................... 848,333 563,068
Gas gathering systems............................... 32,312 28,219
Furniture, vehicles and equipment..................... 13,421 8,487
---------- --------
1,013,803 681,900
Less accumulated depreciation, depletion, amortization
and impairment....................................... 266,628 194,642
---------- --------
$ 747,175 $487,258
========== ========
F-9
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
5. UNEVALUATED OIL AND GAS PROPERTY COSTS
Unevaluated oil and gas property costs associated with unevaluated
properties and major development projects consist of the following:
COSTS INCURRED DURING
-------------------------------
1997 1996 1995 TOTAL
------- ------- ------ --------
(IN THOUSANDS)
Acquisition costs
United States.............................. $50,711 $24,079 $2,773 $ 77,563
Peru....................................... 2,865 1,229 -- 4,094
Exploration costs
United States.............................. 23,237 7,094 17 30,348
Peru....................................... 7,732 -- -- 7,732
------- ------- ------ --------
$84,545 $32,402 $2,790 $119,737
======= ======= ====== ========
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
1997 1996
-------- -------
(IN THOUSANDS)
Line of Credit............................................ $100,000 $70,000
7.55% Senior Notes........................................ 150,000 --
Production Payments....................................... 17,231 --
-------- -------
Total..................................................... 267,231 70,000
Less: current portion..................................... 794 --
-------- -------
Long-term debt............................................ $266,437 $70,000
======== =======
Line of Credit
The Company has a reserve-based line of credit with a group of banks which
provides up to $250 million, maturing September 30, 2002. The amount actually
available to the Company under the line at any given time is limited to the
collateral value of proved reserves as determined by the lenders. Based on the
lenders' determination of collateral value, as of December 31, 1997 (which was
based on an unaudited June 30, 1997 reserve report), the Company's borrowing
limit was $150 million. The lenders are currently reviewing the December 31,
1997 reserve report to determine current collateral value at which time the
borrowing base could change. The Company is required to pay only interest
during the revolving period. At its option, the Company has elected to use the
London interbank eurodollar rate (LIBOR) plus a spread ranging from .185
percent to .625 percent (depending on the Company's Senior Debt Rating and the
ratio of the Company's outstanding indebtness to its earnings before interest,
taxes and depreciation, depletion and amortization) for a substantial portion
of the outstanding balance. As of December 31, 1997 the Company's outstanding
balance under the line of credit was $100 million of which $90 million was
accruing interest at an average LIBOR based rate of 6.31 percent and $10
million was accruing interest on a prime based rate of 8.5 percent. The line
of credit agreement provides for facility fees ranging between 9/100 of one
percent and 37.5/100 of one percent of the lesser of the available commitment
and the borrowing base. The Credit Agreement restricts the payment of
dividends, borrowings, sale of assets, loans to others, and investment and
merger activity over certain limits
F-10
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
without the prior consent of the banks and requires the Company to maintain
certain net worth and debt to equity levels.
7.55% Senior Notes
In February 1997, the Company completed a public offering of $150 million
(principal amount) of its 7.55% Senior Notes due 2007 ("Notes"). A portion of
the net proceeds from the offering was used to repay the Company's existing
line of credit. The Notes are senior unsecured obligations of the Company
ranking equally in right of payment to all existing and future senior
indebtedness of the Company. At the option of the Company, the Notes may be
redeemed at any time, in whole or in part, by paying an amount specified for a
make-whole premium. The indenture of the Notes limits the Company's ability to
incur indebtedness secured by certain liens, engage in certain sale/leaseback
transactions, and engage in certain merger, consolidation or reorganization
transactions. Interest is paid semi-annually on February 1 and August 1 of
each year.
Production Payments
In January 1997, the Company assumed a production payment in an acquisition
of properties with a term of three years. Payments of the production payment
liability is funded from production from the properties.
In November 1997, the Company sold its interest in certain Colorado
properties to an investment group which includes a Company subsidiary. For
accounting purposes, the Company has treated the sale as a non-recourse
monetary production payment reflected in long-term liabilities on the balance
sheet. Net of transaction costs, the proceeds from the sale were approximately
$15.5 million in cash. Payments of the production payment liability are funded
from the operating cash flow of the properties, less funds required for
working capital purposes. The liability is expected to be fully repaid by
2003.
The aggregate amount of long-term debt maturities (including estimated
operating cash flows from properties designated for production payments) for
each of the five years after 1997 are: $1 million, $3.7 million, $3.2 million,
$2.8 million and $102.6 million.
Fair Value of Financial Instruments
The carrying amounts of cash, accounts receivable, accounts payable, and
accrued liabilities approximate fair value due to the short-term maturities of
these assets and liabilities. Based on the variable borrowing rates and re-
pricing terms currently available to the Company for the line of credit, the
carrying amounts of the Company's line of credit and the production payment
liabilities approximate fair value. The fair value of the Notes was $166.1
million at December 31, 1997.
7. COMMON STOCK AND OPTIONS
Common Stock
In conjunction with a property acquisition transaction executed in April
1997, the Company issued a written put option that obligates the Company to
issue 150,000 shares of its common stock to the holder of the option should
the holder elect to exercise this option. The Company will receive the
holder's minority interest in a subsidiary of the Company. This option can be
exercised by the holder at any time prior to January 31, 2012. In addition,
the Company has a written call option, exercisable between January 1, 2002 and
January 31, 2012, that gives it the right to purchase the minority interest by
issuing the aforementioned common shares. The put option was recorded to
additional paid-in capital at a fair market value totaling $4.2 million, the
value of the Company's common stock to be issued pursuant to the option. The
fair market value was based on the market price of the Company's common stock
at the date the option was issued.
F-11
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
In June 1997, the Company's shareholders voted to increase the authorized
number of shares of the Company's common stock from 35 million to 45 million.
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.
Barrett has a stock purchase rights plan designed to insure that
stockholders receive full value for their shares in the event of certain
takeover attempts.
Stock Options
The Company has three employee stock option plans, a 1990 Plan, a 1994 Plan
and a 1997 Plan, under which the Company's common stock may be granted to
officers and employees of the Company and subsidiaries. The 1990 Plan provides
for the granting of options to purchase 775,000 shares. The 1994 Plan, as
amended, provides for the granting of options to purchase 1,000,000 shares of
the Company's common stock. The 1997 Plan, provides for the granting of
options to purchase 1,500,000 shares of the Company's common stock. In
addition, the Company has a non-discretionary stock option plan, as amended,
under which options for an aggregate of 300,000 shares of the Company's common
stock may be granted to non-employee directors. In 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.
The exercise price of each option is equal to the market price of the
Company's stock on the date of grant. Options under the Company's plans
generally become exercisable in equal installments on each of the first four
anniversaries of the date of grant. All options granted under the Plains
option plans are exercisable. 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:
FOR THE YEAR ENDED
DECEMBER 31,
-----------------------
1997 1996 1995
------- ------- -------
(IN THOUSANDS)
Net income (loss)
As reported..................................... $29,261 $29,526 $(2,240)
Pro forma....................................... $22,301 $27,277 $(2,485)
Net income (loss) per share
As reported
Basic......................................... $ .93 $ 1.04 $ (.09)
Diluted....................................... $ .92 $ 1.02 $ (.09)
Pro forma
Basic......................................... $ .71 $ .96 $ (.10)
Diluted....................................... $ .70 $ .95 $ (.10)
F-12
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
Changes in outstanding stock options under these plans are summarized as
follows:
1997 1996 1995
-------------------- -------------------- --------------------
WEIGHTED- WEIGHTED- WEIGHTED-
NUMBER OF AVERAGE NUMBER OF AVERAGE NUMBER OF AVERAGE
OPTION EXERCISE OPTION EXERCISE OPTION EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
--------- --------- --------- --------- --------- ---------
Outstanding at beginning
of year................ 1,481,559 $22.50 986,546 $16.89 1,359,791 $16.06
Granted................. 787,250 33.18 727,600 28.59 110,000 22.69
Exercised............... (83,851) 16.48 (230,897) 17.72 (425,969) 14.70
Forfeited............... (96,750) 32.74 (1,690) 23.96 (57,276) 24.48
--------- --------- ---------
Outstanding at end of
year................... 2,088,208 1,481,559 22.50 986,546 16.89
========= ========= =========
Options exercisable at
year end............... 718,633 392,959 417,121
Weighted-average fair
value of options
granted during the
year................... $ 20.69 $ 17.74 $ 14.23
The calculated value of stock options granted under these plans, following
calculation methods prescribed by SFAS 123, uses the Black-Scholes stock
option pricing model with the following weighted-average assumptions used:
1997 1996 1995
----- ----- -----
Expected option life--years........................... 5.44 4.90 4.90
Risk-free interest rate............................... 6.78% 6.44% 6.68%
Dividend yield........................................ 0 0 0
Volatility............................................ 57.47% 69.54% 69.54%
The following table summarizes information about stock options outstanding
at December 31, 1997:
STOCK OPTIONS
STOCK OPTIONS OUTSTANDING EXERCISABLE
-------------------------------------- ---------------------
WEIGHTED- WEIGHTED- WEIGHTED-
NUMBER AVERAGE AVERAGE NUMBER AVERAGE
RANGE OF OUTSTANDING REMAINING EXERCISE EXERCISABLE EXERCISE
EXERCISE PRICES AT 12/31/97 CONTRACTUAL LIFE PRICE AT 12/31/97 PRICE
- --------------- ----------- ---------------- --------- ----------- ---------
$ 5-16.......... 297,195 1.3 $12.71 208,045 $12.47
16-21.......... 288,789 2.8 18.72 229,064 18.72
21-30.......... 556,224 4.8 24.68 206,524 24.34
30-43.......... 946,000 6.0 33.82 75,000 35.61
--------- -------
2,088,208 4.6 26.29 718,633 20.29
========= =======
8. RETIREMENT BENEFITS
Current Plan Benefits
The Company has a voluntary 401(k) employee savings plan. Under this plan,
as amended, the Company matches 100% of each participating employee's
contribution, up to a maximum of 6% of base salary, with one-half of the match
paid in cash and one-half of the match paid in the Company's common stock.
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 $434,000, $341,000 and $239,000 in 1997,
1996 and 1995, respectively.
F-13
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
Plains' Pre-merger Benefit Plans
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 for the 1995 plan year.
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. The final
distribution was made to the participants by the trustee of the assets in
January 1998.
Concurrently with the effective date of the merger, Plains' postretirement
healthcare benefit and salary continuation plans were terminated. Participants
in the salary continuation plan received (1) a lump sum benefit equal to the
present value of the remaining monthly payments if receiving Death Benefits
under the plan at the date of the termination, or (2) insurance polices, the
cost of which was limited to the cash values of the life insurance policies
owned by Plains. Benefits associated with the postretirement healthcare
benefit plan were terminated and, accordingly, accrued postretirement benefit
costs were relieved.
9. HEDGING ACTIVITIES
Hedging for Production
The Company uses swap agreements to reduce the effect of natural gas price
volatility on a portion of its natural gas production. The objective of its
hedging activities is to achieve more predictable revenues and cash flows. In
a typical swap agreement, on a monthly basis for the term of the swap
agreement, the Company receives the difference between a fixed price per unit
of production and a price based on an agreed-upon third party index. The
Company reviews and monitors the credit standing of the counter party to each
of its swap agreements and believes that the counter party will fully comply
with its contractual obligations.
As of December 31, 1997, the Company had in effect outstanding natural gas
swaps associated with its Rocky Mountain natural gas production of 25.1 Bcf
for the year 1998 and 104 Bcf for the period of January 1999 through February
2003. Fixed prices associated with these swaps ranges from $1.71 to $2.24 per
MMBtu for 1998 and from $1.71 to $1.79 per MMBtu for January 1999 through
February 2003.
At year end 1996, the Company had outstanding natural gas swaps associated
with Rocky Mountain production of approximately 8.8 Bcf for January through
October 1997 with fixed prices ranging between $1.45 and $2.01 per MMBtu.
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, 1997, 1996 and 1995, the Company's gains (losses) under its
production swap agreements were $(4.3) million, $(5.0) million and $0.4
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
F-14
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
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.
Hedging for Trading Activities
At year end 1997, the Company had in effect outstanding natural gas swaps
associated with its natural gas trading activities of 25.9 Bcf for January
through March 1998 with fixed prices of $1.58 to $3.12 per MMBtu and 14.4 Bcf
for April 1998 through October 1999 with fixed prices of $1.31 to $1.83 per
MMBtu. These swaps are in place to cover fixed price purchases and sales.
10. COMMITMENTS AND CONTINGENCIES
Lease Commitments
The minimum future payments under the terms of operating leases, principally
for office space, are as follows:
YEAR ENDED
DECEMBER 31,
------------ (IN THOUSANDS)
1998...................................................... $1,390
1999...................................................... 1,295
2000...................................................... 1,167
2001...................................................... 564
2002...................................................... 113
------
$4,529
======
Total minimum future rental payments have not been reduced by $238,000 of
sublease rentals to be received in the future. Rent expense was $1,055,000,
$990,000 and $956,000 for the years ended December 31, 1997, 1996 and 1995,
respectively.
Litigation
The Internal Revenue Service (IRS) has examined the federal tax returns of
Plains, a subsidiary of Barrett Resources Corporation, for pre-merger calendar
years 1991, 1992 and 1993. The IRS issued a "Notice of Deficiency" of $5.3
million together with penalties of $1.1 million, and an undetermined amount of
interest. The IRS Notice of Deficiency resulted primarily from the IRS's
disallowance of certain net operating loss deductions claimed during the
periods under examination. These net operating losses originally had been
incurred by companies that were acquired by Tri-Power Petroleum, Inc. which
was then acquired by Plains in 1986. For years following 1993, the Company has
additional net operating loss carryforwards of approximately $30 million
related to the same acquisition.
Management disagrees with the IRS position. In management's opinion, the
federal tax returns of Plains reflect the proper federal income tax liability
and the existing net operating loss carryforwards are appropriate as supported
by relevant authority. The Company is vigorously contesting these proposed
adjustments and believes it will prevail in its positions. In this connection,
the Company filed a petition on November 29, 1996 with the United States Court
requesting a redetermination of the IRS's Notice of Deficiency. A May 4, 1998
trial date has been set.
An August 1996 United States Court of Appeals decision reversed a Federal
Energy Regulatory Commission's decision with respect to producer reimbursement
of Kansas ad valorem tax as an add-on to the
F-15
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
maximum lawful price under the Natural Gas Policy Act of 1978. As a result of
the Court Appeals decision, for the year 1997, the Company recorded a $2.7
million liability refund which was partially offset by a $700,000 receivable
recoverable from other working, royalty and net profits interest owners. The
Company has received an additional refund statement of $2.85 million ($2.02
million net to the Company) for Kansas ad valorem tax reimbursements relating
to the period of October 1984 through September 1985. The Company believes
that it is not responsible for this latter refund amount and is disputing the
claim.
At December 31, 1997, 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
At year end 1997, there were no known environmental or other regulatory
matters related to the Company's operations which are reasonably expected to
result in a material liability to the Company. Compliance with environmental
laws and regulations has not had, and in management's opinion is not expected
to have, a material adverse effect on the Company's capital expenditures,
earnings or competitive position.
11. INCOME TAXES
The provision for income taxes consists of the following:
1997 1996 1995
------- ------- ------
(IN THOUSANDS)
Current:
Federal........................................... $ 87 $ 513 $ 269
State............................................. (231) 794 (233)
------- ------- ------
(144) 1,307 36
Deferred:
Federal........................................... 17,345 12,833 2,039
State............................................. 724 822 (241)
------- ------- ------
18,069 13,655 1,798
------- ------- ------
$17,925 $14,962 $1,834
======= ======= ======
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:
1997 1996 1995
------- ------- ------
(IN THOUSANDS)
Tax by applying the statutory federal income tax
rate to pretax accounting income (loss).......... $16,515 $15,571 $ (138)
Increase (decrease) in tax from:
Change in valuation allowance................... -- -- 396
State income taxes.............................. 493 1,616 (474)
Non-deductible merger costs..................... -- -- 2,429
Other, net...................................... 917 (2,225) (379)
------- ------- ------
$17,925 $14,962 $1,834
======= ======= ======
F-16
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
Long-term deferred tax assets (liabilities) are comprised of the following
at December 31, 1997 and 1996:
1997 1996
--------- --------
(IN THOUSANDS)
Deferred tax assets:
Allowance for losses................................. $ -- $ 88
Partnership activities............................... 8,549 --
Loss carryforwards and other......................... 44,400 27,957
--------- --------
Gross deferred tax assets.......................... 52,949 28,045
Deferred tax liabilities:
Deferred revenue--partnership activities............. -- (1,182)
Depreciation, depletion and amortization............. (120,504) (76,458)
Capitalized interest on other assets................. (229) (120)
--------- --------
Gross deferred tax liabilities..................... (120,733) (77,760)
--------- --------
Net deferred tax liability............................. (67,784) (49,715)
Valuation allowance.................................... (1,193) (1,193)
--------- --------
$ (68,977) $(50,908)
========= ========
Valuation allowances of $1,193,000 were provided at both December 31, 1997
and 1996 based on carryforward amounts which may not be utilized before
expiration.
The Company has net operating loss and investment tax credit carryforwards
available totaling $112.4 million and $.5 million, respectively, which expire
in the years 1998 through 2010.
The 1995 merger with Plains also resulted in a change in the Company's and
Plains' ownership as defined by Section 382 of the Internal Revenue Code. The
change effectively limits the annual utilization of the Company's and Plains'
remaining net operating losses arising prior to the merger to $15,831,000 per
year for the Company. Portions of the above limitations which are not used
each year may be carried forward to future years.
12. SUPPLEMENTAL CASH FLOW SCHEDULES AND INFORMATION
CASH PAID DURING YEARS
1997 1996 1995
------ ------ ------
(IN THOUSANDS)
Income tax............................................. $ 824 $ 416 $ 65
Interest............................................... 8,079 3,809 5,129
Supplemental information of noncash investing and
financing activities:
Issuance of common stock exchanged for treasury shares
in cashless option transactions....................... $ 207 $ 527 $ 545
During 1997, in separate transactions, the Company assumed a production
payment with a value of $2.8 million and issued a written put option on
150,000 shares of the Company's common stock with a market value of $4.2
million (at the date of issue) in acquisitions of interests in oil and gas
properties located in the Uinta and Piceance Basins, respectively.
F-17
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
During 1996, the Company issued 50,000 shares of common stock with a market
value of $1.9 million and exchanged certain oil and gas properties plus $13.4
million cash for oil and gas properties located in the Uinta Basin of Utah. In
addition, with respect to acquisitions of various oil and gas and related
properties located in the Piceance Basin of Colorado in 1996, the Company
issued 585,661 shares of common stock valued at $16.5 million and recognized
additional deferred taxes of $13.7 million, for the difference between the tax
basis and book basis of the properties acquired.
13. RELATED PARTIES
During 1997, there were no transactions between the Company and its
directors, executive officers or known holders of greater than five percent of
the Company's Common Stock in which the amount involved exceeded $60,000 and
in which any of the foregoing persons had or will have a material interest.
In April 1996, the Company acquired for $2.7 million from Zenith Drilling
Corporation ("Zenith") all of Zenith's oil and gas interests located in the
Piceance Basin of Colorado. In addition, the Company acquired all the stock of
Grand Valley Corporation ("GVC") in exchange for 350,000 shares of the
Company's common stock. The sole asset of GVC was an approximate 10% interest
in the Grand Valley Gathering System. The Company previously owned interests
in and is the operator of both the gathering system and the gas and oil assets
in which it acquired interests as a result of these transactions.
A member of the Company's Board of Directors owns 89% of Zenith and, at the
time of the GVC transaction, was a director of GVC and owned 10% of GVC. Due
to these relationships, the terms of these transactions with Zenith and GVC
were negotiated on behalf of the Company by a Special Committee of the Board
of Directors of the Company, consisting of four independent outside directors.
The Company also obtained an opinion from an investment banking firm that the
terms of these transactions were fair to the Company.
During the years ended December 31, 1996 and 1995, Zenith was billed by the
Company as operator, approximately, $77,000 and $1,062,000, 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 and $942,000 as its
share of revenues for 1996 and 1995, respectively.
F-18
BARRETT RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
14. QUARTERLY INFORMATION (UNAUDITED)
THREE MONTHS ENDED
---------------------------------
3/31/97 6/30/97 9/30/97 12/31/97
------- ------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE
DATA)
1997
Net revenues.................................. $75,768 $70,496 $ 88,660 $145,049
Gross margin.................................. 23,404 15,621 16,774 28,663
Income from operations........................ 15,988 7,077 7,464 16,657
Net income.................................... 9,913 4,387 4,629 10,332
Net income per share:
Basic....................................... .32 .14 .15 .33
Assuming dilution........................... .31 .14 .14 .32
THREE MONTHS ENDED
---------------------------------
3/31/96 6/30/96 9/30/96 12/31/96
------- ------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE
DATA)
1996
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:
Basic....................................... .14 .26 .22 .40
Assuming dilution........................... .14 .25 .22 .39
F-19
SUPPLEMENTAL OIL AND GAS INFORMATION
The following information, pertaining to the Company's oil and gas producing
activities for the years ended December 31, 1997, 1996 and 1995, is presented
in accordance with Statement of Financial Accounting Standards No. 69,
"Disclosure About Oil and Gas Producing Activities" (FSAS No. 69).
MAJOR PURCHASER
During 1997, one natural gas purchaser accounted for 8 percent of the
Company's total revenue (16 percent of oil and gas revenues.) Sales of gas to
this same purchaser represented 11 percent and 18 percent of total revenues in
1996 and 1995, 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:
1997 1996 1995
-------- -------- -------
(IN THOUSANDS)
Acquisition of evaluated properties............... $ 45,148 $ 68,157 $ 7,429
Acquisition of unevaluated properties:
United States.................................... 63,643 45,051 8,383
Peru............................................. 10,597 1,229 --
Exploration costs................................. 118,779 32,086 23,272
Development costs................................. 93,701 69,651 33,029
Other, principally proceeds from mineral convey-
ances............................................ (14,253) (1,948) (426)
-------- -------- -------
Total additions to oil and gas properties......... $317,615 $214,226 $71,687
======== ======== =======
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 of $3.9 million in 1997 for various
supporting production facilities consisting principally of natural gas
gathering systems and processing plants. Production facility expenditures for
1996 and 1995 were $15.1 million and $1.3 million.
F-20
BARRETT RESOURCES CORPORATION
SUPPLEMENTAL OIL AND GAS INFORMATION--(CONTINUED)
OIL AND GAS RESERVES (UNAUDITED)
The following reserve related information for 1997 is based on estimates
prepared by the Company. All of the Company's reserves are located in the
United States. The 1997 reserve information for the Company was reviewed by
Ryder Scott, an independent reservoir engineer. The Company's 1996 and 1995
reserves, exclusive of Plains, were prepared by the Company and reviewed by
Ryder Scott as of December 31, 1996 and December 31, 1995. The 1995 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.
1997 1996 1995
---------------- --------------- ---------------
OIL GAS OIL GAS OIL GAS
(MBBL) (MMCF) (MBBL) (MMCF) (MBBL) (MMCF)
------- ------- ------ ------- ------ -------
(IN THOUSANDS)
Proved developed and
undeveloped reserves:
Beginning of year......... 23,231 674,893 12,967 513,531 11,444 458,820
Revisions of previous
estimates................ (11,651) (54,945) (210) (778) 1,209 (3,805)
Purchase of minerals in
place.................... 1,910 52,303 6,628 95,914 831 3,983
Extensions and
discoveries.............. 8,287 258,520 6,029 127,547 1,232 102,329
Production................ (2,235) (76,625) (1,913) (60,883) (1,702) (47,692)
Sale of minerals in place. (891) (2,902) (270) (438) (47) (104)
------- ------- ------ ------- ------ -------
End of year............... 18,651 851,244 23,231 674,893 12,967 513,531
======= ======= ====== ======= ====== =======
Proved developed reserves:
Beginning of year......... 15,773 511,645 11,669 419,672 7,848 393,051
======= ======= ====== ======= ====== =======
End of year............... 10,751 553,787 15,773 511,645 11,669 419,672
======= ======= ====== ======= ====== =======
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
The standardized measure of discounted future net cash flows is based on
estimated quantities of proved reserves and the future periods in which they
are expected to be produced and on year-end economic conditions. Estimated
future gross revenues are priced on the basis of year-end prices, except in
the case of contracts where the applicable contract price, including fixed and
determinable escalations, were used for the duration of the contract.
Estimated future gross revenues are reduced by estimated future development
and production costs, as well as certain abandonment costs and by estimated
future income tax expense. Future income tax expenses have been computed
considering the tax basis of the oil and gas properties plus available
carryforwards and credits.
F-21
BARRETT RESOURCES CORPORATION
SUPPLEMENTAL OIL AND GAS INFORMATION--(CONTINUED)
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.
1997 1996 1995
---------- ---------- ----------
(IN THOUSANDS)
Future cash inflows..................... $2,158,461 $2,893,217 $1,132,711
Future production costs................. (608,123) (773,233) (355,756)
Future development costs................ (250,467) (152,141) (46,888)
Future income tax expenses.............. (306,946) (628,901) (207,922)
---------- ---------- ----------
Future net cash flows................... 992,925 1,338,942 522,145
10% annual discount for estimated timing
of cash flows.......................... (428,794) (574,139) (212,271)
---------- ---------- ----------
Standardized measure of discounted
future net cash flows.................. $ 564,131 $ 764,803 $ 309,874
========== ========== ==========
The following are the principal sources of changes in the standardized
measure of discounted future net cash flows:
1997 1996 1995
--------- --------- --------
(IN THOUSANDS)
Net change in sales price and production
costs...................................... $(457,246) $ 415,937 $ 24,558
Changes in estimated future development
costs...................................... 43,391 16,288 10,301
Sales and transfers of oil and gas produced,
net of production costs.................... (152,536) (110,341) (62,294)
Net change due to extensions and
discoveries................................ 195,992 230,797 85,524
Net change due to purchases and sales of
minerals in place.......................... 32,153 167,235 7,424
Net change due to revisions in quantities... (122,656) (41,486) (1,393)
Net change in income taxes.................. 183,901 (249,836) (33,172)
Accretion of discount....................... 69,881 28,053 23,112
Other, principally revisions in estimates of
timing of production....................... 6,448 (1,718) 13,193
--------- --------- --------
Net changes................................. (200,672) 454,929 67,253
Balance, beginning of year.................. 764,803 309,874 242,621
--------- --------- --------
Balance, end of year........................ $ 564,131 $ 764,803 $309,874
========= ========= ========
The December 31, 1997 weighted average prices utilized for purposes of
estimating the Company's proved reserves and future net revenues were $15.52
per barrel of oil and $2.19 per Mcf of natural gas.
F-22
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 6, 1998
By: /s/ PAUL M. RADY
PAUL M. RADY
PRESIDENT, CHIEF EXECUTIVE
OFFICER
Date: March 6, 1998
By: /s/ JOHN F. KELLER
JOHN F. KELLER
CHIEF FINANCIAL OFFICER,
AND PRINCIPAL FINANCIAL AND
ACCOUNTING OFFICER
SIGNATURE TITLE DATE
--------- ----- ----
/S/ WILLIAM J. BARRETT Director March 6, 1998
- ------------------------------------
WILLIAM J. BARRETT
/S/ C. ROBERT BUFORD Director March 6, 1998
- ------------------------------------
C. ROBERT BUFORD
/S/ DERRILL CODY Director March 6, 1998
- ------------------------------------
DERRILL CODY
/S/ JAMES M. FITZGIBBONS Director March 6, 1998
- ------------------------------------
JAMES M. FITZGIBBONS
/S/ WILLIAM W. GRANT, III Director March 6, 1998
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WILLIAM W. GRANT, III
/S/ JOHN F. KELLER Director March 6, 1998
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JOHN F. KELLER
/S/ PAUL M. RADY Director March 6, 1998
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PAUL M. RADY
/S/ A. RALPH REED Director March 6, 1998
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A. RALPH REED
/S/ JAMES T. RODGERS Director March 6, 1998
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JAMES T. RODGERS
SIGNATURE TITLE DATE
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/S/ PHILIPPE SCHREIBER Director March 6, 1998
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PHILIPPE S.E. SCHREIBER
/S/ HARRY S. WELCH Director March 6, 1998
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HARRY S. WELCH