-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Nlks/qyRK+ntwUJEj1xE655FBbFroaGtEhVKrjMRk9VE2pRoEXR7B8IxhGqMpOZ2 QutSmjU1zPcL3tjwcHDwsw== 0000927356-97-000296.txt : 19970329 0000927356-97-000296.hdr.sgml : 19970329 ACCESSION NUMBER: 0000927356-97-000296 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19961231 FILED AS OF DATE: 19970328 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: BARRETT RESOURCES CORP CENTRAL INDEX KEY: 0000351993 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 840832476 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-13446 FILM NUMBER: 97566438 BUSINESS ADDRESS: STREET 1: 1515 ARAPAHOE ST STREET 2: TOWER 3 STE 1000 CITY: DENVER STATE: CO ZIP: 80202 BUSINESS PHONE: 3032973900 MAIL ADDRESS: STREET 1: 1515 ARAPAHOE ST STREET 2: TOWER 3 STE 1000 CITY: DENVER STATE: CO ZIP: 80202 FORMER COMPANY: FORMER CONFORMED NAME: AIMEXCO INC DATE OF NAME CHANGE: 19840215 10-K 1 FORM 10-K ================================================================================ SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K [X]ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR YEAR ENDED DECEMBER 31, 1996 OR [_]TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM _____ TO _____ COMMISSION FILE NO. 1-13446 BARRETT RESOURCES CORPORATION (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER) DELAWARE 84-0832476 (STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER IDENTIFICATION NO.) INCORPORATION OR ORGANIZATION) 1515 ARAPAHOE STREET, 80202 TOWER 3, SUITE 1000 (ZIP CODE) DENVER, COLORADO (ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (303) 572-3900 (REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE) SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: (None) SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: COMMON STOCK (PAR VALUE $.01 PER SHARE) TITLE OF CLASS Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [_] Indicate by check mark if there are no delinquent filers to disclose herein pursuant to Item 405 of Regulation S-K, and there will not be any delinquent filers to disclose, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [_] As of March 20, 1997, the Registrant had 31,340,876 common shares outstanding, and the aggregate market value of the common shares held by non- affiliates was approximately $996,572,776. This calculation is based upon the closing sale price of $34.00 per share for the stock on March 20, 1997. ================================================================================ 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 Market for the Registrants common stock and Related Security 5. Holders Matters.............................................. 19 6. Selected Financial Data...................................... 19 Managements Discussion and Analysis of Financial Condition 7. and Results of Operations.................................... 19 8. Financial Statements and Supplemental Data................... 24 Changes in and Disagreements with Accountants on Accounting 9. and Financial Disclosures.................................... 24 PART III 10. Directors and Executive Officers of the Company.............. 25 11. Executive Compensation....................................... 29 Security Ownership of Certain Beneficial Owners and 12. Management................................................... 33 13. Certain Relationships and Related Transactions............... 34 PART IV 14. Exhibits, Financial Schedules, and Reports on Form 8-K....... 35
PART I ITEMS 1. AND 2. BUSINESS AND PROPERTIES Barrett Resources Corporation (the "Company" or "Barrett", which reference shall include the Company's wholly owned subsidiaries) was incorporated in December 1980 as an oil and gas company under the name AIMEXCO Inc. and became publicly owned with a $5.8 million common stock offering in May 1981. In December 1983, AIMEXCO acquired all the common stock of Barrett Energy Company, which owned a number of oil and gas properties, in exchange for 71.5 percent of the common stock of AIMEXCO that was outstanding after the transaction. In January 1984, the Company changed its name to Barrett Resources Corporation. In November 1985, the Company acquired Excel Energy Corporation, a Utah corporation that owned oil and gas interests, in exchange for approximately 1,425,000 shares of the Companys common stock. In June 1987, the Company acquired all the outstanding stock of Finance For Energy, Ltd., whose assets consisted primarily of cash and mortgages, in exchange for 1,174,100 shares of the Companys common stock. In September 1987, the Company effected a one-for-twenty reverse stock split of the Company's common shares and changed the par value of its common stock to $.01 per share. All prior references in this Item to numbers of shares of the Company's common stock have been adjusted for the effect of this one-for- twenty reverse stock split. In May 1990, the Company completed the public offering of 3,565,000 shares of its common stock for $21.3 million, net of the underwriting discount. In March 1993, the Company completed the public offering of an additional two million shares of its common stock for $19.2 million, net of the underwriting discount. Effective July 1, 1993, the Company sold substantially all its interests in oil and gas properties, a gas processing plant and the related gas gathering system located in the Wattenberg Field of Colorado. The adjusted sales price, net of selling expenses, was approximately $14.4 million. In July 1995, the Company completed the merger of the Company and Plains Petroleum Company ("Plains") pursuant to which Plains became a wholly owned subsidiary of the Company. The Company issued 12.8 million shares of common stock in exchange for all the outstanding shares of Plains. In June 1996, the Company completed the public offering of 5.4 million shares of its common stock for $135 million, net of the underwriting discount. In February 1997, the Company completed the public offering of $150 million of its 7.55% Senior Notes due 2007. OIL AND GAS EXPLORATION AND DEVELOPMENT Barrett is an independent natural gas and crude oil exploration and production company with core areas of activity in the Rocky Mountain Region of Colorado, Wyoming and Utah; the Mid-Continent Region of Kansas, Oklahoma, New Mexico and Texas; and the Gulf of Mexico Region of offshore Texas and Louisiana. At December 31, 1996, the Company's estimated proved reserves were 814.3 Bcfe (83% natural gas and 17% crude oil) with an implied reserve life of 11.3 years based on 1996 total production of 72 Bcfe. The Company concentrates its activities in core areas in which it has accumulated detailed geologic knowledge and developed significant management expertise. The Company continues to build on its interests in the Piceance Basin in northwestern Colorado, the Uinta Basin of northeastern Utah, the Anadarko and Arkoma Basins in Oklahoma, the Wind River Basin in Wyoming and the Gulf of Mexico. The Company also has significant interests in the Hugoton Embayment in Kansas and Oklahoma, the Permian Basin in Texas and New Mexico, and the Powder River Basin in Wyoming. At December 31, 1996, these principal areas of focus represented approximately 94% of the Company's estimated proved reserves. 1 The Company continues to experience significant growth in its proved reserves, production volumes, revenues and cash flow, particularly in the Wind River, Piceance, Anadarko, Arkoma and Uinta Basins. The Company currently is pursuing development projects in the Wind River, Piceance, Anadarko, Arkoma and Uinta Basins, and exploration projects in the Wind River and Anadarko Basins, the Gulf of Mexico and the Republic of Peru. The Company's average net daily production increased to 198 MMcfe for the year ended December 31, 1996 from 159 MMcfe for the year ended December 31, 1995. As of December 31, 1996, the Company owned interests in 2,106 producing wells and operated 1,310 of these wells. These operated wells contributed approximately 82% of Barrett's natural gas and oil production for the year ended December 31, 1996. The Company also owns interests in and operates a natural gas gathering system, a 27-mile pipeline and a natural gas processing plant in the Piceance Basin. Barrett markets all of its own natural gas and oil production from wells that it operates. In addition, the Company engages in natural gas trading activities, which involve purchasing natural gas from third parties and selling natural gas to other parties at prices and volumes that management anticipates will result in profits to the Company. Through these natural gas trading activities, the Company obtains knowledge and information that enables it to more effectively market its own production. See "--Natural Gas and Oil Marketing and Trading." EMPLOYEES AND OFFICES The Company currently has 181 full time employees, including 12 officers (five of whom are geologists and two of whom are petroleum engineers), 14 geologists, six geophysicists, 12 engineers, one environmental manager, 11 landmen, four district managers, one operations superintendent, and administrative, clerical, accounting and field operations personnel, none of whom is represented by organized labor unions. The Company's executive offices are located at 1515 Arapahoe Street, Tower 3, Suite 1000, Denver, Colorado 80202, and its telephone number is (303) 572- 3900. In addition, the Company maintains regional offices in Tulsa, Oklahoma and Houston, Texas. 2 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 1995 1996 1996 -------------- ---------------- ---------------- -------------- (BCFE) (BCFE) (MMCFE) Rocky Mountain Region Wind River.............. 88.1 95.8 42.2 Piceance................ 119.1 201.7 28.5 Powder River............ 30.0 32.0 15.6 Green River............. 12.5 14.8 5.4 Uinta................... 4.2 92.2 3.9 Mid-Continent Region Arkoma.................. 27.4 26.7 12.9 Anadarko................ 33.7 46.2 21.6 Hugoton Embayment....... 200.7 211.9 42.7 Permian................. 39.1 31.8 12.9 Gulf of Mexico Region..... 8.7 23.8 5.9 Other Natural Gas and Oil Activities(1)............ 27.8 37.4 6.7 ----- ----- ----- Total................. 591.3 814.3 198.3 ===== ===== =====
- -------- (1) Reserves primarily located in northeastern Colorado, the Paradox Basin (Utah and Colorado) and Nevada. ROCKY MOUNTAIN REGION WIND RIVER BASIN. In 1994, following its major natural gas discovery in the Cave Gulch Field, the Company began a focused exploration program in the Wind River Basin of Wyoming, particularly along the Owl Creek Thrust fault. Cave Gulch Field. In August 1994, the Company drilled the Barrett #1 Cave Gulch Federal Unit well and discovered a significant natural gas field in the Fort Union and Lance Sandstones below the Owl Creek Thrust. The Company currently owns a 94% working interest in the Cave Gulch Federal Unit. Since August 1994, the Company has acquired additional interests in the area and currently owns working interests ranging from 5% to 100% in 16,011 gross leasehold acres, constituting 9,590 net leasehold acres, in the Cave Gulch area. Combined daily production for the Cave Gulch Field net to the Company's interest at December 31, 1996 was 50 MMcf of natural gas and 171 barrels of oil. In February 1997, the Company reached a total depth of 19,106 feet on the Cave Gulch #16 deep test well, which was drilled to test the deeper Frontier, Muddy, Lakota, Morrison and Sundance Formations. The well encountered these formations at least 1,100 feet structurally updip (high) to the productive zones in four offset gas wells, three of which have produced from the Frontier Formation and the fourth of which has produced from the Muddy, Lakota, Morrison and Sundance Formations. The Company has run production casing and will begin testing the well in April 1997. The Company owns an 85.2% working interest in this well, subject to reduction to 84.9% after payout. During 1996, the Company had planned to drill up to 10 wells in the Cave Gulch Field. However, the Bureau of Land Management (the "BLM") determined that an environmental impact statement ("EIS") in the greater Cave Gulch area would be required to assess future development proposals from the Company and other 3 operators in the area. As a result, the Company drilled four Lance wells in 1996, and began drilling the Barrett #16 Cave Gulch deep test. The BLM has indicated that the EIS will be completed in August 1997, but there is no assurance that this will be the case. No additional drilling activity in this area for 1997 has been approved by the BLM, and the BLM has indicated that no drilling activity will be approved prior to the completion of the EIS. The Company will, however, be permitted to recomplete wells. In the event that the BLM allows drilling activity in this area pending the completion of the EIS, the Company will proceed accordingly. Through December 31, 1996, the Company had drilled 14 wells in the Cave Gulch area to test the Lance and Fort Union Sandstones. Five of these wells are producing, two are shut in due to line pressures, four are shut in due to limited pipeline capacity, two are being completed and one is waiting on completion. Two interstate pipelines serve the Cave Gulch area, and both have proposed expansions to increase their take-away capacity. The Company is supporting these expansion proposals with transportation volume commitments. Both pipeline expansions are scheduled to be completed by mid-1997. In an effort to increase production, the Company has installed a temporary gas conditioning facility that will allow the Company to remove liquids from the portion of the gas that currently does not meet pipeline specifications and to compress gas prior to entering one of the interstate pipelines. By the end of March 1997, this temporary facility enabled the Company to increase its natural gas production in the Cave Gulch area to approximately 71.3 MMcf per day. Stone Cabin Project. In the second quarter of 1996, the Company acquired a 100% working interest in 9,754 acres in the Wallace Creek Unit and adjacent land. This acreage, in the Company's Stone Cabin Project, is along the south flank of the Wind River Basin. In July 1996, the Company began an exploration and development program to target the Upper Cretaceous Muddy Sandstone and the Raderville Sandstone of the Lower Cody Shale Formation. The Company has drilled four wells in this program, two of which are producing. The Company is testing the other two wells to determine if they are capable of commercial production. The Company plans to drill up to five wells in 1997 to further develop the Muddy Formation. The BLM is imposing restrictions on winter drilling activities, which will delay drilling until April 1997. Owl Creek Thrust. The Company continues to evaluate additional exploration prospects in the Owl Creek Thrust and central Wind River Basin. The Company has 82,406 gross and 76,681 net acres under lease in portions of the Owl Creek Thrust and central Wind River Basin outside of the Cave Gulch area. In 1997, the Company plans to drill three exploratory test wells along the Owl Creek Thrust. At December 31, 1996, the Wind River Basin represented 12% of the Company's estimated proved reserves, and 21% of the Company's total production. In 1997, 6% of Barrett's capital expenditure budget is planned to be spent in the Wind River Basin for development, leasehold acquisition, seismic surveys and exploration, including participating in drilling up to 27 wells. PICEANCE BASIN. The Piceance Basin of northwestern Colorado is a core operating area for the Company and will continue to be very prominent in the Company's capital spending plans. The Company's activities in the Piceance Basin are conducted primarily in three fields: Parachute, Rulison and Grand Valley. The Company's drilling activities in the Piceance Basin primarily target the lenticular sandstones of the Williams Fork Formation of the Mesaverde Group. These sandstone reservoirs overlie the blanket sandstones of the Iles Formation in the basal Mesaverde. Barrett drilled its first well in the Piceance Basin in 1984. At December 31, 1996, the Company owned interests in 297 wells, and operated 285 of these wells in the Piceance Basin. In 1996, the Company completed the acquisition of working interests in the Piceance Basin from some of the Company's former joint working interest owners in this project, and the Company's average working interest in properties in this area increased from approximately 29% to approximately 62%. The Company paid an aggregate of $28.9 million cash and issued an aggregate of 585,661 shares of common stock to acquire these interests. 4 In February 1995, the Company received approval for 40-acre well density by the Colorado Oil and Gas Conservation Commission (the "Colorado Commission") with respect to 81 640-acre sections in the Parachute, Rulison and Grand Valley Fields, and has commenced an active development drilling program on 40- acre sites in the same Fields. In November 1996, the Company requested and received approval from the Colorado Commission for two four-well pilot drilling programs on 20-acre well density. These two pilot programs are located in the Rulison and Grand Valley Fields and are currently drilling. The Company will evaluate the engineering and geologic data resulting from these pilot programs and determine whether to apply for approval for 20-acre well density on all or selected acreage in the Piceance Basin in the future. There is no assurance that the Colorado Commission will approve any additional requests for 20-acre well density. At December 31, 1996, this Basin represented 25% of the Company's estimated proved reserves, and represented 14% of the Company's total production. The Company currently is continuously operating three drilling rigs in the Basin, with a fourth rig to be added in the second quarter 1997. In 1997, the Company intends to spend 15% of its capital expenditure budget in the Piceance Basin for development and exploration, including participating in drilling up to 101 wells and 20 recompletions. Grand Valley Gathering System. In 1985, the Company's wholly-owned subsidiary, Bargath, Inc., designed and constructed a gathering system in the Grand Valley Field to transport natural gas from certain of the Company's wells to Questar Pipeline Corporation's interstate pipeline. This gathering system subsequently has been expanded to approximately 150 miles, and a 16- inch, 27-mile pipeline has been added. Through three acquisitions in 1996, the Company increased its ownership interest in this system to approximately 62%. As of December 31, 1996, the Grand Valley Gathering System was connected to 220 producing natural gas wells in the Piceance Basin. The system now has the flexibility to deliver natural gas to three interstate pipelines, which are owned respectively by Questar Pipeline Company, Northwest Pipeline Corporation and Colorado Interstate Gas Company, and one intrastate pipeline owned by Public Service Company of Colorado and K N Energy, Inc. ("K N"). In December 1994, the Company completed the construction of a 90,000 MMBtu per day natural gas processing plant to extract liquid hydrocarbons from the natural gas stream. Depending on the take-away capacity from time to time of these four pipeline systems, the gathering system has the capability of delivering approximately 90,000 MMBtu of natural gas per day. UINTA BASIN. As an extension of its Piceance Basin operations, in 1995, the Company entered the Uinta Basin of Duchesne and Uintah Counties, in northeastern Utah. The Uinta Basin is separated from the Piceance Basin by the Douglas Creek Arch. Brundage Canyon Field. Beginning in December 1995, the Company made acquisitions totaling $5.2 million in the Brundage Canyon Field. As a result of these acquisitions and new drilling, the Company currently owns working interests ranging from 75 to 100% in 31 producing wells, a gathering and transmission system, and 36,500 gross acres, covering approximately 35,500 net acres, all of which are on the Ute Indian Reservation. Wells in this Field produce primarily from multiple sandstone reservoirs of the lower Green River Formation at depths averaging 5,500 feet. As of December 31, 1996, these wells produced approximately 800 barrels of black wax crude oil per day. The Company plans extensive work in this Field during 1997, including a 24- well program to develop infill and field extension locations, a 40-acre pilot waterflood project, and recompletions and workovers of existing wells to test the viability of shallower horizons for potential future development. Altamont-Bluebell Project. The Altamont-Bluebell Field complex, which includes the Cedar Rim area, covers a large portion of the northern Uinta Basin. In 1996, the Company acquired through a number of transactions working interests ranging from 25 to 100% in 159 producing wells and in approximately 131,500 gross and 82,700 net acres of leasehold interests. The largest of these acquisitions was completed on November 1, 1996 when the Company acquired producing and non-producing natural gas and oil properties in the Altamont- Bluebell Field. The effective date of the acquisition of a significant portion of these properties is January 1, 1997. The purchase included 120 operated wells with an average working interest of 80%, together with approximately 5 100,000 gross and 72,000 net acres of leasehold interests. The total purchase price for the November 1996 acquisition was approximately $32 million, including approximately $14 million cash, 50,000 shares of the Company's common stock, and certain non-strategic producing properties owned by the Company. The Company's production in this area is predominantly from the multiple sandstone reservoirs in the Wasatch Formation which are found at an average depth of 12,000 feet. Also productive in the Field are the upper, lower, and middle portions of the Green River Formation at depths of 5,000 to 7,000 feet. In January 1997, the Company acquired additional interests in this Field for $3.5 million. These interests consist of 16 non-operated wells with average working interests of 42%, together with approximately 10,000 gross and 4,600 net acres of leasehold interests. At December 31, 1996, the Uinta Basin represented 11% of the Company's estimated proved reserves, and 2% of the Company's total production. In 1997, the Company plans a 30 well recompletion/restimulation program and the drilling of 34 development and extension wells in the Uinta Basin. Expenditures for this activity in 1997 are expected to total $26 million, or 9% of the Company's capital expenditure budget. With this activity the Company plans to test the potential in the lower, middle, and upper Green River Formation both from behind pipe in existing wells and in new infill locations. POWDER RIVER BASIN. The Powder River Basin in Wyoming is primarily an oil province, with production from Cretaceous and Permian-age Formations. One of the reservoir targets in this area is the Permian Minnelusa Formation. This Basin contributes approximately 44% of the Company's daily oil production. The Company has initiated or is planning the use of alkaline surfactant polymer ("ASP") technology to chemically enhance oil recovery in a number of fields. The Company also is using 3-D seismic technology to identify development opportunities in this area. Two exploration wells targeting the Minnelusa and Shannon Formations, respectively, were drilled and abandoned in the first quarter of 1997. At December 31, 1996, this Basin represented 4% of the Company's estimated proved reserves and 8% of the Company's total production. In 1997, the Company intends to spend 1% of its capital expenditure budget for development utilizing 3-D seismic technology, enhanced recovery projects and exploration opportunities in the Powder River Basin, including participating in drilling up to 36 wells. GREATER GREEN RIVER BASIN. The Company owns leasehold interests within the greater Green River Basin, primarily in the West Side Canal Field and in the Wyoming Overthrust Trend. The Company participated in two wells in the Green River Basin in 1996. At December 31, 1996, this Basin represented 2% of the Company's estimated proved reserves, and 3% of the Company's total production. In 1997, the Company intends to spend approximately $4 million for capital expenditures in drilling up to nine wells and recompleting three additional wells in the Green River Basin. MID-CONTINENT REGION ARKOMA BASIN. Due to the complex structure and overlapping nature of the rock formations, the Company has been using and will continue to use 3-D seismic surveys extensively in the Arkoma Basin in Oklahoma. In 1996, Barrett participated in the drilling of 15 wells in four areas of the Arkoma Basin in Oklahoma: South Panola 3-D area, Limestone Ridge area, Wilburton Field, and Alderson area. At December 31, 1996, this Basin represented 3% of the Company's estimated proved reserves, and 6% of the Company's total production. In 1997, the Company intends to spend 3% of its capital expenditure budget for drilling in the Arkoma Basin, including participating in drilling up to 10 wells, together with land and seismic surveys. ANADARKO BASIN. Since 1993, the Anadarko Basin in southwestern Oklahoma has been one of the Company's most active drilling areas. In 1996, the Company participated in the drilling of 58 wells with working 6 interests ranging from 1.5 to 100% after payout. While staying active in the Strong City Red Fork Play, the Company has become increasingly active in the Mountain Front Granite Wash and Springer plays. At December 31, 1996, this Basin represented 6% of the Company's estimated proved reserves, and 11% of the Company's total production. The Company plans to spend 10% of its 1997 capital expenditure budget in the Anadarko Basin for development and exploration drilling, including participating in drilling up to 71 wells, together with leasehold acquisitions and seismic surveys as currently planned. HUGOTON EMBAYMENT. The largest single producing area for the Company is the Hugoton Embayment, which is one of the largest natural gas producing areas in the United States, located in southwest Kansas, the Oklahoma panhandle and the Texas panhandle. The Company produces natural gas from three fields in the Hugoton Embayment: the Hugoton, the Guymon-Hugoton and Panoma Fields. Hugoton and Guymon-Hugoton Fields. In the Hugoton and Guymon-Hugoton Fields, the Company has working interests in 364 gross wells and operates 312 of them. The Hugoton and the Guymon-Hugoton Fields produce from the Chase Formation. Six wells were drilled in the Hugoton Field in 1996, all of which have been placed on production. Panoma Field. Panoma is the field designation for natural gas produced from the Council Grove Formation, a formation beneath the Chase Formation. The Council Grove Formation has similar reservoir rocks as the Chase Formation. However, the productive limits are not as extensive. Presently, the Company has a working interest in 54 gross Panoma wells and operates 50 of those wells, including one well drilled in 1996 which was placed on production in January 1997. Natural Gas Sales Agreement. The majority of the Company's natural gas production from the Hugoton and Panoma Fields is sold under a long-term contract (life-of-field) to KN Gas Supply Services, Inc. ("KNGSS"). Among other things, this contract provides for annual re-determination of the price the Company is to receive. In 1997, as in 1996, the price is calculated each month by using the average of four Mid-Continent index prices less a variable amount ranging from $.11 per MMBtu for an average index price less than $.75 to a maximum of $.20 for an average index price of $2.26 or higher. The volume of natural gas for which the Company receives payment is reduced by one percent of the volume as an in-kind fuel charge for moving the natural gas. Net Profit Agreements. The Company produces natural gas in the Guymon- Hugoton Field and the nearby Camrick Field under a Dry Gas Agreement with Chevron U.S.A. Inc. ("Chevron"). This agreement allows the Company to expend funds for the operation of the properties (including the cost of drilling wells) and to recoup the funds so expended from current production income. Eighty percent of net operating income generated by the natural gas production (after operational costs are recouped, including the cost of drilling and equipping wells) is then paid to Chevron. At each of December 31, 1995 and 1996, the Company had interests in 56 wells subject to the terms of this agreement. The Company also produces natural gas in the Hugoton Field under various agreements similar to the Chevron agreement, except that net operating income is allocated 15% to the Company and 85% to other parties. At December 31, 1996, the Company had interests in an aggregate of 49 Chase Formation wells and eight Council Grove Formation wells under these other agreements. The third party interests under all the net profit agreements are treated as lease operating expenses by the Company. Additional or replacement wells drilled on the properties would be operated under the same terms and conditions as existing wells, and would result in the commencement of the 80/20 or 85/15 net operating income allocation after the cost of the new wells is recovered. Hugoton Gas Trust Agreement. Natural gas rights established in 1955 to approximately 50,000 acres in Finney and Kearny Counties, Kansas were transferred to Plains by K N on October 1, 1984 subject to a natural gas payment of $0.06 per Mcf for natural gas produced from the acreage. Quarterly payments are made by the Company to the Hugoton Gas Trust, a publicly held trust created in 1955. Payments terminate when the estimated 7 gross recoverable natural gas reserves decline to 50 Bcf or less. As of December 31, 1996, the gross proved natural gas reserves attributable to the leases burdened by this agreement were estimated to be 144.3 Bcf. The natural gas payments are treated as lease operating expenses by the Company. At December 31, 1996, the Company had working interests in 196 wells that were subject to these payments. Any additional natural gas wells drilled on this acreage also will be subject to the $0.06 payment per Mcf of natural gas produced. At December 31, 1996, this Basin represented 26% of the Company's estimated proved reserves, and 22% of the Company's total production. Barrett intends to spend $2 million of its 1997 capital expenditure budget on the Hugoton Embayment for development drilling and increased deliverability through compression, including participating in drilling 16 new wells. PERMIAN BASIN. The Permian Basin in west Texas and southeast New Mexico is primarily an oil province. As of December 31, 1996, the Company had an interest in 270 gross wells (191 net wells) located in the Permian Basin, which produce approximately 1,337 barrels of oil per day net to the Company's interests. In 1996, Barrett participated in drilling 15 wells in the Permian Basin. At December 31, 1996, this Basin represented 4% of the Company's estimated proved reserves, and 7% of the Company's total production. Barrett intends to spend 3% of its 1997 capital expenditure budget in the Permian Basin, including participating in drilling up to 21 wells. This includes six wells in the Sprayberry Trend where a recent 80-acre downspacing was approved. GULF OF MEXICO REGION Beginning in the latter half of 1995 and continuing during 1996, the Company established a new core area in the Gulf of Mexico in the shallow offshore Louisiana and Texas waters. In 1996, the Company participated in 15 Gulf of Mexico wells, 12 of which were successful. The Company believes that this area has significant reserve potential and is well suited to Barrett's exploration emphasis and geologic expertise. The availability of extensive 3-D seismic coverage over most of the Outer Continental Shelf ("OCS"), the frequency of lease sales and the turnover of expiring leases also make the Gulf of Mexico an attractive area. In addition, wells in the Gulf of Mexico typically produce at higher rates, which increases cash flow, but have relatively shorter productive lives. This production profile will complement the Company's long- lived, relatively lower deliverability wells in the Rocky Mountain and Mid- Continent regions. Also, Gulf of Mexico natural gas prices historically have been higher than prices in other regions in which the Company operates. Initially, the Company's Gulf of Mexico operations centered on developing high quality prospects with established operators. At the April 1996 Central Gulf of Mexico Outer Continental Shelf Lease Sale #157, the Company joined another operator in acquiring nine blocks. The Company has a 25% working interest through completion of production facilities and a 22% working interest thereafter in each of these nine blocks. Separately, the Company joined with a second operator with a 50% working interest, in acquiring one block. In addition, the Company acquired a block in which it has a 100% interest. Bonus payments net to the Company for these lease interests totaled $2.3 million. The Company's efforts are now directed at internally developing an inventory of high quality prospects for future drilling. This effort was significantly advanced at the Western Gulf of Mexico Outer Continental Shelf Lease Sale #161 in September 1996 as a result of which the Company acquired 17 blocks in water depths ranging from 33 to 315 feet. The Company has a 100% working interest in 14 of these blocks and a 50% working interest in the three other blocks. The Company's net share of the bonus payments for these leases was $34.4 million. On March 5, 1997, the Company was the high bidder and apparent winner on seven tracts offered in the Federal Offshore Lease Sale #166 for the Central Gulf of Mexico. All bids are subject to approval by the Minerals Management Service ("MMS"). The Company will have a 100% working interest in all of these blocks, which range in water depth from 17 to 201 feet, if approved by the MMS. Barrett's net share of the bonus payment for these apparent winning bids was $14.87 million if all are accepted. 8 At December 31, 1996, the Gulf of Mexico represented 3% of the Company's estimated proved reserves, and 3% of the Company's total production. In 1997, the Company intends to spend $113 million or 41% of the Company's 1997 capital expenditure budget to drill 24 wells, acquire additional 3-D seismic for future prospects, lease additional future prospects and to put into production eight wells drilled in 1996. INTERNATIONAL OPERATIONS With an industry partner, the Company obtained, in November 1996, a license to evaluate, explore and develop Block 55 (A, B, and C), which encompasses approximately 820,000 acres in the Maranon Basin of eastern Peru. The Company currently has a 55% working interest in this project and has the right to increase its working interest to 77.5%. In the initial phase of the license, which is underway, the Company and its co-venturer will be conducting seismic reprocessing and environmental and engineering feasibility studies regarding the viability of developing the Bretana Field, which was discovered in 1974 by another company. Gross costs of approximately $1.3 million for this first phase are expected. Following those studies, it is anticipated that an appraisal well will be drilled in the third quarter of 1997. The gross costs of drilling and testing this well are anticipated to be approximately $4.5 million. In late January 1997, the Company entered into an agreement with industry partners that provided the Company with a working interest in Block 67, which covers approximately two million gross acres and is located in the Maranon Basin of northeastern Peru. The Company and its partners intend to acquire and analyze between 200 to 250 miles of seismic data in preparation for exploratory drilling to begin in late 1997 or early 1998. The Company's participation, which is subject to approval of the government of Peru, is intended to consist of a 45% working interest, subject to a cost commitment of 60% of the 1996 and 1997 seismic costs and 60% of the cost of up to three exploratory wells. The Company estimates that its total net cost for this participation in seismic acquisition and the drilling of three exploratory wells will approximate $7.5 million in 1997 and $7.2 million in 1998. It is anticipated that the Company will be designated operator for operations in Block 67 in mid-1997. Pursuant to the licenses for both Block 55 and 67, the Republic of Peru receives a variable royalty payment on production that can range from 18 to 38% based on an investment revenue ratio and is anticipated to average approximately 23%. Estimated capital expenditures for international operations for 1997 constitute approximately 4% of the Company's capital expenditure budget. CERTAIN DEFINITIONS Unless otherwise indicated in this document, natural gas volumes are stated at the legal pressure base of the state or area in which the reserves are located at 60(degrees) Fahrenheit. Natural gas equivalents are determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids so that one barrel of oil is referred to as six Mcf of natural gas equivalent or "Mcfe." As used in this document, the following terms have the following specific meanings: "Mcf" means thousand cubic feet, "MMcf" means million cubic feet, "Bcf" means billion cubic feet, "Bbl" means barrel, "MBbl" means thousand barrels, "Mcfe" means thousand cubic feet equivalent, "MMcfe" means million cubic feet equivalent, and "MMBtu" means million British thermal units. With respect to information concerning the Company's working interests in wells or drilling locations, "gross" natural gas and oil wells or "gross" acres is the number of wells or acres in which the Company has an interest, and "net" gas and oil wells or "net" acres are determined by multiplying "gross" wells or acres by the Company's working interest in those wells or acres. A working interest in an oil and natural gas lease is an interest that gives the owner the right to drill, produce, and conduct operating activities on the property and to receive a share of production of any hydrocarbons covered by the lease. A working interest in an oil and gas lease also entitles its owner to a proportionate interest in any well located on the lands covered by the lease, subject to all royalties, overriding royalties and other burdens, to all costs and expenses of exploration, development and operation of any well located on the lease, and to all risks in connection therewith. 9 "Capital expenditures" means costs associated with exploratory and development drilling (including exploratory dry holes); leasehold acquisitions; seismic data acquisitions; geological, geophysical and land related overhead expenditures; delay rentals; producing property acquisitions; and other miscellaneous capital expenditures. "Capital expenditure budget" means an estimate prepared by management for the total expenditures anticipated to be incurred during the subject time period. This amount can deviate or fluctuate due to the timing of drilling of wells, environmental considerations, acquisition of important fee, state and federal leases, and natural gas and oil prices. A "development well" is a well drilled as an additional well to the same horizon or horizons as other producing wells on a prospect, or a well drilled on a spacing unit adjacent to a spacing unit with an existing well capable of commercial production and which is intended to extend the proven limits of a prospect. An "exploratory well" is a well drilled to find commercially productive hydrocarbons in an unproved area, or to extend significantly a known prospect. A "farmout" is an assignment to another party of an interest in a drilling location and related acreage conditional upon the drilling of a well on that location. A "farm-in" is an assignment by the owner of a working interest in an oil and gas lease of the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary working interest in the lease. The assignee is said to have "farmed-in" the acreage. "Present value of estimated future net revenues" means the present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with the Securities and Exchange Commission guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expense and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. A "recompletion" is the completion of an existing well for production from a formation that exists behind the casing of the well. "Reserves" means natural gas and crude oil, condensate and natural gas liquids on a net revenue interest basis, found to be commercially recoverable. "Proved developed reserves" includes proved developed producing reserves and proved developed behind-pipe reserves. "Proved developed producing reserves" includes only those reserves expected to be recovered from existing completion intervals in existing wells. "Proved undeveloped reserves" includes those reserves expected to be recovered from new wells on proved undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. PRODUCTION The table below sets forth information with respect to the Company's net interests in producing natural gas and oil properties for each of its last three years, respectively:
NATURAL GAS AND OIL PRODUCTION ----------------------- YEAR ENDED DECEMBER 31, ----------------------- 1994 1995 1996 ------- ------- ------- Quantities Produced and Sold Natural gas (Bcf).................................. 33.3 47.7 60.9 Oil and condensate (MMBbls)........................ 1.3 1.7 1.9 Average Sales Price Natural gas ($/Mcf)................................ $ 1.83 $ 1.47 $ 1.88 Oil and condensate ($/Bbl)......................... 13.95 15.76 19.51 Average Production Costs/Mcfe....................... $ 0.69 $ 0.60 $ 0.66
10 PRODUCTIVE WELLS The productive wells in which the Company owned a working interest as of December 31, 1996 are described in the following table:
PRODUCTIVE WELLS (1) ------------------------- GAS WELLS OIL WELLS ------------ ------------ GROSS NET GROSS NET ----- ------ ----- ------ Rocky Mountain Region Wind River....................................... 46 23.40 0 0.00 Piceance......................................... 297 159.56 0 0.00 Powder River..................................... 39 3.00 328 81.40 Green River...................................... 45 22.64 1 1.00 Uinta............................................ 1 0.78 135 115.58 Mid-Continent Region Arkoma........................................... 121 32.06 0 0.00 Anadarko......................................... 191 73.03 16 15.60 Hugoton Embayment................................ 418 353.68 0 0.00 Permian.......................................... 16 10.48 254 180.74 Gulf of Mexico Region.............................. 21 5.86 3 1.00 Other.............................................. 100 66.89 74 5.90 ----- ------ --- ------ Total.......................................... 1,295 751.38 811 401.22 ===== ====== === ======
- -------- (1) Each well completed to more than one producing zone is counted as a single well. The Company has royalty interests in certain wells that are not included in this table. DRILLING ACTIVITY The following table summarizes the Company's natural gas and oil drilling activities, all of which were located in the United States, during the last three years:
WELLS DRILLED ----------------------------------- YEAR ENDED DECEMBER 31, ----------------------------------- 1994 1995 1996 ----------- ----------- ----------- GROSS NET GROSS NET GROSS NET ----- ----- ----- ----- ----- ----- Development Natural gas............................. 100 36.51 88 39.03 94 46.24 Oil..................................... 19 12.62 22 11.68 43 30.48 Non-productive.......................... 18 7.65 10 3.51 17 8.03 --- ----- --- ----- --- ----- Total................................. 137 56.78 120 54.22 154 84.75 === ===== === ===== === ===== Exploratory Natural gas............................. 1 0.50 0 0.00 8 4.05 Oil..................................... 5 0.58 1 0.33 3 1.00 Non-productive.......................... 8 1.84 8 2.65 6 3.66 --- ----- --- ----- --- ----- Total................................. 14 2.92 9 2.98 17 8.71 === ===== === ===== === =====
In addition, the Company was participating in 25 gross (10.82 net) wells, which were in the process of being drilled, at December 31, 1996. 11 RESERVES The table below sets forth the Company's estimated quantities of historical proved reserves, all of which were located in the United States, and the present values attributable to those reserves. These estimates were prepared by the Company. With respect to the reserve estimates as of and prior to December 31, 1995, certain portions were reviewed by Ryder Scott Company, an independent reservoir engineer, and the other portions were reviewed or prepared by Netherland, Sewell & Associates, Inc., an independent reservoir engineer. The estimates as of December 31, 1996 were reviewed solely by Ryder Scott Company. The total proved net reserves estimated by the Company were within 10% of those reviewed and estimated by the engineers; however, on a well by well basis, differences of greater than 10% may exist.
ESTIMATED PROVED RESERVES ----------------------------------------------- DECEMBER 31, ----------------------------------------------- 1994 1995 1996 ------------ ------------ ------------ (DOLLARS IN MILLIONS, EXCEPT SALES PRICE DATA) Estimated Proved Reserves Natural gas (Bcf).......... 458.8 513.5 674.9 Oil and condensate (MMBbls).................. 11.4 13.0 23.2 Total (Bcfe)............. 527.5 591.3 814.3 Proved developed reserves (Bcfe)...................... 440.1 489.7 606.3 Natural gas price as of December 31 ($/Mcf)......... $ 1.67 $ 1.77 $ 3.46 Oil price as of December 31 ($/Bbl)..................... $ 14.43 $ 17.35 $ 24.12 Present value of estimated future net revenues before future income taxes discounted at 10%(1)........ $ 322.7 $ 432.6 $ 1,121.5 Standardized measure of discounted net cash flows(2).................... $ 242.6 $ 309.9 $ 764.8
- -------- (1) The present value of estimated future net revenues on a non-escalated basis is based on weighted average prices realized by the Company of $1.95 per Mcf of natural gas and $11.05 per Bbl of oil at December 31, 1993, $1.67 per Mcf of natural gas and $14.43 per Bbl of oil at December 31, 1994, $1.77 per Mcf of natural gas and $17.35 per Bbl of oil at December 31, 1995 and $3.46 per Mcf of natural gas and $24.12 per Bbl of oil at December 31, 1996. (2) The Standardized measure of discounted net cash flows prepared by the Company represents the present value of estimated future net revenues after income taxes discounted at 10%. In accordance with applicable requirements of the Securities and Exchange Commission, (the "Commission"), estimates of the Company's proved reserves and future net revenues are made using sales prices estimated to be in effect as of the date of such reserve estimates and are held constant throughout the life of the properties (except to the extent a contract specifically provides for escalation). Estimated quantities of proved reserves and future net revenues therefrom are affected by natural gas and oil prices, which have fluctuated widely in recent years. There are numerous uncertainties inherent in estimating natural gas and oil reserves and their estimated values, including many factors beyond the control of the producer. The reserve data set forth in this document represents only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers, including those used by the Company, may vary. In addition, estimates of reserves are subject to revision based upon actual production, results of future development and exploration activities, prevailing natural gas and oil prices, operating costs and other factors, which revisions may be material. Accordingly, reserve estimates are often different from the quantities of natural gas and oil that are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which they are based. In general, the volume of production from natural gas and oil properties owned by the Company declines as reserves are depleted. Except to the extent the Company acquires additional properties containing proved reserves 12 or conducts successful exploration and development activities, or both, the proved reserves of the Company will decline as reserves are produced. Volumes generated from future activities of the Company are therefore highly dependent upon the level of success in acquiring or finding additional reserves and the costs incurred in doing so. Reference should be made to "Supplemental Gas and Oil Information" on pages F-21 through F-23 following the Consolidated Financial Statements included in this document for additional information pertaining to the Company's proved natural gas and oil reserves as of the end of each of the last three years. During the past year, the only report concerning the Company's estimated proved reserves that was filed with a U.S. federal agency other than the Commission was filed prior to the Company's merger with Plains, by Barrett and Plains, respectively. This report was the Annual Survey of Domestic Oil and Gas Reserves and was filed with the Energy Information Administration ("EIA") as required by law. Only minor differences of less than 5% in reserve estimates, which were due to small variances in actual production versus year end estimates, have occurred in certain classifications reported in this document as compared to those in the EIA report. DEVELOPED AND UNDEVELOPED ACREAGE The gross and net acres of developed and undeveloped natural gas and oil leases held by the Company as of December 31, 1996 are summarized in the following table. "Undeveloped Acreage" includes leasehold interests that already may have been classified as containing proved undeveloped reserves.
DEVELOPED ACREAGE UNDEVELOPED ACREAGE ----------------- ------------------- GROSS NET GROSS NET -------- -------- ---------- -------- Rocky Mountain Region Wind River.............................. 5,115 3,411 105,296 93,344 Piceance................................ 36,560 20,336 116,405 55,443 Powder River............................ 42,848 26,319 68,640 26,214 Green River............................. 22,055 7,038 52,139 37,673 Uinta................................... 97,580 60,940 57,168 44,346 Mid-Continent Region Arkoma.................................. 51,200 14,450 19,112 13,789 Anadarko................................ 83,265 49,920 56,256 51,855 Hugoton Embayment....................... 88,332 84,946 0 0 Permian................................. 45,701 15,143 5,952 1,313 Gulf of Mexico Region..................... 34,765 9,255 179,791 114,093 International............................. 0 0 820,000 451,000 Other..................................... 41,225 28,209 27,394 11,204 -------- -------- ---------- -------- Total................................. 548,646 319,967 1,508,153 900,274 ======== ======== ========== ========
- -------- (1) Undeveloped acreage is leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves. Of the aggregate of 1,508,153 gross and 900,274 net undeveloped acres, 165,896 gross and 75,250 net acres are held by production from other leasehold acreage. 13 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, 1997........................................ 91,416 31,630 December 31, 1998........................................ 30,493 30,348 December 31, 1999........................................ 58,476 58,408 December 31, 2000 and later.............................. 1,327,768 779,888
OVERRIDING ROYALTY INTERESTS The Company owns overriding royalty interests covering in excess of 52,394 gross acres. The majority of these overriding royalty interests are within a range of approximately 0.25 to 2.5 percent. NATURAL GAS AND OIL MARKETING AND TRADING Barrett markets all of its own natural gas and oil production from wells that it operates. In addition, the Company engages in natural gas trading activities, which involve purchasing natural gas from third parties and selling natural gas to other parties at prices and volumes that management anticipates will result in profits to the Company. Through these natural gas trading activities, the Company obtains knowledge and information that enables it to more effectively market its own production. NATURAL GAS. The Company has entered into a number of gas sales agreements on behalf of itself and its industry partners with respect to the sale of natural gas from its properties in each of the Company's basins. These contracts vary with respect to their specific provisions, including price, quantity, and length of contract. As of December 31, 1996, less than 7% of the Company's production was committed to natural gas sales contracts that had fixed prices or price ceilings. With the exception of two contracts covering approximately 8,100 MMBtu per day of natural gas production from the Piceance Basin through 2011, none of the contracts provides for fixed prices or price ceilings beyond May 1997. The Company believes that it has sufficient production from its properties to meet the Company's delivery obligations under its existing natural gas sales contracts. The Company has entered into a series of firm transportation agreements with various Rocky Mountain pipeline companies. At January 1, 1997, these transportation arrangements had terms ranging from seven months to ten years. These transportation agreements provide the Company the opportunity to transport a portion of its Rocky Mountain natural gas production into the Mid- Continent area. These agreements in total provide transportation of approximately 52% of the Company's current daily Rocky Mountain production. In addition to the agreements described above, the Company has entered into a transportation arrangement to support the conversion of a crude oil line to natural gas service. This expansion is designed to transport Rocky Mountain natural gas production to the Mid-Continent area for sale. The Company has committed to 5,000 MMBtu per day of pipeline capacity for a term of five years. This expansion is subject to Federal Energy Regulatory Commission ("FERC") approval and is scheduled to be operational by the third quarter of 1997. For each of 1996 and 1997, the Company renegotiated the pricing provisions with KNGSS with respect to a majority of its Hugoton and Panoma Fields natural gas production. The price is calculated on a monthly basis by using the average of four Mid-Continent index prices less a variable amount ranging from $.11 per MMBtu for an average index price less than $.75 to a maximum of $.20 for an average index price of $2.26 or higher. The volume of natural gas for which the Company receives payment is reduced by one percent of the volume as an in-kind fuel charge for moving the natural gas. 14 During the year ended December 31, 1996, there was one natural gas purchaser, KNGSS, that accounted for approximately 11% of the Company's total revenues. The Company believes it would be able to locate alternate customers in the event of the loss of this customer. The Company has established a Risk Management Committee to oversee its production hedging and trading activities. The Risk Management Committee consists of the Chief Executive Officer, the President and Chief Operating Officer, the Chief Financial Officer, and the Executive Vice President-- Operations. With respect to production hedge transactions, it is the policy of the Company that the Risk Management Committee review and approve all such transactions. As a result of its natural gas trading activities, the Company may from time to time have natural gas purchase or sales commitments without corresponding contracts to offset these commitments, which could result in losses to the Company. The Company currently attempts to control and manage its exposure to these risks by monitoring and hedging its trading positions as it deems appropriate and by having the Company's Risk Management Committee review significant trades or positions before they are committed to by trading personnel. All fixed price trading activities are hedged to lock in margins. As of December 31, 1996, the Company had entered into financial transactions to hedge approximately 8.8 Bcf of natural gas production for the period from January 1997 through October 1997. In January 1997, the Company entered into a transaction to hedge an aggregate of 25.6 Bcf of natural gas production from the Rocky Mountain Region for the five-year period from March 1998 through February 2003. In February 1997, the Company entered into an additional transaction to hedge an aggregate of approximately 18.2 Bcf of natural gas production from the Rocky Mountain Region for the same five-year period. In March 1997, the Company entered into an additional transaction to hedge an aggregate of approximately 13.7 Bcf of natural gas production from the Rocky Mountain Region for the same time period. For the year ended December 31, 1996, revenues from trading activities, which includes the cost of natural gas purchased or sold for trading purposes, were $46.9 million, which constituted 23% of the Company's consolidated revenues and generated a gross margin of $2.8 million. See "Management's Discussion and Analysis of Financial Condition and Results of Operations." OIL AND CONDENSATE. Oil, including condensate production, is generally sold from the leases at posted field prices, plus negotiated bonuses. Marketing arrangements are made locally with various petroleum companies. The Company sells its own oil production to numerous customers. No single customer's total oil purchases represented more than 10% of total Company revenues in 1996. Oil revenues totaled $37.3 million for the year ended December 31, 1996 and represented 18% of the Company's total revenues for that period. The Company does not engage in oil trading activities. GOVERNMENT REGULATION OF THE OIL AND GAS INDUSTRY GENERAL The Company's exploration, production and marketing operations are regulated extensively at the federal, state and local levels. Natural gas and oil exploration, development and production activities are subject to various laws and regulations governing a wide variety of matters. For example, hydrocarbon- producing states have statutes or regulations addressing conservation practices and the protection of correlative rights, and such regulations may affect the Company's operations and limit the quantity of hydrocarbons the Company may produce and sell. Other regulated matters include marketing, pricing, transportation, and valuation of royalty payments. Certain operations the Company conducts are on federal oil and gas leases, which the MMS administers. The MMS issues such leases through competitive bidding. These leases contain relatively standardized terms and require compliance with detailed MMS regulations and orders pursuant to the Outer Continental Shelf Lands 15 Act ("OCSLA"), which are subject to change by the MMS. For offshore operations, lessees must obtain MMS approval for exploration plans and development and production plans prior to the commencement of such operations. In addition to permits required from other agencies (such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency), lessees must obtain a permit from the MMS prior to the commencement of drilling. The MMS has promulgated regulations requiring offshore production facilities located on the OCS to meet stringent engineering and construction specifications. The MMS proposed additional safety-related regulations concerning the design and operating procedures for OCS production platforms and pipelines. These proposed regulations were withdrawn pending further discussions among interested federal agencies. The MMS also has issued regulations restricting the flaring or venting of natural gas and liquid hydrocarbons without prior authorization. Similarly, the MMS has promulgated regulations governing the plugging and abandonment of wells located offshore and the removal of all production facilities. To cover the various obligations of lessees on the OCS, the MMS generally requires that lessees post substantial bonds or other acceptable assurances that such obligations will be met. The cost of such bonds or other surety can be substantial and there is no assurance that bonds or other surety can be obtained in all cases. Under certain circumstances, the MMS may require any Company operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect the Company's financial condition and operations. At the U.S. federal level, the FERC regulates interstate transportation of natural gas under the Natural Gas Act and regulates the maximum selling prices of certain categories of natural gas sold in "first sales" in interstate and intrastate commerce under the Natural Gas Policy Act ("NGPA"). Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act deregulated natural gas prices for all "first sales" of natural gas, which includes sales by Barrett of its own production. As a result, all sales of the Company's natural gas produced in the U.S. may be sold at market prices, unless otherwise committed by contract. Congress could reenact price controls in the future. See "--Natural Gas and Oil Marketing and Trading." The Company's natural gas sales are affected by regulation of intrastate and interstate natural gas transportation. In an attempt to promote competition, the FERC has issued a series of orders which have altered significantly the marketing and transportation of natural gas. The effect of these orders has been to enable the Company to market its natural gas production to purchasers other than the interstate pipelines located in the vicinity of its producing properties. The Company believes that these changes have generally improved the Company's access to transportation and have enhanced the marketability of its natural gas production. To date, Barrett has not experienced any material adverse effect on natural gas marketing as a result of these FERC orders; however, the Company cannot predict what new regulations may be adopted by the FERC and other regulatory authorities, or what effect subsequent regulations may have on its future natural gas marketing. The Company also is subject to laws and regulations concerning occupational safety and health. It is not anticipated that the Company will be required in the near future to expend amounts that are material in the aggregate to the Company's overall operations by reason of occupational safety and health laws and regulations, but inasmuch as such laws and regulations are frequently changed, the Company is unable to predict the ultimate cost of compliance. ENVIRONMENTAL MATTERS The Company, as an owner or lessee and operator of natural gas and oil properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability and substantial penalties on the lessee under a natural gas and oil lease for the cost of pollution clean-up resulting from operations, subject the lessee to liability for pollution damages, require suspension or cessation of operations in affected areas, and impose restrictions on the injection of liquid into subsurface aquifers that may contaminate groundwater. The Oil Pollution Act of 1990, as recently amended by the Coast Guard Authorization Act of 1996, requires operators of offshore facilities to provide financial assurance in the amount of $35 million to cover potential environmental cleanup and restoration costs. This amount is subject to upward regulatory adjustment. 16 The Company has made, and will continue to make, expenditures in its efforts to comply with these requirements, which it believes are necessary business costs in the oil and gas industry. The Company believes it is in substantial compliance with applicable environmental laws and requirements and to date such compliance has not had a material adverse effect on the earnings or competitive position of the Company, although there can be no assurance that significant costs for compliance will not be incurred in the future. The Company maintains insurance coverages which it believes are customary in the industry although it is not fully insured against many environmental risks. TITLE TO PROPERTIES Title to properties is subject to royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the oil and gas industry, to liens for current taxes not yet due and to other encumbrances. As is customary in the industry in the case of undeveloped properties, little investigation of record title is made at the time of acquisition (other than a preliminary review of local records). The Company reviews information concerning federal and state offshore lease blocks prior to acquisition. Drilling title opinions are always prepared before commencement of drilling operations; however, as is customary in the industry, the Company does not obtain drilling title opinions on offshore leases it has received directly from the MMS. DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS This Annual Report on Form 10-K includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements other than statements of historical facts included in this Annual Report on Form 10-K, including without limitation statements under "Items 1 and 2. Business and Properties-- Core Areas of Activity", "--Reserves", "--Natural Gas and Oil Marketing and Trading", and "--Government Regulation of the Oil and Gas Industry", "Item 3. Legal Matters", and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations", regarding the Company's financial position, reserve quantities and net present values, business strategy, plans and objectives of management of the Company for future operations and capital expenditures, are forward-looking statements. Although the Company believes that the expectations reflected in the forward-looking statements and the assumptions upon which such forward-looking statements are based are reasonable, it can give no assurance that such expectations and assumptions will prove to have been correct. Reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Additional statements concerning important factors that could cause actual results to differ materially from the Company's expectations ("Cautionary Statements") are disclosed in this Annual Report on Form 10-K and in the "Risk Factors" section of the Company's Prospectus dated February 11, 1997 included in the Company's Registration Statement on Form S-3 (File Number 333-19363). All written and oral forward-looking statements attributable to the Company or persons acting on its behalf subsequent to the date of this Annual Report on Form 10-K are expressly qualified in their entirety by the Cautionary Statements. ITEM 3. LEGAL PROCEEDINGS On November 29, 1996, the Company filed a petition with the United States Tax Court to request a redetermination of a Notice Of Deficiency issued to the Company by the Internal Revenue Service (the "IRS"). The IRS had examined the federal tax returns of the Company's Plains subsidiary for the calendars years of 1991, 1992 and 1993, which were prior to the merger of Plains and a subsidiary of the Company. The IRS issued a Notice of Deficiency of $5.3 million, together with penalties of $1.1 million, and an undetermined amount of interest. The IRS Notice Of Deficiency resulted primarily from the IRS's disallowance of certain net operating loss deductions claimed during the periods under examination. These net operating losses originally had been incurred by a company that was acquired by Plains in 1986. The Company currently has additional unused net operating loss carry forwards of approximately $30 million related to the same acquisition. 17 Management of the Company disagrees with the IRS position. In management's opinion, the federal tax returns of Plains reflect the proper federal income tax liability and the existing net operating loss carry forwards are appropriate as supported by relevant authority. The Company will vigorously contest these proposed adjustments and believes it will prevail in its positions. It is anticipated that the final determination of this matter will involve a lengthy process. The petition filed by the Company on November 29, 1996 with the United States Tax Court requests that the IRS Notice Of Deficiency be redetermined by allowing the net operating losses deductions as originally reported in the Plains tax returns. At December 31, 1996, the Company was a party to certain other legal proceedings which have arisen out of the ordinary course of business. Based on the facts currently available, in management's opinion the liability, individually or in the aggregate, if any, to the Company resulting from such actions will not have a material adverse effect on the Company's consolidated financial position or results of operations. ITEM 4. SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS No matters were submitted to a vote of the Company's security holders during the fourth quarter of the year ended December 31, 1996. 18 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, 1995............................................... $21.75 $16.87 June 30, 1995................................................ 25.87 19.37 September 30, 1995........................................... 25.37 19.37 December 31, 1995............................................ 30.62 21.00 March 31, 1996............................................... $29.50 $22.00 June 30, 1996................................................ 29.87 22.50 September 30, 1996........................................... 36.75 28.00 December 31, 1996............................................ 43.00 33.00
On March 20, 1997, the closing price for the Company's common stock was $34.00 per share. (b) Holders. The number of record holders of the Company's common stock as of March 20, 1997, was 4,148. (c) Dividends. The Company has not paid any cash dividends since its inception. The Company's credit agreement restricts payment of dividends to amounts that are less than 50 percent of net income. The Company anticipates that all earnings will be retained for the development of its business and that no cash dividends on its common stock will be declared in the foreseeable future. ITEM 6. SELECTED FINANCIAL DATA The following table sets forth certain selected financial data of the Company for each of the last five years ended December 31:
YEAR ENDED DECEMBER 31, --------------------------------------------- 1996 1995 1994 1993 1992 -------- -------- -------- -------- -------- (IN THOUSANDS, EXCEPT PER SHARE DATA) Revenues........................ $202,572 $128,016 $109,458 $106,072 $ 89,050 Net income (loss)............... 29,256 (2,240) 11,299 13,666 13,872 Per share....................... 1.02 (0.09) 0.46 0.55 0.47 Total assets at the end of each period......................... 576,945 340,412 310,952 243,452 208,601 Long-term debt at the end of each period.................... 70,000 89,000 53,000 13,500 20,000
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion should be read in conjunction with the Consolidated Financial Statements and Notes thereto referred to in "Item 8. Financial Statements and Supplemental Data", and "Items 1 and 2. Business and Properties--Disclosure Regarding Forward-Looking Statements" of this Form 10- K. LIQUIDITY AND CAPITAL RESOURCES At December 31, 1996, the Company had cash and short-term investments of $14.5 million, working capital of $11.4 million, property and equipment of $487.3 million and total assets of $576.9 million. Compared to 19 December 31, 1995, cash and short-term investments increased $7.0 million, working capital increased $7.7 million, property and equipment increased $186.6 million, and total assets increased $236.5 million. During 1996, the Company generated operating cash flow of $87.8 million before working capital changes, which is $54.4 million greater than the amount generated in 1995. After working capital changes, cash flow provided by operations was $88.7 million, an increase of $53.2 million from 1995. The 1995 amounts were net of costs associated with the merger of Plains Petroleum Company ("Plains"). In June 1996, the Company issued 5.4 million shares of common stock for $26.375 per share in a public offering. The net proceeds from the issuance of the shares was approximately $134.8 million after deducting issuance costs and underwriting fees. Of the net proceeds from this offering, $110 million was used to repay the balance of the Company's outstanding credit facility at that date. As of December 31, 1996 and 1995, respectively, the outstanding balance under the Company's bank credit facility was $70 million and $89 million. The Company's bank credit facility is an unsecured $200 million facility with a consortium of six banks. The amount of the borrowing base under the bank credit facility at any time is determined by the lenders with reference to the Company's proved reserves and the Company's projected cash requirements. With the issuance of the $150 million of senior notes discussed below, the current borrowing base is $75 million until May 1, 1997, at which time the borrowing base may be adjusted based on the lending banks' review of the Company's December 31, 1996 reserves and projected cash requirements. At the time of borrowing funds under the bank credit facility, interest begins to accrue on those funds, at the Company's election, either at the London interbank eurodollar rate (LIBOR) plus a spread ranging from 0.5 percent to 1.0 percent (depending on the ratio of the Company's outstanding indebtedness to its borrowing base) or at the U.S. prime rate of interest. The Company is required to pay interest on a quarterly basis until the entire outstanding balance matures on October 31, 2000. In February 1997, the Company completed a public offering of $150 million of 7.55% Senior Notes due 2007 ("Notes"). A portion of the net proceeds from the offering was used to repay in full the then outstanding balance of $85 million of the Company's existing line of credit. The Notes are senior unsecured obligations of the Company ranking equally in right of payment to all existing and future senior indebtedness of the Company. The Company will pay interest semi-annually on February 1 and August 1 of each year, beginning August 1, 1997. Capital Expenditures During 1996 the Company invested $234.7 million in oil and gas properties and other equipment, including acquisitions of oil and gas property working interests and related facilities principally in the Piceance and Uinta Basins, and exploration and development programs principally in the Anadarko, Arkoma, Piceance, Wind River and Uinta basins and in the Gulf of Mexico. These drilling programs were primarily to develop and extend producing fields. During the year the Company expanded its exploration programs with investments in leases in the Gulf of Mexico, offshore Louisiana and Texas, and international programs in Peru. The Company's capital expenditure budget for 1997 has been established at $279.9 million. This capital expenditure budget represents an increase of $45.2 million over 1996 capital expenditures. During 1997, the Company expects to spend approximately $113 million in exploring and developing its prospects in the Gulf of Mexico Region. Other significant budgeted exploratory and development capital expenditures include $92 million in the Rocky Mountain Region with emphasis in the Wind River and Piceance Basins, $46 million in the Mid-Continent Region, and $12 million in Peru. The Company's exploration and development programs are discussed in "Business and Properties" under Items 1 and 2 of this Form 10-K. On March 5, 1997, the Company was the high bidder and apparent winner on seven tracts offered in the Federal Offshore Lease Sale #166 for the Central Gulf of Mexico. All bids are subject to approval by the MMS. 20 If approved, the Company will have a 100 percent working interest in all of these blocks with net bonus obligations of approximately $14.9 million. Reserves and Pricing Proved reserves at year end 1996 were 814.3 billion cubic feet of natural gas equivalents (Bcfe), a 38 percent increase over December 31, 1995 proved reserves. Approximately 52 percent of the reserve additions were generated through exploration and development projects and 48 percent of the reserve additions were provided by acquisitions of properties. Proved reserves were reduced by production of approximately 72.4 Bcfe, sales of properties with reserves of 18.2 Bcfe, and downward revisions of previous estimates of 2.0 Bcfe. During 1996, as a result of its drilling and acquisition activities net of sales and revisions, the Company's reserve replacement was 408 percent of total production. As of year-end 1996, the standardized measure of discounted future net cash flows increased $454.9 million, or 147 percent, from 1995 primarily due to reserve additions and increases in oil and gas prices. Reserve extensions and discoveries added $230.8 million to the standardized measure, and purchases of proved reserves, net of sales, added $167.2 million. The changes in year end sales prices and production costs from 1995 to 1996 increased the standardized measure of discounted future net cash flows by $415.9 million. These additions were offset by a $110.3 million reduction due to reserves produced during the year and $249.8 million for additional income taxes being deducted in the computation. The Company's standardized measure of discounted future net cash flows is sensitive to gas prices in the current volatile commodities market. Oil and natural gas prices fluctuate throughout the year. Generally higher natural gas prices prevail during the winter months of December through February. As of December 31, 1996, the Company was receiving weighted average prices of $24.12 per barrel of oil and $3.46 per Mcf of gas. These prices are significantly above the average annual prices received during the past several years. During the first three months of 1997, prices have declined from the December 31, 1996 levels. A significant decline in prices would have a material effect on the standardized measure of discounted future net cash flows which, in turn, could impact the "ceiling test" for the Company's oil and gas properties accounted for under the full cost method. From time to time the Company uses swaps to hedge the sales price of its natural gas and oil. In a typical swap agreement, the Company and a counterparty will enter into an agreement whereby one party will pay a fixed price and the other will pay an index price on a specified volume of production during a specified period of time. Settlement is made by the parties for the difference between the two prices at approximately the same time as the physical transactions. The intent of hedging activities is to reduce the volatility associated with the sales prices of the Company's natural gas and oil production. Although hedging transactions associated with the Company's production minimize the Company's exposure to reductions in production revenue as a result of unfavorable price changes, these transactions also limit the Company's ability to benefit from favorable price changes. As of December 31, 1996, the Company held positions to hedge 8.8 Bcf of the Company's future natural gas production at an average price of $1.87 per Mcf. Subsequent to December 31, 1996, the Company hedged an additional 43.8 Bcf of natural gas production, over a five year period beginning March 1998, at a weighted average price of $1.74 per Mcf. These positions are more fully described in the notes to the financial statements. The Company currently has no oil swaps in place for 1997. The Company's drilling and acquisition activities have increased its reserve base and its productive capacity and, therefore, its potential cash flow. Lower gas prices may adversely affect cash flow. The Company intends to continue to acquire and develop oil and gas properties in its areas of activity as dictated by market conditions and financial ability. The Company retains flexibility to participate in oil and gas activities at a level that is supported by its cash flow and financial ability. Management believes that the Company's borrowing capacities and cash flow are sufficient to fund its currently anticipated activities. The Company intends to continue to use financial leverage to fund its operations as investment opportunities become available on terms that management believes warrant investment of the Company's capital resources. 21 RESULTS OF OPERATIONS In 1995, the Company consummated a merger of a wholly owned subsidiary of the Company with Plains by issuing 12.8 million shares of its common stock to the former Plains stockholders. As a result of this merger, Plains became a wholly owned subsidiary of the Company. In addition, in 1995, the Company changed its fiscal year end from September 30 to December 31. The merger was accounted for using the pooling of interests method. This method of accounting for mergers combines previously reported results as though the combination had occurred at the beginning of the periods being presented. Merger costs were expensed during 1995. The financial statements of the Company and Plains for 1994 through 1995 have been restated and adjusted for the merger with Plains and the change in fiscal year end. Due to this restatement, these financial statements are not comparable to the financial statements for the same periods as previously presented by the separate companies. 1996 vs. 1995 During 1996, the Company earned net income of $29.5 million ($1.02 per share) compared to a net loss of $2.2 million ($.09 per share) in 1995. The 1995 results included $14.2 million for merger and reorganization costs. Excluding the merger costs, the Company's net income after taxes in 1995 would have been $9.5 million ($.38 per share). Revenues increased 58 percent from 1995 to $202.6 million, and operating expenses increased 23 percent to $158.1 million. Production revenues increased 56 percent to $151.7 million, and trading revenues increased 64 percent to $46.9 million. Lease operating expenses increased $13.1 million, and depreciation, depletion and amortization increased $12.3 million. Production revenues increased $54.7 million due primarily to a 28 percent increase in gas production to 60.9 Bcf (166,400 Mcf per day) coupled with a 28 percent increase in the average gas sales price to $1.88 per Mcf. Oil production increased 12 percent to 1,913,000 barrels (5,226 barrels per day) while the average oil prices increased 24 percent to $19.51 per barrel. Gas production accounted for 84 percent of total production on an energy equivalent basis. The Hugoton Embayment and Wind River Basin properties accounted for 26 and 25 percent, respectively, of total gas production. The Powder River and Permian Basins accounted for 44 and 26 percent, respectively, of total oil production. Lease operating expenses of $47.6 million averaged $.66 per Mcfe ($3.95 per BOE) of production compared to $.60 per Mcfe ($3.58 per BOE) in 1995. Depreciation, depletion, and amortization increased $12.3 million primarily due to production increases. During 1996, depreciation, depletion, and amortization on oil and gas production was provided at an average rate of $.59 per Mcfe ($3.54 per BOE) compared to an average rate of $.55 per Mcfe ($3.28 per BOE) in 1995. The gross margin on trading activities increased to $2,826,000 from $943,000 in 1995. Gas trading volumes increased 35 percent to 29.9 Bcf in 1996. The Company enters into the hedging arrangements to minimize its exposure to price risks associated with commodities markets. Although hedging transactions associated with its production minimize the Company's exposure to losses as a result of unfavorable price changes, the transactions also limit the Company's ability to benefit from favorable price changes. During 1996, the Company hedged 14.1 Bcf (23 percent) of gas production for a net cost of $4.6 million and hedged 182 MBbls (10 percent) of oil production for a net cost of $0.3 million. General and administrative expenses of $16.9 million are 26 percent greater than the previous year. The 1996 amount is net of $4.0 million of operating fee recoveries compared to a $3.8 million recovery in 1995. General and administrative costs increased during 1996 due to the continued growth and expansion of the Company. Interest expense decreased from $4.6 million in 1995 to $3.7 million in 1996. This decline is attributed to a mid-year reduction of the Company's debt as a result of application of proceeds of the Company's June 1996 public equity offering to repay the outstanding balance of $110 million on the Company's bank credit facility at that time. 22 Income tax expenses increased to $15.0 million from $1.8 million in 1995. The Company's effective financial statement tax rate in 1996 was 33.6 percent, compared to a combined federal and state statutory rate of approximately 38 percent. The Company's results of operations depend primarily on the production of natural gas which accounted for over 80 percent of the Company's reserves and production during 1996. Therefore, the Company's future results will depend, among other things, on both the volume of natural gas production and the sales price for gas. The Company continues to explore for oil and gas to increase its production. The lack of predictability of both production volumes and sales prices may influence future operating results. 1995 vs. 1994 During 1995, the Company incurred a net loss of $2.2 million ($.09 per share) compared to net income of $11.3 million ($.46 per share) in 1994. The 1995 results include merger and reorganization costs of $14.2 million. Excluding the merger costs, the Company's net income after taxes for 1995 would have been $9.5 million ($.38 per share). Revenues increased 17 percent from 1994 to $128.0 million. Operating expenses, including $14.2 million of merger and reorganization costs, increased 38 percent to $128.4 million. Oil and gas production revenue increased 23 percent to $97.0 million. Lease operating expenses increased $6.3 million, and depreciation, depletion and amortization increased $10.7 million. Production revenues increased $18.2 million from 1994 primarily due to a 43 percent increase in gas production to 47.7 Bcf (130,700 Mcf per day). Oil production increased 32 percent to 1,702,000 barrels (4,660 barrels per day). Average gas sales prices decreased 20 percent to $1.47 per Mcf, while average oil prices increased 13 percent to $15.76 per barrel. Gas production accounted for 82 percent of total production on an energy equivalent basis. The Hugoton Embayment and Piceance Basin properties accounted for 37 and 14 percent, respectively, of total gas production. The Powder River and Permian Basins accounted for 43 and 32 percent, respectively, of total oil production. The decreased gas sales price was due to an overall deterioration in gas markets during most of the year. Lease operating expenses of $34.5 million in 1995 averaged $.60 per Mcfe ($3.58 per BOE) of production compared to $.69 per Mcfe ($4.13 per BOE) in 1994. Depreciation, depletion and amortization increased $10.7 million primarily due to production increases. During 1995, depreciation, depletion and amortization on oil and gas production was provided at an average rate of $.55 per Mcfe ($3.28 per BOE) compared to an average rate of $.52 per Mcfe ($3.14 per BOE) in 1994. The gross margin on trading activities was virtually unchanged from 1994 at $943,000. Gas trading volumes increased 26 percent to 22.2 Bcf in 1995. The Company hedged 11.0 Bcf (23 percent) of gas production for a net gain of $417,000. The hedging gain related to production is net of $1.2 million for an expense recorded in the fourth quarter due to a lack of correlation of the hedging instruments to the underlying commodity as of December 31, 1995. At the end of December 1995, the basis differential between the commodities markets and the market price of the Company's gas widened to historic levels. Because the increase in the commodities price was not accompanied by a similar increase in the market price of the Company's gas, the Company recorded an expense for the difference due to the inefficient hedge and the positions that did not qualify for hedge accounting treatment. General and administrative expenses of $13.4 million for 1995 are one percent greater than the previous year. The 1995 amount is net of $3.8 million of operating fee recoveries compared to a $3.4 million recovery in 1994. General and administrative expense in 1995 is generally a combination of the separate expenses for the Company and Plains, since the integration of the two entities did not occur until late in the year, and included costs for the Company to expand its business in existing and new activity areas. Interest expense increased 23 significantly from $942,000 in 1994 to $4.6 million in 1995 as the Company financed a portion of its growth with bank debt. The Company incurred a 1995 expense of $14.2 million to combine the Company and Plains and to integrate the operations of the two companies. The costs consist primarily of $7.4 million of investment banker and other professional fees to evaluate and consummate the merger and $5.6 million for employee termination and benefit costs. During 1995, the Company recorded a $1.8 million income tax expense even though it incurred a loss before taxes due to non-deductible merger costs. Excluding non-deductible merger costs, the Company would have had a $600,000 tax benefit. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA The Consolidated Financial Statements and schedules that constitute Item 8 are attached at the end of this Annual Report on Form 10-K. An index to these Consolidated Financial Statements and Schedules is also included in Item 14(a) of this Annual Report on Form 10-K. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTS ON ACCOUNTING AND FINANCIAL DISCLOSURES Not applicable. 24 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)(8)........ 68 Chief Executive Officer and Chairman of the 1993 Board C. Robert Buford 1983 (1)(2)(3)(4)........... 63 Director Derrill Cody (2)(3)(4).. 58 Director 1995 James M. Fitzgibbons 1987 (3)(4)(6).............. 62 Director Hennie L.J.M. Gieskes 1985 (1)(3)(4).............. 58 Director William W. Grant, III 1995 (3)(4)................. 64 Director J. Frank Keller (5)..... 53 Chief Financial Officer, Executive Vice 1983 President, Secretary, and a Director Paul M. Rady (2)(8)..... 43 President, Chief Operating Officer, and a 1994 Director A. Ralph Reed........... 59 Executive Vice President--Operations and a 1990 Director James T. Rodgers 1993 (3)(4)................. 62 Director Philippe S.E. Schreiber 1985 (2)(3)(4).............. 56 Director Harry S. Welch (3)(4)... 73 Director 1995 Joseph P. Barrett (7)... 43 Vice President--Land -- Peter A. Dea............ 43 Senior Vice President--Exploration -- Clifford S. Foss, Jr.... 49 Vice President and General Manager--Gulf of -- Mexico Region Bryan G. Hassler........ 38 Vice President--Marketing -- Robert W. Howard........ 42 Senior Vice President--Finance and Treasurer -- Eugene A. Lang, Jr...... 43 Senior Vice President and General Counsel -- Donald H. Stevens....... 44 Vice President--Corporate Relations and Capital -- Markets Maurice F. Storm........ 36 Vice President and General Manager--Mid- -- Continent Region
- -------- (1) Member of the Executive Committee of the Board of Directors. (2) Member of the Board Planning and Nominating Committee of the Board of Directors. (3) Member of the Audit Committee of the Board of Directors. (4) Member of the Compensation Committee of the Board of Directors. (5) Mr. Keller and Mr. Barrett are brothers-in-law. (6) Mr. Fitzgibbons served as a Director of the Company from July 1987 until October 1992. He was re-elected to the Board of Directors in January 1994. (7) Joseph P. Barrett is the son of William J. Barrett. (8) The Board of Directors has elected Paul M. Rady to serve as Chief Executive Officer effective as of July 1, 1997, at which time William J. Barrett will retire as Chief Executive Officer. Mr. Barrett's retirement plans include remaining as Chairman of the Board until January 1999. WILLIAM J. BARRETT has been Chief Executive Officer since December 1983 and Chairman of the Board of Directors of the Company since March 1994. Mr. Barrett was President of the Company from December 1983 through September 1994. From January 1979 to February 1982, Mr. Barrett was an independent oil and gas operator in the western United States in association with Aeon Energy, a partnership composed of four sole proprietorships. From 1971 to 1978, Mr. Barrett served as Vice President--Exploration and a director of Rainbow Resources, Inc., a publicly held independent oil and gas exploration company that merged with a subsidiary of the Williams Companies in 1978. Mr. Barrett served as President, Exploration Manager and 25 Director for B&C Exploration from 1969 until 1971 and was a chief geologist for Wolf Exploration Company, now known as Inexco Oil Co., from 1967 to 1969. He was an exploration geologist with Pan-American Petroleum Corporation from 1963 to 1966 and worked as an exploration geologist, a petroleum geologist and a stratigrapher for El Paso Natural Gas Co. at various times from 1958 to 1963. Mr. Barrett's retirement plans include remaining as Chairman of the Board until January 1999 and remaining as Chief Executive Officer until July 1, 1997. C. ROBERT BUFORD has been a director of the Company since December 1983 and served as Chairman of the Board of Directors from December 1983 through March 1994. Mr. Buford has been President, Chairman of the Board and controlling shareholder of Zenith Drilling Corporation ("Zenith"), Wichita, Kansas, since February 1966. Zenith is engaged in the oil and gas business and owns approximately 3% of the Company's common stock. Since 1993, Mr. Buford has served as a director of Encore Energy, Inc., a wholly owned subsidiary of Zenith engaged in the marketing of natural gas. Mr. Buford is also a member of the Board of Directors of Intrust Financial Corporation, a bank holding company. Mr. Buford served as a director of Lonestar Steakhouse & Saloon, Inc from March 1992 until his resignation on January 3, 1997. DERRILL CODY has been a director of the Company since July 1995. Mr. Cody was a director of Plains from May 1990 through July 1995. Since January 1990, Mr. Cody has been an attorney in private practice in Oklahoma City, Oklahoma. From 1986 to 1990, he was Executive Vice President of Texas Eastern Corporation, and from 1987 to 1990 he was the Chief Executive Officer of Texas Eastern Pipeline Company. He has been a director of the general partner of TEPPCO Partners, L.P. since January 1990. JAMES M. FITZGIBBONS has been a director of the Company since January 1994, and previously served as a director of the Company from July 1987 until October 1992. Since October 1990, Mr. Fitzgibbons has been Chairman and Chief Executive Officer of Fieldcrest Cannon, Inc., a manufacturer of home furnishing textiles. From January 1986 until October 1990, Mr. Fitzgibbons was President of Amoskeag Company in Boston, Massachusetts. Prior to 1986, he was President of Howes Leather Company, a producer of leather. Mr. Fitzgibbons is also member of the Board Of Directors of Lumber Mutual Insurance Company, American Textile Manufacturers Institute and a Trustee of Dreyfus Laurel Funds, a series of mutual funds. HENNIE L.J.M. GIESKES has been a director of the Company since November 1985. Mr. Gieskes is the Managing Director of Spaarne Compagnie N.V., a Netherlands company engaged in the investment business. From before 1976 until December 1990, Mr. Gieskes was a Managing Director of Vitol Beheer B.V., a Netherlands trading company engaged primarily in energy-related commodities. WILLIAM W. GRANT, III has been a director of the Company since July 1995. Mr. Grant was a director of Plains from May 1987 through July 1995. He has been an advisory director of Colorado National Bankshares, Inc. and Colorado National Bank since 1993. He was a director of Colorado National Bankshares, Inc. from 1982 to 1993 and the Chairman of the Board of Colorado National Bank from 1986 to 1993. He served as the Chairman of the Board of Colorado Capital Advisors from 1989 through 1994. J. FRANK KELLER has been Chief Financial Officer since July 1995 and an Executive Vice President, the Secretary and a director of the Company since December 1983. Mr. Keller was the President and a co-founder of Myriam Corp., an architectural design and real estate development firm beginning in 1976, until it was reorganized as Barrett Energy in February 1982. PAUL M. RADY has been President, Chief Operating Officer, and a director of the Company since September 1994. The Board of Directors has elected Mr. Rady to serve as Chief Executive Officer effective as of July 1, 1997, at which time William J. Barrett will retire as Chief Executive Officer and remain as Chairman of the Board. Prior to September 1994, Mr. Rady served as Executive Vice President--Exploration of the Company beginning February 1993. From August 1990 until July 1992, Mr. Rady served as Chief Geologist for the Company, and from July 1992 until January 1993 he served as Exploration Manager for the Company. From July 1980 until August 1990, Mr. Rady served in various positions with the Denver, Colorado regional office of Amoco Production Company ("Amoco"), the exploration and production subsidiary of Amoco Corporation. While with Amoco, Mr. Rady's areas of responsibility included the Rocky Mountain Basins, Utah-Wyoming Overthrust Belt, offshore Alaska, Oklahoma, particularly with respect to the Arkoma Basin, and the New Ventures Group, which concentrated on the western United States. 26 A. RALPH REED has been an Executive Vice President of the Company since November 1989 and a director since September 1990. From 1986 to 1989, Mr. Reed was an independent oil and gas operator in the Mid- Continent region of the United States, including the period from January 1988 to November 1989 when he acted as a consultant to Zenith. From 1982 to 1986, Mr. Reed was President and Chief Executive Officer of Cotton Petroleum Corporation ("Cotton"), a wholly owned exploration and production subsidiary of United Energy Resources, Inc. Prior to joining Cotton in 1980, Mr. Reed was employed by Amoco from 1962, holding various positions including Manager of International Production, Division Production Manager and Division Engineer. JAMES T. RODGERS has been a director of the Company since October 1993. Mr. Rodgers served as the President, Chief Operating Officer and a director of Anadarko Petroleum Corporation ("Anadarko") from 1986 through 1992. Anadarko is a Houston-based oil and gas exploration and production company. Prior to 1986, Mr. Rodgers was employed in other capacities by Anadarko and Amoco. Mr. Rodgers taught Petroleum Engineering at the University of Texas in Austin in 1958 and at Texas Tech University in Lubbock from 1958 to 1961. Mr. Rodgers currently serves as a Director of Louis Dreyfus Natural Gas Corporation and as an advisor to Ural Petroleum Corporation, a privately held exploration and production company operating exclusively in the former Soviet Union. PHILIPPE S.E. SCHREIBER has been a director of the Company since November 1985. Mr. Schreiber is an independent lawyer and business consultant who also is of counsel to the law firm of Walter, Conston, Alexander & Green, P.C. in New York, New York. Mr. Schreiber has been affiliated with that law firm as counsel or partner since August 1985. From 1988 to mid-1992, he also was the Chairman of the Board and a principal shareholder of HSE, Inc., d/b/a Manhattan Kids Limited, a privately owned corporation involved in catalogue sales of American made children's clothing in Europe. HARRY S. WELCH has been a director of the Company since July 1995. Mr. Welch was a director of Plains from May 1986 to July 1995. Since August 1989, he has been an attorney in private practice in Houston, Texas. He served as Vice President and General Counsel of Texas Eastern Corporation from 1988 to July 1989. JOSEPH P. BARRETT has been a Vice President since March 1995 and has been with the Company in various positions in the Land Department since 1982. PETER A. DEA has been Senior Vice President--Exploration of the Company since June 1996. Mr. Dea served as Exploration Manager beginning August 1995. Mr. Dea served as Chief Geologist from January 1995 to August 1995 and as Senior Geologist from February 1994 to January 1995. Mr. Dea served as President of Nautilus Oil and Gas Company in Denver, Colorado from 1992 through 1993. From 1982 until 1991, Mr. Dea served in various positions with Exxon Company USA as a Geologist in the Production Department in Corpus Christi, Texas and as a Senior Geologist and Supervisor in the Exploration Department in Denver, Colorado. While with Exxon, Mr. Dea's areas of responsibility included the Rocky Mountain Basins and South Texas Gulf Coast and new ventures in the Special Trades Unit. Mr. Dea served as adjunct Professor of Geology at Western State College, Gunnison, Colorado in the spring semesters of 1980 and 1982. CLIFFORD S. FOSS, JR. has been Vice President and General Manager of the Gulf of Mexico Region for the Company since June of 1996 and General Manager of the Gulf of Mexico Region for the Company since January 1996. Prior to joining the Company, Mr. Foss served from January 1973 to 1996 in various positions with Cockrell Oil Corporation as Geologist, District Geologist, Exploration Manager and Vice President of Exploration and Exploitation. Mr. Foss's primary areas of responsibility at Cockrell Oil Corporation included the Gulf Coast and Gulf of Mexico. Prior to January 1973, Mr. Foss served as an exploration geologist for Cities Services Oil Company in its Gulf of Mexico Division. BRYAN G. HASSLER has been Vice-President--Marketing of the Company since December 1996 and has been with the Company as Director of Marketing since August 1994. Prior to joining the Company, Mr. Hassler held various positions with Questar Corporation's exploration and production, pipeline and marketing groups. 27 ROBERT W. HOWARD has been Senior Vice President of the Company since March 1992. Mr. Howard served as the Executive Vice President--Finance from December 1989 until March 1992 and served as Vice President-- Finance of the Company from December 1983 until December 1989. Mr. Howard has been the Treasurer of the Company since March 1986. During 1982, Mr. Howard was a Manager/Accountant with Weiss & Co., a certified public accounting firm. EUGENE A. LANG, JR. has been Senior Vice President and General Counsel of the Company since September 1995. Mr. Lang served as Senior Vice President, General Counsel and Secretary of Plains from May 1994 to July 1995, and from October 1990 to May 1994 he served as Vice President, General Counsel and Secretary of Plains. From 1986 to 1990 he was an associate with the Houston, Texas law firm of Vinson & Elkins. From 1984 to 1986, he was General Attorney and Assistant Secretary of K N. From 1978 to 1984, he was an attorney for K N. DONALD H. STEVENS has been the Vice President--Corporate Relations and Capital Markets for the Company since August 1992. From July 1989 until August 1992, Mr. Stevens served as Manager of Corporate and Tax Planning for Kennecott Corporation, a mining company. From May 1986 until September 1989, Mr. Stevens served as Corporate Planning Analyst in Corporate Acquisition and Divestitures for BP America, Inc., formerly The Standard Oil Company. Prior to May 1986, Mr. Stevens served in various finance, tax and analyst positions with Seco Energy Corporation and Gulf Oil Corporation, both of which are oil and gas companies. MAURICE F. STORM has been Vice President and General Manager of the Company's Mid-Continent Region since July 1996. From October 1991 to July 1996 Mr. Storm was retained by the Company as a consultant to develop drilling opportunities in the Anadarko and Arkoma Basins. From September 1984 through October 1991 Mr. Storm worked for other independent exploration and production companies in various exploration geologist and management positions. SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE Section 16(a) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), requires the Company's directors, executive officers and holders of more than 10% of the Company's common stock to file with the Securities and Exchange Commission initial reports of ownership and reports of changes in ownership of common stock and other equity securities of the Company. The Company believes that during the fiscal year ended December 31, 1996, its officers, directors and holders of more than 10% of the Company's common stock complied with all Section 16(a) filing requirements, with the following exception: Donald H. Stevens, an executive officer of the Company, reported on October 25, 1996 on a Form 4, the sale on September 24, 1996 of 3,750 shares. In making these statements, the Company has relied upon the written representations of its directors and officers. 28 ITEM 11. EXECUTIVE COMPENSATION SUMMARY COMPENSATION TABLE The following table sets forth, in summary form, the compensation received during each of the Company's last three years by the Chief Executive Officer of the Company and by the four other most highly compensated executive officers whose compensation exceeded $100,000 during the year ended December 31, 1996. Beginning with the year ended December 31, 1995, the Company changed its fiscal year end from September 30 to December 31. The figures in the following table are for each of the one year periods ended December 31, 1996, 1995, and 1994: SUMMARY COMPENSATION TABLE
LONG TERM COMPENSATION ----------------------------------- AWARDS PAYOUTS ----------------------- -------- RESTRICTED SECURITIES OTHER ANNUAL STOCK UNDERLYING LTIP ALL OTHER NAME AND PRINCIPAL FISCAL COMPENSATION AWARD(S) OPTIONS/SARS PAYOUTS COMPENSATION POSITION YEAR SALARY ($) BONUS $(/1/) ($)(/2/) ($)(/3/) ($)(/4/) (#)(/5/) ($)(/6/) ------------------ ------ ---------- ------------ ------------ ---------- ------------ -------- ------------ William J. Barrett...... 1996 $255,417 $150,000 -0- -0- 100,000 -0- $7,913 Chief Executive 1995 $200,000 -0- -0- -0- -0- -0- $4,680 Officer, and Chairman of the Board 1994 $200,000 $ 40,000 -0- -0- 100,000 -0- $4,560 Paul M. Rady............ 1996 $206,667 $ 63,000 -0- -0- 52,000 -0- $8,138 President, Chief 1995 $175,000 -0- -0- -0- -0- Operating -0- $4,680 Officer, and a director 1994 $139,583 $ 30,000 -0- -0- 70,000 -0- $4,247 A. Ralph Reed........... 1996 $207,917 $ 54,000 -0- -0- 40,000 -0- $7,988 Executive Vice 1995 $200,000 -0- -0- -0- -0- -0- $4,680 President-- Operations, and a 1994 $164,583 $ 30,000 -0- -0- 100,000 -0- $4,705 director J. Frank Keller......... 1996 $155,938 $ 40,000 -0- -0- 19,200 -0- $8,222 Executive Vice 1995 $150,000 -0- -0- -0- -0- -0- $4,560 President, Chief Financial 1994 $128,750 $ 25,000 -0- -0- 55,000 -0- $3,922 Officer, Secretary and a director Eugene A. Lang, Jr., ... 1996 $141,242 $ 25,000 -0- -0- 9,600 -0- $7,432 Senior Vice President 1995 $138,422 $ 8,000 -0- -0- -0- -0- $1,500 and General 1994 $127,560 -0- -0- -0- 25,460(/8/) -0- $1,500 Counsel(/7/)
- -------- (1) The dollar value of bonus (cash and non-cash) paid during the year indicated. In March 1997, cash bonuses were determined by the Compensation Committee and paid by the Company based upon the Company's performance in 1996. These bonuses included $250,000 paid to Mr. Barrett, $160,000 paid to Mr. Rady, $120,000 paid to Mr. Reed, $90,000 paid to Mr. Keller, and $65,000 paid to Mr. Lang. (2) During the period covered by the Table, the Company did not pay any other annual compensation not properly categorized as salary or bonus, including perquisites and other personal benefits, securities or property. (3) During the period covered by the Table, the Company did not make any award of restricted stock, including share units. (4) The sum of the number of shares of common stock to be received upon the exercise of all stock options granted. See "Option Grants Table". (5) Except for stock option plans, the Company does not have in effect any plan that is intended to serve as incentive for performance to occur over a period longer than one fiscal year. (6) Represents the Company's matching contribution under the Company's 401(k) Plan for each named executive officer. The amounts for 1994 and 1995 for Mr. Lang represent matching contributions under the Plains 401(k) Plan. (7) Mr. Lang's compensation was paid by Plains during the period from January 1, 1994 through July 18, 1995 when Plains merged with a subsidiary of the Company. (8) Consists of options to purchase 25,460 shares of common stock of Plains that became options to purchase 33,097 shares of common stock of the Company upon the merger of Plains with a subsidiary of the Company. 29 OPTION GRANTS IN LAST FISCAL YEAR No stock appreciation rights were granted to any executive officers or employees in the year ended December 31, 1996. The following table provides information on stock option grants in the year ended December 31, 1996 to the named executive officers. OPTION GRANTS IN LAST FISCAL YEAR
INDIVIDUAL GRANTS ---------------------------------------------- NUMBER OF % OF TOTAL SECURITIES OPTIONS UNDERLYING GRANTED TO OPTIONS EMPLOYEES EXERCISE POTENTIAL REALIZABLE VALUE GRANTED IN FISCAL PRICE EXPIRATION --------------------------- NAME (#) YEAR ($/SHARE) DATE 5% 10% ---- ---------- ---------- --------- ------------- ------------ -------------- William J. Barrett...... 100,000(1) 14.13% $23.125 March 5, 2003 $ 942,119 $ 2,194,882 Paul M. Rady............ 52,000(2) 7.35% $23.125 March 5, 2003 $ 489,901 $ 1,141,338 A. Ralph Reed........... 40,000(2) 5.65% $23.125 March 5, 2003 $ 376,847 $ 877,952 J. Frank Keller......... 19,200(2) 2.71% $23.125 March 5, 2003 $ 180,886 $ 421,416 Eugene A. Lang, Jr...... 9,600(2) 1.36% $23.125 March 5, 2003 $ 90,443 $ 210,708
- -------- (1) Half of these option shares became exercisable on March 5, 1997, and the balance of these option shares are first exercisable on March 5, 1998. (2) One-fourth of these option shares became exercisable on March 5, 1997, and an additional one-fourth of these option shares are first exercisable on each of March 5, 1998, March 5, 1999 and March 5, 2000. AGGREGATED OPTION EXERCISES AND FISCAL YEAR-END OPTION VALUE TABLE The following table sets forth information concerning each exercise of stock options during the fiscal year ended December 31, 1996 by the Company's Chief Executive Officer and the four other most highly compensated executive officers of the Company whose compensation exceeded $100,000 during the year ended December 31, 1996 and the fiscal year-end value of unexercised options held by these persons: AGGREGATED OPTION EXERCISES FOR FISCAL YEAR ENDED DECEMBER 31, 1996 AND YEAR-END OPTION VALUES (1)
NUMBER OF SECURITIES UNDERLYING UNEXERCISED VALUE OF UNEXERCISABLE OPTIONS AT FISCAL YEAR- IN-THE-MONEY OPTIONS AT SHARES END(#)(4) FISCAL YEAR-END($)(5) ACQUIRED ON VALUE REALIZED ------------------------- ------------------------- NAME EXERCISE(2) ($)(3) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE ---- ----------- -------------- ----------- ------------- ----------- ------------- William J. Barrett..... 20,000 $230,000 5,000 150,000 $125,000 $3,370,000 Chief Executive Officer, and Chairman of the Board Paul M. Rady........... -0- -0- 35,000 87,000 $951,500 $1,965,500 President, Chief Operating Officer, and a director A. Ralph Reed.......... 14,952 $347,709 35,048 90,000 $904,454 $2,121,800 Executive Vice President--Operations and a director J. Frank Keller........ -0- -0- 27,500 46,700 $760,600 $1,135,000 Executive Vice President, Chief Financial Officer, Secretary, and a director Eugene A. Lang, Jr. ... 3,750 $ 45,825 40,860 9,600 $981,347 $ 187,200 Senior Vice President and General Counsel
30 - -------- (1) No stock appreciation rights are held by any of the named executive officers. (2) The number of shares received upon exercise of options during the fiscal year ended December 31, 1996. (3) With respect to options exercised during the Company's fiscal year ended December 31, 1996, the dollar value of the difference between the option exercise price and the market value of the option shares purchased on the date of the exercise of the options. (4) The total number of unexercised options held as of December 31, 1996, separated between those options that were exercisable and those options that were not exercisable. (5) For all unexercised options held as of December 31, 1996, the aggregate dollar value of the excess of the market value of the stock underlying those options over the exercise price of those unexercised options. These values are shown separately for those options that were exercisable, and those options that were not yet exercisable, on December 31, 1996. As required, the price used to calculate these figures was the closing sale price of the common stock at year's end, which was $42.625 per share on December 31, 1996. On March 20, 1997, the closing sale price was $34.00 per share. EMPLOYEE RETIREMENT PLANS, LONG-TERM INCENTIVE PLANS, AND PENSION PLANS The Company has an employee retirement plan (the "401(k) Plan") that qualifies under Section 401(k) of the Internal Revenue Code of 1986, as amended. Employees of the Company are entitled to contribute to the 401(k) Plan up to 15 percent of their respective salaries. For each pay period through March 31, 1996, the Company contributed on behalf of each employee 50 percent of the contribution made by that employee, up to a maximum contribution by the Company of three percent of that employees gross salary for that pay period. Effective April 1, 1996, the Company's matching contribution increased to 100 percent of each participating employee's contribution, up to a maximum of six percent of base salary, with one-half of the match paid in cash and one-half of the match paid in the Company's common stock. The Company's match is subject to a vesting schedule. Benefits payable to employees upon retirement are based on the contributions made by the employee under the 401(k) Plan, the Company's matching contributions, and the performance of the 401(k) Plans investments. Therefore, the Company cannot estimate the annual benefits that will be payable to participants in the 401(k) Plan upon retirement at normal retirement age. Excluding the 401(k) Plan, the Company has no defined benefit or actuarial or pension plans or other retirement plans. Excluding the Company's stock option plans, the Company has no long-term incentive plan to serve as incentive for performance to occur over a period longer than one fiscal year. COMPENSATION OF DIRECTORS Standard Arrangements. Pursuant to the Company's standard arrangement for compensating directors, no compensation for serving as a director is paid to directors who also are employees of the Company, and those directors who are not also employees of the Company ("Outside Directors") receive an annual retainer of $20,000 paid in equal quarterly installments. In addition, for each Board of Directors or committee meeting attended, each Outside Director receives a $750 meeting attendance fee. Effective March 5, 1996, each Outside Director receives $200 for each telephone meeting lasting more than 15 minutes. Effective April 1, 1997, the meeting attendance fee was increased to $1,000, and the fee for telephone meetings lasting more than 15 minutes was increased to $300. Also effective April 1, 1997, the Chairman of the Compensation and Audit Committees will receive a $1,500 meeting attendance fee for each committee meeting. For each Board of Directors or committee meeting attended, each Outside Director will have options to purchase 500 shares of common stock become exercisable. Although these options become exercisable only at the rate of 500 for each meeting attended, each director will be granted options to purchase 10,000 shares at the time the person initially becomes a director. (The Board of Directors has approved, and recommended for stockholder approval, amendments to the Non-Discretionary Stock Option Plan. If the stockholders approve the proposed amendments to the Non-Discretionary Stock Option Plan, options thereunder will become exercisable at the rate of 1,000 shares for each meeting attended.) Any options that have not become exercisable at the time of termination of a director's service will expire at that time. At such time that the options to purchase all 10,000 shares have become exercisable, 31 options to purchase an additional 10,000 shares will be granted to the director and will be subject to the restrictions on exercise as the previously received options. The options are granted to the Outside Directors pursuant to the Company's Non-Discretionary Stock Option Plan, and their exercise price is equal to the closing sales price for the Company's common stock on the date of grant. The options expire upon the later to occur of five years after the date of grant and two years after the date those options first became exercisable. Other Arrangements. During the fiscal year ended December 31, 1996, no compensation was paid to directors of the Company other than pursuant to the standard compensation arrangements described in the previous section. EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT AND CHANGE-IN-CONTROL ARRANGEMENTS The Company does not have any written employment contracts with respect to any of the executive officers named in the Summary Compensation Table, except for Mr. Lang. Mr. Lang is a party to an agreement with Plains to which the Company became bound as a result of the Barrett-Plains merger. That agreement provides, among other things, that if, within three years after a "change in control" (as defined in the agreement), Mr. Lang's employment is involuntarily terminated or is terminated by Mr. Lang for "Good Reason", Mr. Lang is to be paid a cash amount equal to (a) two times of the higher of (i) his then annual compensation (including salary, bonuses and incentive compensation) or (ii) the highest annual compensation (including salary, bonuses and incentive compensation) paid or payable during any of the three calendar years ending with the year of his termination, plus (b) an amount equal to any excise taxes payable by Mr. Lang with respect to these amounts and any excise or income taxes payable by Mr. Lang as a result of this reimbursement of excise taxes. "Good Reason" is defined as a reduction in Mr. Lang's compensation or employment responsibilities, a required relocation outside the greater Denver, Colorado area or, generally, any conduct that renders Mr. Lang unable to discharge his employment duties effectively. This agreement terminates on July 18, 1998. The Company has no other compensatory plan or arrangement that results or will result from the resignation, retirement, or any other termination of the employment with the Company and its subsidiaries of the executive officers named in the Summary Compensation Table or from a change- in-control of the Company or a change in such an executive officers responsibilities following a change-in-control, except that (i) in January 1994, the Board of Directors approved a resolution allowing all options outstanding under the Companys 1990 Stock Option Plan to become exercisable if an announcement is made concerning a business combination with the Company; and (ii) in September 1994, the Compensation Committee committed to Mr. Reed that all stock options that had been granted to him as of September 10, 1994 would become exercisable upon termination of his employment provided that he remains in the employment of the Company continuously until September 10, 1997, and further provided that the Compensation Committee, or its successor, determines as of the date of his termination that his employment performance has satisfied the Companys employment standards for executive officers. COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION During the year ended December 31, 1996, each of C. Robert Buford, Derrill Cody, James M. Fitzgibbons, Hennie L.J.M. Gieskes, James T. Rodgers, Philippe S.E. Schreiber, and Harry S. Welch served as members of the Compensation Committee of the Board of Directors. Mr. Schreiber served as the President of Excel Energy Corporation ("Excel") prior to the 1985 merger of Excel with and into the Company, and Mr. Gieskes served as Chairman of the Board of Excel at the time of the merger of Excel with and into the Company. No other person who served as a member of the Compensation Committee during the year ended December 31, 1996 was, during that year, an officer or employee of the Company or of any of its subsidiaries, or was formerly an officer of the Company or of any of its subsidiaries. For a description of transactions involving Mr. Buford and the Company, please see "Item 13. Certain Relationships and Related Transactions". 32 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The following table summarizes certain information as of March 20, 1997 with respect to the ownership by each director, by each executive officer named in the "Executive Compensation" section above, by all executive officers and directors as a group, and by each other person known by the Company to be the beneficial owner of more than five percent of the common stock:
NAME OF AMOUNT/NATURE OF PERCENT OF CLASS BENEFICIAL OWNER BENEFICIAL OWNERSHIP BENEFICIALLY OWNED ---------------- -------------------- ------------------ William J. Barrett................ 410,211 Shares(1) 1.3% C. Robert Buford.................. 653,366 Shares(2) 2.1% Derrill Cody...................... 13,560 Shares(3) * James M. Fitzgibbons.............. 11,500 Shares(3) * Hennie L.J.M. Gieskes............. 899,214 Shares(3) 2.9% William W. Grant, III............. 26,150 Shares(3) * J. Frank Keller................... 82,658 Shares(3) * Eugene A. Lang, Jr................ 49,873 Shares(3) * Paul M. Rady...................... 87,152 Shares(3) * A. Ralph Reed..................... 91,158 Shares(4) * James T. Rodgers.................. 12,000 Shares(3) * Philippe S.E. Schreiber........... 20,507 Shares(3) * Harry S. Welch.................... 19,800 Shares(3) * All Directors and Executive Officers as a Group (20 persons)......................... 2,476,119 Shares(5) 7.8% Fidelity Management and Research Corporation...................... 3,163,660 Shares(6) 10.1% 82 Devonshire Street Boston, MA 02109 State Farm Mutual Automobile Insurance Company and affiliates.. 2,278,233 Shares(6)(7) 7.3% One State Farm Plaza Bloomington, IL 61710
- -------- * Less than 1% of the common stock outstanding. (1) The number of shares indicated includes 36,292 shares owned by Mr. Barrett's wife, 230,000 shares owned by the Barrett Family L.L.L.P., a Colorado limited liability limited partnership for which Mr. Barrett and his wife are general partners and owners of an aggregate of 62.92294 percent of the partnership interests, and 75,000 shares underlying options that currently are exercisable or become exercisable within the next 60 days. Pursuant to Rule 16a-1(a)(4) under the Securities Exchange Act of 1934 (the "1934 Act"), Mr. Barrett disclaims ownership of all but 144,723 shares held by the Barrett Family L.L.L.P., which constitutes Mr. and Mrs. Barrett's proportionate share of the shares held by the Barrett Family L.L.L.P. (2) C. Robert Buford is considered a beneficial owner of the 598,210 shares of which Zenith is the record owner. Mr. Buford owns approximately 89 percent of the outstanding common stock of Zenith. The number of shares of the Company's stock indicated for Mr. Buford also includes 10,000 shares that are owned by Aguilla Corporation, which is owned by Mr. Buford's wife and adult children. Mr. Buford disclaims beneficial ownership of the shares held by Aguilla Corporation pursuant to Rule 16a-1(a)(4) under the 1934 Act. The number of shares indicated also includes 11,500 shares underlying stock options are currently exercisable or that become exercisable within the next 60 days. (3) The number of shares indicated consists of or includes the following number of shares underlying options that currently are exercisable or that become exercisable within the next 60 days that are held by each of the following persons: Derrill Cody, 13,300; James M. Fitzgibbons,9,500; Hennie L.J.M. Gieskes, 10,000; William W. Grant, III, 16,400; J. Frank Keller, 40,900; Eugene A. Lang, Jr., 43,259; Paul M. Rady, 57,000; James T. Rodgers, 12,000; Philippe S.E. Schreiber, 10,500; and Harry S. Welch, 17,200. (4) The number of shares indicated includes 10,150 shares owned by Mary C. Reed, Mr. Reed's wife and 55,848 shares underlying options that currently are exercisable or that become exercisable within the next 60 days. 33 (5) The number of shares indicated includes the shares owned by Zenith that are beneficially owned by Mr. Buford as described in note (2) and the aggregate of 372,407 shares underlying the options described in notes (1), (2), (3) and (4), an aggregate of 25,170 shares owned by seven executive officers not named in the above table, and an aggregate of 73,800 shares underlying options that currently are exercisable or that are exercisable within 60 days that are held by those seven executive officers. (6) Based on information included in a Schedule 13G filed with the Securities and Exchange Commission by the named stockholders and from information obtained from other sources. (7) The number of shares indicated includes the shares owned by entities affiliated with State Farm Mutual Automobile Insurance Company ("SFMAI"). Those entities and SFMAI may be deemed to constitute a "group" with regard to the ownership of shares reported on a Schedule 13G under the Securities Exchange Act of 1934, as amended. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS On April 10, 1996, the Company acquired all the Piceance Basin oil and gas interests of Zenith for $2.7 million, and the Company, through a merger of GVC into a subsidiary company, acquired all the stock of GVC in exchange for 350,000 shares of the Company's common stock. These transactions were effective March 1, 1996. Pursuant to the respective agreements with Zenith and GVC, Zenith and the shareholders of GVC are responsible for liabilities that accrue on or before March 1, 1996 and the Company is responsible for liabilities accruing after March 1, 1996. The terms of these transactions were negotiated with Zenith and GVC by a Special Committee of the Board of Directors of the Company consisting of William W. Grant, III, James T. Rodgers, Philippe S.E. Schreiber, and Harry S. Welch, each of whom is an outside director. The Company obtained an opinion from an investment banking firm that the terms of these transactions were fair to the Company. Prior to the Company's acquisition of these interests as described above, Zenith owned a working interest in many of the leases for which the Company is the operator. For the period from January 1, 1996 through the effective date of the acquisition, Zenith paid to the Company, as operator, approximately $77,000 as Zenith's portion of the lease operating expenses and development costs for those leases. Also as a result of its working interest, which ranged from three to 50 percent in leases for which the Company is the operator, Zenith received approximately $448,000 as its share of revenues. All terms and arrangements between Zenith and the Company with respect to these working interests are the same as those between the Company and the other working interest owners in the leases. Zenith is 89 percent owned by Mr. Buford. Mr. Buford also was a director of GVC which owned a 10.4 percent interest in the pipeline gathering system and related facilities on the Company's Grand Valley Gathering System. Until acquired by the Company, as described above, ten percent of GVC was owned by Mr. Buford, and 90 percent of GVC was owned by Mr. Buford's three adult children. From January 1, 1996, the effective date of the acquisition, GVC's proportionate share of the pipeline gathering system's expenses, not including depreciation, was approximately $33,000, and its share of the pipeline gathering system's revenues was approximately $101,000. All terms and arrangements between GVC and the Company with respect to this gathering system are the same as those between the Company and the other owners of the gathering system. 34 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, 1996 and 1995............. F-2 Consolidated Statements of Income for each of the three years in the period ended December 31, 1996....................................... F-3 Consolidated Statements of Stockholders' Equity for each of the three years in the period ended December 31, 1996.......................... F-4 Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 1996................................... F-5 Notes to the Consolidated Financial Statements........................ F-6 Supplemental Oil And Gas Information.................................. F-21
All other schedules are omitted because the required information is not present in amounts sufficient to require submission of the schedule or because the information required is included in the Consolidated Financial Statements and Notes thereto. (a)(3) Exhibits See "EXHIBIT INDEX" on page 36. (b) Reports On Form 8-K. No Current Reports on Form 8-K were filed during the fourth quarter of the year ended December 31, 1996. During the period from January 1, 1997 through March 20, 1997, the Company filed three Current Reports on Form 8-K reporting events that occurred on January 8, 1997, February 7, 1997, and February 13, 1997, respectively. 35 EXHIBIT INDEX
EXHIBIT ------- 2.1 Agreement And Plan of Merger, dated as of May 2, 1995, among Barrett Resources Corporation ("Barrett" or "Registrant"), Barrett Energy Inc. (formerly known as Vanilla Corporation), and Plains Petroleum Company ("Plains") is incorporated by reference from Annex I to the Joint Proxy Statement/Prospectus of Barrett and Plains dated June 13, 1995. 3.1 Restated Certificate Of Incorporation of Barrett Resources Corporation, a Delaware corporation, is incorporated herein by reference from Exhibit 3.2 of Registrant's Registration Statement on Form S-4 dated June 9, 1995. 3.6 Bylaws of Barrett, as amended, are incorporated herein by reference from Exhibit 3.3 of Registrant's Registration Statement on Form S-4 dated June 9, 1995. 10.1 Non-Qualified Stock Option Plan Of Barrett Resources Corporation is incorporated by reference from Registrant's Registration Statement on Form S-8 dated November 15, 1989. 10.2 Registrant's 1990 Stock Option Plan, as amended, is incorporated by reference from the Registrant's Registration Statement on Form S-8 dated March 15, 1995. 10.3 Registrant's Non-Discretionary Stock Option Plan is incorporated by reference from Registrant's Annual Report on Form 10-K for the year ended September 30, 1991. 10.4 1994 Stock Option Plan, as amended, is incorporated by reference from the Registrant's Registration Statement on Form S-8 dated March 15, 1995. 10.5A Gas Purchase Contract, No. P-1090, dated April 20, 1984, as amended, between Plains and KN Energy, Inc. is incorporated by reference from Plains Petroleum Company's Registration Statement on Form 10 dated August 21, 1985. 10.5B Letter Agreement dated December 19, 1996, amending the Gas Purchase Contract, No. P-1090, dated April 20, 1984, between Plains and KN Energy, Inc. 10.6A Revolving Credit Agreement dated as of July 19, 1995 among Barrett and Texas Commerce Bank National Association, as Agent, and Texas Commerce Bank National Association, Nations Bank of Texas, N.A., Bank of Montreal, Houston Agency, Colorado National Bank, and The First National Bank of Boston, as the "Banks" is incorporated by reference from Exhibit 10.6 to Barrett's Annual Report on Form 10-K for the year ended December 31, 1996. 10.6B First Amendment to Revolving Credit Agreement dated October 31, 1996 between and among Barrett, Agent and the Banks is incorporated by reference from Exhibit 10.1 to Amendment No. 2 to Barrett's Registration Statement on Form S-3 (File No. 333 -19363) dated February 10, 1997. 10.6C Second Amendment to Revolving Credit Agreement dated February 10, 1997 between and among Barrett, the Agent, and the Banks is incorporated by reference from Exhibit 10.2 to Amendment No. 2 to Barrett's Registration Statement on Form S-3 (File No. 333 -19363) dated February 10, 1997. 21 List of Subsidiaries. 23 Consent of Arthur Andersen LLP. 27 Financial Data Schedule.
36 REPORT OF ARTHUR ANDERSEN LLP INDEPENDENT PUBLIC ACCOUNTANTS The Board of Directors Barrett Resources Corporation Denver, Colorado 80202 We have audited the accompanying consolidated balance sheets of Barrett Resources Corporation (a Delaware corporation) and subsidiaries as of December 31, 1996 and 1995, and the related consolidated statements of income, stockholders' equity and cash flows for each of the three years in the period ended December 31, 1996. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Barrett Resources Corporation and subsidiaries as of December 31, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles. Arthur Andersen LLP Denver, Colorado February 28, 1997 F-1 BARRETT RESOURCES CORPORATION CONSOLIDATED BALANCE SHEETS DECEMBER 31, 1996 AND 1995 (IN THOUSANDS)
1996 1995 -------- -------- ASSETS Current assets: Cash and cash equivalents................................. $ 14,539 $ 7,529 Receivables, net.......................................... 73,045 31,089 Inventory................................................. 947 554 Other current assets...................................... 1,156 574 -------- -------- Total current assets.................................... 89,687 39,746 Net property and equipment (full cost method)............... 487,258 300,666 -------- -------- $576,945 $340,412 ======== ======== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable.......................................... $ 41,617 $ 14,369 Amounts payable to oil and gas property owners............ 18,496 8,874 Production taxes payable.................................. 13,830 8,047 Accrued and other liabilities............................. 4,374 4,770 -------- -------- Total current liabilities............................... 78,317 36,060 Long term debt.............................................. 70,000 89,000 Deferred income taxes....................................... 50,908 23,524 Commitments and contingencies--Note 10 Stockholders' equity: Preferred stock, $.001 par value: 1,000,000 shares authorized, none outstanding............................. -- -- Common stock, $.01 par value: 35,000,000 shares authorized, 31,330,361 outstanding (25,092,246 at December 31, 1995)....................................... 313 251 Additional paid-in capital................................ 241,991 86,154 Retained earnings......................................... 135,416 105,890 Treasury stock, at cost................................... -- (467) -------- -------- Total stockholders' equity.............................. 377,720 191,828 -------- -------- $576,945 $340,412 ======== ========
See accompanying notes. F-2 BARRETT RESOURCES CORPORATION CONSOLIDATED STATEMENTS OF INCOME YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994 (IN THOUSANDS, EXCEPT PER SHARE DATA)
1996 1995 1994 -------- -------- -------- Revenues: Oil and gas production.......................... $151,737 $ 96,996 $ 78,794 Trading revenues................................ 46,862 28,554 28,114 Revenue from gas gathering...................... 2,654 1,074 353 Interest income................................. 760 714 864 Other income.................................... 559 678 1,333 -------- -------- -------- 202,572 128,016 109,458 Operating expenses: Lease operating expenses........................ 47,642 34,525 28,223 Depreciation, depletion and amortization........ 45,775 33,480 22,760 Cost of trading................................. 44,036 27,611 27,190 General and administrative...................... 16,947 13,426 13,261 Interest expense................................ 3,684 4,631 942 Other expenses, net............................. -- 588 645 Merger and reorganization expense............... -- 14,161 -- -------- -------- -------- 158,084 128,422 93,021 -------- -------- -------- Income (loss) before income taxes................. 44,488 (406) 16,437 Provision for income taxes........................ 14,962 1,834 5,138 -------- -------- -------- Net income (loss)................................. $ 29,526 $ (2,240) $ 11,299 ======== ======== ======== Net income (loss) per common share and common share equivalent................................. $ 1.02 $ (.09) $ .46 ======== ======== ========
See accompanying notes. F-3 BARRETT RESOURCES CORPORATION CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994 (IN THOUSANDS)
ADDITIONAL TOTAL COMMON PAID-IN TREASURY RETAINED STOCKHOLDERS' STOCK CAPITAL STOCK EARNINGS EQUITY ------ ---------- -------- -------- ------------- Balance, January 1, 1994.... $246 $ 78,210 $(204) $100,358 $178,610 Exercise of stock options.................. 1 970 (313) -- 658 Purchase of treasury stock.................... -- -- (78) -- (78) Retirement of treasury stock.................... -- (552) 552 -- -- Cash dividends--Plains common stock............. -- -- -- (2,353) (2,353) Net income for the year ended December 31, 1994.. -- -- -- 11,299 11,299 ---- -------- ----- -------- -------- Balance, December 31, 1994.. 247 78,628 (43) 109,304 188,136 Exercise of stock options.................. 4 7,690 (588) -- 7,106 Retirement of treasury stock.................... (164) 164 -- -- Cash dividends--Plains common stock............. -- -- -- (1,174) (1,174) Net loss for the year ended December 31, 1995.. -- -- -- (2,240) (2,240) ---- -------- ----- -------- -------- Balance, December 31, 1995.. 251 86,154 (467) 105,890 191,828 Exercise of stock options.................. 2 4,077 (527) -- 3,552 Purchase of treasury stock.................... -- -- (351) -- (351) Retirement of treasury stock.................... -- (1,345) 1,345 -- -- Stock issued in connection with property acquisitions............. 6 18,362 -- -- 18,368 Issuance of common stock, net...................... 54 134,743 -- -- 134,797 Net income for the year ended December 31, 1996.. -- -- -- 29,526 29,526 ---- -------- ----- -------- -------- Balance, December 31, 1996.. $313 $241,991 $ -- $135,416 $377,720 ==== ======== ===== ======== ========
See accompanying notes. F-4 BARRETT RESOURCES CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994 (IN THOUSANDS)
1996 1995 1994 --------- -------- -------- Cash flows from operations: Net income (loss).............................. $ 29,526 $ (2,240) $ 11,299 Adjustments needed to reconcile to net cash flow provided by operations: Depreciation, depletion and amortization...... 45,775 33,480 22,760 Unrealized (gain) loss on trading............. (1,139) 1,139 58 Deferred income taxes......................... 13,655 1,798 4,788 Other......................................... -- (787) 70 --------- -------- -------- 87,817 33,390 38,975 Change in current assets and liabilities: Receivables................................... (41,956) 3,433 (8,436) Other current assets.......................... (582) 525 (148) Accounts payable.............................. 27,248 (524) 6,803 Amounts due oil and gas owners................ 9,622 (2,725) 623 Production taxes payable...................... 5,783 -- -- Accrued and other liabilities................. 742 1,439 (1,244) --------- -------- -------- Net cash flow provided by operations............ 88,674 35,538 36,573 --------- -------- -------- Cash flows from investing activities: Proceeds from sales of oil and gas properties.. 1,948 504 458 Short-term investments, net.................... -- -- 3,968 Acquisitions of property and equipment......... (202,610) (82,758) (95,589) Other.......................................... -- -- 146 --------- -------- -------- Net cash flow used in investing activities...... (200,662) (82,254) (91,017) --------- -------- -------- Cash flows from financing activities: Proceeds from issuance of common stock, net.... 138,349 7,071 301 Purchase of treasury stock..................... (351) -- (78) Borrowing under line of credit................. 91,000 115,000 44,000 Payments on line of credit..................... (110,000) (79,000) (4,500) Dividends paid................................. -- (1,174) (2,353) Other.......................................... -- -- (147) --------- -------- -------- Net cash flow provided by financing activities.. 118,998 41,897 37,223 --------- -------- -------- Increase (decrease) in cash and cash equivalents.................................... 7,010 (4,819) (17,221) Cash and cash equivalents at beginning of year.. 7,529 12,348 29,569 --------- -------- -------- Cash and cash equivalents at end of year........ $ 14,539 $ 7,529 $ 12,348 ========= ======== ========
See accompanying notes. F-5 BARRETT RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Business Barrett Resources Corporation (the "Company") is an independent natural gas and oil exploration and production company with producing properties located in the mid-continent states and Rocky Mountain region of the United States. Barrett also operates gas gathering systems and related facilities in certain areas in which the Company owns production. In addition, Barrett engages in natural gas trading activities, which involve purchasing natural gas from third parties and selling natural gas to other parties. In 1996, the Company commenced international activities with an exploration and development project in Peru. Principles of consolidation The consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are wholly-owned. All significant intercompany transactions have been eliminated in consolidation. Reclassifications Certain reclassifications have been made to 1995 and 1994 amounts to conform to the 1996 presentation. Use of estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. There are many factors, including global events, that may influence the production, processing, marketing, and valuation of crude oil and natural gas. A reduction in the valuation of oil and gas properties resulting from declining prices or production could adversely impact depletion rates and ceiling test limitations. Partnerships The consolidated financial statements include the Company's proportionate share of the assets, liabilities, revenues and expenses of its oil and gas partnership interests. Cash and cash equivalents Cash in excess of daily requirements is invested in money market accounts and commercial paper with maturities of three months or less. Such investments are deemed to be cash equivalents for purposes of the consolidated statements of cash flows. The carrying amount of cash equivalents approximates fair value because of the short maturity of those instruments. Oil and gas properties The Company utilizes the full cost method of accounting for oil and gas properties whereby all productive and nonproductive costs paid to third parties that are incurred in connection with the acquisition, exploration and development of oil and gas reserves are capitalized. No gains or losses are recognized upon the sale, conveyance or other disposition of oil and gas properties except in extraordinary transactions involving the transfer of significant amounts of oil and gas reserves. F-6 BARRETT RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) Capitalized costs are accumulated on a country-by-country basis subject to a cost center ceiling and amortized using the units-of-production method. The Company presently has two cost centers: the United States and Peru. Amortizable costs include developmental drilling in progress as well as estimates of future development costs of proved reserves but exclude the costs of unevaluated oil and gas properties. Accumulated depreciation and amortization is written off as assets are retired. Depletion and amortization equaled approximately $.59, $.55 and $.52 per Mcfe ($3.54, $3.28 and $3.14 per BOE) during the years ended December 31, 1996, 1995 and 1994, respectively. The Company capitalizes interest costs on amounts expended on assets during the period in which activities are occurring to place the asset in service. Amounts spent to develop properties included in the full cost center of oil and gas properties are excluded from the interest capitalization computation. The Company acquires nonproducing acreage for its exploration and development activities. The cost of these leases is included in unevaluated oil and gas property costs recorded at the lower of cost or fair market value. The Company operates many of the wells in which it owns an economic interest. The operating agreements for these activities provide for a fee structure to allow the Company to recover a portion of its direct and overhead charges related to its operating activities. The fees collected under the operating agreements are recorded as a reduction of general and administrative expenses. Any amounts collected from a sale of oil and gas interests or earned as a result of assembling oil and gas drilling activities are applied to reduce the book value of oil and gas properties. In 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets to Be Disposed Of" (SFAS No. 121) with an effective date of January 1, 1996. This pronouncement requires that impairment losses be recorded on other long-lived assets used in operations when either the undiscounted future cash flows estimated to be generated by those assets or the fair market value are less than the assets net book value. Oil and gas properties accounted for using the full cost method of accounting, a method utilized by the Company, are excluded from this requirement, but will continue to be subject to the ceiling test limitations. Other property and equipment Other property and equipment is recorded at cost. Renewals and betterments which substantially extend the useful life of the assets are capitalized. Maintenance and repairs are expensed when incurred. Depreciation is provided using accelerated and straight-line methods over the estimated useful lives, ranging from five to ten years, of the assets. Amounts payable to oil and gas property owners Amounts payable to oil and gas property owners consist of cash calls from working interest owners to pay for development costs of properties being currently developed and production revenue that the Company, as operator, is collecting and distributing to revenue interest owners. Trading and hedging activities The Company's business activities include buying and selling of natural gas. The Company recognizes revenue and costs on gas trading transactions at the point in time when gas is delivered to the purchaser. The Company uses both commodity futures contracts and price swaps to hedge the impact of price fluctuations on a portion of its production and trading activities. The Company enters into a hedging position for F-7 BARRETT RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) specific transactions that management deems expose the Company to an unacceptable market price risk. Price swaps or commodities transactions without corresponding scheduled physical transactions (scheduled physical transactions include committed trading activities or production from producing wells) do not qualify for hedge accounting. The Company classifies these positions as trading positions and records these instruments at fair value. Gains and losses are recognized as fair values fluctuate from time to time compared to cost. Gains or losses on hedging transactions are deferred until the physical transaction occurs for financial reporting purposes. Deferred gains and losses and unrealized gains and losses are evaluated in connection with the physical transaction underlying the hedge position. Hedging gains or losses significantly exceeding the price movement of the underlying physical transaction are recorded in the consolidated statements of income in the period in which the lack of correlation occurred. Gains or losses on hedging activities are recorded in the consolidated statements of income as adjustments of the revenue or cost of the underlying physical transaction. Hedging transactions are reported as operating activities in the consolidated statements of cash flows. Earnings per share Per share amounts were computed using the weighted average number of shares of common stock and common stock equivalents outstanding during each year: 1996--28,820,000; 1995--24,931,000; and 1994--24,967,000. Options to purchase stock are included as common stock equivalents, when dilutive, using the treasury stock method. Change in fiscal year On July 18, 1995, the Company changed its fiscal year-end from September 30 to December 31. A transition report for the period October 1, 1994 through December 31, 1994 was filed with the Securities and Exchange Commission. During the three months ended December 31, 1994, the Company reported revenues of $15 million and net income of $207,000. 2. MERGER On July 18, 1995 Plains Petroleum Company ("Plains") was merged with and into a subsidiary of the Company, resulting in Plains becoming a wholly owned subsidiary of the Company. Approximately 12.8 million shares of the Company's common stock were issued in exchange for all of the outstanding common stock of Plains. Additionally, outstanding options to acquire Plains common stock were converted to options to acquire approximately 593,000 shares of the Company's common stock. In connection with the merger, the Company's authorized number of shares of common stock was increased to 35 million shares. The merger was accounted for as a pooling of interests, and accordingly, the accompanying financial statements have been restated to include the accounts and operations of Plains for all periods prior to the merger. Plains used the successful efforts method of accounting for its oil and gas exploration and development activities. In conjunction with the merger, Plains adopted the full cost method used by the Company resulting in increases of net property and equipment due to the capitalization of exploration costs, reversal of impairment and adjustments of depreciation, depletion and amortization expense for periods prior to the merger. The financial statements for 1994 have been retroactively restated for the change in accounting method which resulted in increased net income. Retained earnings and deferred income taxes have been adjusted for the effect of the retroactive application of the new method. In connection with the merger, approximately $14.2 million of merger and reorganization costs and expenses were incurred and have been charged to expense in the Company's third and fourth quarters of fiscal 1995. These nonrecurring costs and expenses consist of (1) investment banker and professional fees of $7.4 F-8 BARRETT RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) million; (2) severance and employee benefit costs of $5.6 million for approximately 38 employees, terminated through consolidation of administrative and operational functions; (3) a non-cash credit of approximately $.9 million associated with the termination of Plains postretirement benefit plans and other related benefit plans and (4) other merger and reorganization related costs of $2.1 million. 3. RECEIVABLES
1996 1995 ------- ------- (IN THOUSANDS) Oil and gas revenue and trading receivables................. $48,161 $21,200 Joint interest billings..................................... 21,497 7,652 Other accounts receivable................................... 3,387 2,237 ------- ------- $73,045 $31,089 ======= =======
The Company's accounts receivable are primarily due from medium size oil and gas entities in the Rocky Mountain region. Collection of joint interest billings is generally secured by future production. The Company performs periodic credit evaluations of customers purchasing production for which no collateral is required. Historically, the Company has not experienced significant losses related to these extensions of credit. As of December 31, 1996 and 1995, receivables are recorded net of allowance for doubtful accounts of $229,000 and $201,000, respectively. 4. PROPERTY AND EQUIPMENT
1996 1995 -------- -------- (IN THOUSANDS) Oil and gas properties, full cost method: Unevaluated costs, not being amortized................. $ 82,126 $ 10,579 Evaluated costs........................................ 563,068 420,388 Gas gathering systems.................................. 28,219 13,168 Furniture, vehicles and equipment........................ 8,487 5,844 -------- -------- 681,900 449,979 Less accumulated depreciation, depletion, amortization and impairment.......................................... 194,642 149,313 -------- -------- $487,258 $300,666 ======== ========
The Company capitalized interest costs of $8,000 and $403,000 in 1996 and 1995, respectively, associated with qualifying properties. Total interest costs incurred after recognition of the capitalized interest amount were $3.7 million and $4.6 million in 1996 and 1995, respectively. 5. UNEVALUATED OIL AND GAS PROPERTY COSTS Unevaluated oil and gas property costs associated with unevaluated properties and major development projects consist of the following:
COSTS INCURRED DURING ------------------------------------------------ 1996 1995 1994 PRIOR PERIODS TOTAL ------- ------ ------ ------------- -------- (IN THOUSANDS) Acquisition costs United States.................... $46,810 $5,623 $125 $14 $52,572 Peru............................. 1,229 -- -- -- 1,229 Exploration costs United States.................... 27,908 417 -- -- 28,325 ------- ------ ------ -------------- ------- $75,947 $6,040 $125 $14 $82,126 ======= ====== ====== ============== =======
F-9 BARRETT RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) The unevaluated costs were incurred for projects which are being explored. The Company anticipates that substantially all unevaluated costs will be classified as evaluated costs within the next five years. 6. LONG-TERM DEBT The Company has a reserve-based line of credit with a group of banks which provides up to $200 million, maturing October 31, 2000. The amount actually available to the Company under the line at any given time is limited to the collateral value of proved reserves as determined by the lenders. Based on the lenders' determination of collateral value, as of December 31, 1996 (which was based on the June 30, 1996 reserve report), the Company's borrowing limit was $205 million. In connection with the sale of senior notes described below, the borrowing base was limited to $75 million until May 1, 1997. The lenders are currently reviewing the December 31, 1996 reserve report to determine current collateral value at which time the borrowing base could increase. The Company is required to pay interest only during the revolving period. At its option, the Company has elected to use the London interbank eurodollar rate (LIBOR) plus a spread ranging from .5 percent to 1.0 percent (depending on the Company's borrowing relative to its borrowing base) for a substantial portion of the outstanding balance. As of December 31, 1996 the Company's outstanding balance under the line of credit was $70 million of which $55 million was accruing interest at an average LIBOR based rate of 6.03 percent and $15 million was accruing interest on a prime based rate of 8.25 percent. The Credit Agreement restricts the payment of dividends, borrowings, sale of assets, loans to others, and investment and merger activity over certain limits without the prior consent of the bank and requires the Company to maintain certain net worth and debt to equity levels. Based on the variable borrowing rates and re-pricing terms currently available to the Company for the line of credit, management believes the fair value of long-term debt approximates the carrying value. In February 1997, the Company completed a public offering of $150 million (principal amount) of its 7.55% Senior Notes due 2007 ("Notes"). A portion of the net proceeds from the offering was used to repay in full the balance of $85 million of the Company's existing line of credit. The Notes are senior unsecured obligations of the Company ranking equally in right of payment to all existing and future senior indebtedness of the Company. At the option of the Company, the Notes may be redeemed at any time, in whole or in part, by paying an amount specified for a make-whole premium. The indenture of the Notes limits the Company's ability to incur indebtedness secured by certain liens, engage in certain sale/leaseback transactions, and engage in certain merger, consolidation or reorganization transactions. Interest will be paid semi-annually on February 1 and August 1 of each year, beginning August 1, 1997. 7. COMMON STOCK AND OPTIONS In June 1996, the Company issued 5.4 million shares of common stock for $26.375 per share in a public offering. The net proceeds from the issuance of the shares totaled approximately $134.8 million after deducting issuance costs and underwriting fees. The Company has two employee stock option plans, a 1990 Plan and a 1994 Plan, under which the Company's common stock may be granted to officers and employees of the Company and subsidiaries. The 1990 Plan provides for the granting of options to purchase 775,000 shares. The 1994 Plan, as amended, provides for the granting of options to purchase 1,000,000 shares of the Company's common stock. In addition, the Company has a non-discretionary stock option plan, as amended, under which options for an aggregate of 200,000 shares of the Company's common stock may be granted to non-employee directors. In connection with the merger discussed in Note 2, the Company assumed preexisting stock option plans of Plains and converted all options then outstanding into options to acquire shares of the Company's common stock. No further options will be granted under the Plains' plans. F-10 BARRETT RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) The exercise price of each option is equal to the market price of the Company's stock on the date of grant. Options generally become exercisable in equal installments on each of the first four anniversaries of the date of grant. The options expire, to the extent not exercised, between two and ten years after the date of the grant, or within 30 days after the recipient's earlier termination of employment with the Company. Options can be incentive stock options or non-statutory stock options. On January 1, 1996, the Company adopted Statement of Financial Accounting Standards No. 123, "Accounting for Stock Based Compensation" (SFAS No. 123). The Company elected to continue to account for these plans under APB Opinion No. 25, under which no compensation costs are recognized for option grants that equal market price at time of grant. Had compensation cost for these plans been determined consistent with SFAS No. 123, the Company's net income (loss) and earnings (loss) per share would have been reduced or increased as follows:
FOR THE YEAR ENDED DECEMBER 31, ------------------- 1996 1995 --------- --------- (IN THOUSANDS) Net income (loss) As reported.......................................... $ 29,526 $ (2,240) Pro forma............................................ 27,277 (2,485) Net income (loss) per share As reported.......................................... $ 1.02 $ (.09) Pro forma............................................ .95 (.10)
Changes in outstanding stock options under these plans are summarized as follows:
1996 1995 1994 -------------------- -------------------- -------------------- WEIGHTED- WEIGHTED- WEIGHTED- NUMBER OF AVERAGE NUMBER OF AVERAGE NUMBER OF AVERAGE OPTION EXERCISE OPTION EXERCISE OPTION EXERCISE SHARES PRICE SHARES PRICE SHARES PRICE --------- --------- --------- --------- --------- --------- Outstanding at beginning of year................ 986,546 $16.89 1,359,791 $16.06 929,111 $15.06 Granted................. 727,600 28.59 110,000 22.69 585,500 14.62 Exercised............... (230,897) 17.72 (425,969) 14.70 (141,820) 4.63 Forfeited............... (1,690) 23.96 (57,276) 24.48 (13,000) 4.25 --------- --------- --------- Outstanding at end of year................... 1,481,559 22.50 986,546 16.89 1,359,791 16.06 ========= ========= ========= Options exercisable at year end............... 392,959 417,121 721,041 Weighted-average fair value of options granted during the year................... $ 17.74 $ 14.23
The calculated value of stock options granted under these plans, following calculation methods prescribed by SFAS No. 123, uses the Black-Scholes stock option pricing model with the following weighted-average assumptions used: dividend yield of nil, expected volatility of 69.54 percent, risk-free interest rates of 6.44 percent and 6.68 percent for 1996 and 1995 respectively, and expected lives of 4.9 years. F-11 BARRETT RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) The following table summarizes information about stock options outstanding at December 31, 1996:
STOCK OPTIONS OUTSTANDING STOCK OPTIONS EXERCISABLE ---------------------------------- ---------------------------- WEIGHTED- AVERAGE WEIGHTED- WEIGHTED- NUMBER REMAINING AVERAGE NUMBER AVERAGE RANGE OF OUTSTANDING CONTRACTUAL EXERCISE EXERCISABLE EXERCISE EXERCISE PRICES AT 12/31/96 LIFE PRICE AT 12/31/96 PRICE - --------------- ----------- ------------ --------- ------------- ------------ $ 5-16 346,996 2.17 $12.59 150,946 $ 11.92 16-21 299,064 3.82 18.74 186,114 18.83 21-30 579,499 5.66 24.56 55,399 24.00 30-43 256,000 6.71 35.67 500 37.50 --------- ------- 1,481,559 22.50 392,959 16.92 ========= =======
8. RETIREMENT BENEFITS The Company has a voluntary 401(k) employee savings plan. Under this plan, as amended, the Company matches 100% of each of the participating employees contributions, up to a maximum of 6% of base salary, with one-half of the match paid in cash and one-half of the match paid in the Company's common stock. Prior to April 1, 1996, the Company matched 50% of each of the participating employees contributions, up to a maximum of 6% of base salary. The employee's rights to the Company's matching contributions are subject to a vesting schedule. Company contributions were $341,000, $239,000 and $179,000 in 1996, 1995 and 1994, respectively. Plains had several employee benefit plans. Pursuant to the terms of the merger agreement between Plains and the Company, these plans were terminated in 1995 and plan assets were distributed to the participants as described below. Plains defined benefit, profit-sharing and matching 401-K contributions totaled $281,000 and $838,000 for the 1995 and 1994 plan years, respectively. The Plains' profit-sharing and 401(k) plans were terminated July 1, 1995 and the pension plan was terminated September 18, 1995. Internal Revenue Service approval for termination of these plans was received in January 1996. Final distribution of plan assets was made to participants during 1996. Plains' executive deferred compensation plan and directors' deferred plan permitted the deferral of current salary or directors' fees for the purpose of providing funds at retirement or death for employees, directors and their beneficiaries. These plans were terminated effective June 30, 1995. A final distribution will be made to the participants by the trustee of the assets in 1998. Total accrued liability under these plans at December 31, 1995 was $36,000. Concurrently with the effective date of the merger, Plains' postretirement healthcare benefit and salary continuation plans were terminated. Participants in the salary continuation plan received (1) a lump sum benefit equal to the present value of the remaining monthly payments if receiving Death Benefits under the plan at the date of the termination, or (2) insurance policies, the cost of which was limited to the cash values of the life insurance policies owned by Plains. Benefits associated with the postretirement healthcare benefit plan were terminated and, accordingly, accrued postretirement benefit costs were relieved. 9. PRODUCTION HEDGING ACTIVITIES The Company uses swap agreements to reduce the effect of oil and natural gas price volatility on a portion of its oil and natural gas production. The objective of its hedging activities is to achieve more predictable F-12 BARRETT RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) revenues and cash flows. In a typical swap agreement, on a monthly basis for the term of the swap agreement, the Company receives the difference between a fixed price per unit of production and a price based on an agreed-upon third party index. The Company reviews and monitors the credit standing of the counter party to each of its swap agreements and believes that the counter party will fully comply with its contractual obligations. The following is a summary of the Company's outstanding natural gas swaps in effect as of December 31, 1996, all of which are associated with its Rocky Mountain natural gas production:
DURATION VOLUME FIXED PRICE -------- ---------------- -------------- January-March 1997.......................... 50,000 MMBTU/day $1.45 to $2.01 April-October 1997.......................... 20,000 MMBTU/day $1.45 to $1.75 Subsequent to December 31, 1996, the Company entered into the following additional natural gas swaps: March 1998-February 2003.................... 10,000 MMBTU/day $1.735 March 1998-February 2003.................... 10,000 MMBTU/day $1.75 March 2000-February 2003.................... 5,000 MMBTU/day $1.75 March 2002-February 2003.................... 5,000 MMBTU/day $1.75
Hedging gains and losses are recorded when the related gas or oil production has been produced or delivered or the financial instrument expires, and offset prices that have been received for natural gas and oil production. Net hedging gains (losses) are included in oil and gas revenues. For the years ended December 31, 1996, 1995 and 1994, the Company's gains (losses) under its production swap agreements were $(5.0) million, $0.4 million and $0.1 million, respectively. Included in 1995 is a hedging cost of approximately $1.2 million relating to a portion of the Company's hedging positions at December 31, 1995 which did not qualify for hedge accounting due to reduced correlation between the index price and the prices to be realized for certain physical gas deliveries. The unrealized hedging costs were recorded as a liability in 1995 and offset realized hedging costs as the respective hedges were settled in 1996. 10. COMMITMENTS AND CONTINGENCIES Lease Commitments The minimum future payments under the terms of operating leases, principally for office space, are as follows:
(IN THOUSANDS) Year ended December 31, 1997.................................................. $1,061 1998.................................................. 1,056 1999.................................................. 959 2000.................................................. 827 2001.................................................. 276 ------ $4,179 ======
Total minimum future rental payments have not been reduced by $363,000 of sublease rentals to be received in the future. Rent expense was $990,000, $956,000 and $859,000 for the years ended December 31, 1996, 1995 and 1994, respectively. F-13 BARRETT RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) Litigation The Internal Revenue Service (IRS) has examined the federal tax returns of Plains, a subsidiary of Barrett Resources Corporation, for pre-merger calendar years 1991, 1992 and 1993. The IRS issued a "Notice of Deficiency" of $5.3 million together with penalties of $1.1 million, and an undetermined amount of interest. The IRS notice of deficiency resulted primarily from the IRS's disallowance of certain net operating loss deductions claimed during the periods under examination. These net operating losses originally had been incurred by a company that was acquired by Plains in 1986. The Company currently has additional unused net operating loss carryforwards of approximately $30 million related to the same acquisition. Management disagrees with the IRS position. In management's opinion, the federal tax returns of Plains reflect the proper federal income tax liability and the existing net operating loss carryforwards are appropriate as supported by relevant authority. The Company will vigorously contest these proposed adjustments and believes it will prevail in its positions. It is anticipated that the final determination of this matter will involve a lengthy process. At December 31, 1996, the Company was a party to certain other legal proceedings which have arisen out of the ordinary course of business. Based on the facts currently available, in management's opinion the liability, individually or in the aggregate, if any, to the Company resulting from such actions will not have a material adverse effect on the Company's consolidated financial position or results of operations. Environmental Controls At year end 1996, there were no known environmental or other regulatory matters related to the Company's operations which are reasonably expected to result in a material liability to the Company. Compliance with environmental laws and regulations has not had, and is not expected to have, a material adverse effect on the Company's capital expenditures, earnings or competitive position. 11. INCOME TAXES The provision for income taxes consists of the following:
1996 1995 1994 ------- ------ ------ (IN THOUSANDS) Current: Federal............................................. $ 513 $ 269 $ 233 State............................................... 794 (233) 117 ------- ------ ------ 1,307 36 350 Deferred: Federal............................................. 12,833 2,039 4,511 State............................................... 822 (241) 277 ------- ------ ------ 13,655 1,798 4,788 ------- ------ ------ $14,962 $1,834 $5,138 ======= ====== ======
F-14 BARRETT RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) The difference between the provision for income taxes and the amounts which would be determined by applying the statutory federal income tax rate to income before provision for income taxes is analyzed below:
1996 1995 1994 ------- ------ ------- (IN THOUSANDS) Tax by applying the statutory federal income tax rate to pretax accounting income (loss)........ $15,571 $ (138) $ 5,753 Increase (decrease) in tax from: Change in valuation allowance................. -- 396 (2,148) State income taxes............................ 1,616 (474) 394 Non-deductible merger costs................... -- 2,429 -- Other, net.................................... (2,225) (379) 1,139 ------- ------ ------- $14,962 $1,834 $ 5,138 ======= ====== =======
Long-term deferred tax assets (liabilities) are comprised of the following at December 31, 1996 and 1995:
1996 1995 -------- -------- (IN THOUSANDS) Deferred tax assets: Allowance for losses.................................. $ 88 $ 81 Loss carryforwards and other.......................... 27,957 26,520 -------- -------- Gross deferred tax assets........................... 28,045 26,601 Deferred tax liabilities: Deferred revenue--partnership activities.............. (1,182) (466) Depreciation, depletion and amortization.............. (76,458) (48,460) Capitalized interest on other assets.................. (120) (6) -------- -------- Gross deferred tax liabilities...................... (77,760) (48,932) -------- -------- Net deferred tax liability.............................. (49,715) (22,331) Valuation allowance..................................... (1,193) (1,193) -------- -------- $(50,908) $(23,524) ======== ========
Valuation allowances of $1,193,000 were provided at both December 31, 1996 and 1995 based on carryforward amounts which may not be utilized before expiration. The Company has net operating loss and investment tax credit carryforwards available totaling $63.5 million and $.5 million, respectively, which expire in the years 1997 through 2010. A substantial portion of the net operating losses were acquired in conjunction with purchased operations. The 1990 public offering of common stock by the Company resulted in a change in the Company's ownership as defined in Section 382 of the Internal Revenue Code. The effect of this change in ownership limits the utilization of net operating losses for income tax purposes to approximately $3,069,000 per year which affects $13,590,000 of the net operating losses. The 1995 merger with Plains also resulted in a change in the Company's and Plains' ownership as defined by Section 382 of the Internal Revenue Code. The change effectively limits the annual utilization of the Company's and Plains' remaining net operating losses arising prior to the merger to approximately $14,000,000 for each company. Portions of the above limitations which are not used each year may be carried forward to future years. F-15 BARRETT RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) 12. SUPPLEMENTAL CASH FLOW SCHEDULES AND INFORMATION Cash paid during years
1996 1995 1994 ------ ------ ------ (IN THOUSANDS) Income tax...................................... $ 416 $ 65 $ 338 Interest........................................ 3,809 5,129 711 Supplemental information of noncash investing and financing activities: Issuance of common stock exchanged for treasury shares in cashless option transactions... $ 527 $ 545 $ 313
During 1996, the Company issued 50,000 shares of common stock with a market value of $1.9 million and exchanged certain oil and gas properties plus $13.4 million cash for oil and gas properties located in the Uinta Basin of Utah. In addition, with respect to acquisitions of various oil and gas and related properties located in the Piceance Basin of Colorado in 1996, the Company issued 585,661 shares of common stock valued at $16.5 million and recognized additional deferred taxes of $13.7 million, for the difference between the tax basis and book basis of the properties acquired. 13. RELATED PARTIES In April 1996, the Company acquired for $2.7 million from Zenith Drilling Corporation ("Zenith") all of Zenith's oil and gas interests located in the Piceance Basin of Colorado. In addition, the Company acquired all the stock of Grand Valley Corporation ("GVC") in exchange for 350,000 shares of the Company's common stock. The sole asset of GVC was an approximate 10% interest in the Grand Valley Gathering System. The Company previously owned interests in and is the operator of both the gathering system and the gas and oil assets in which it acquired interests as a result of these transactions. A member of the Company's Board of Directors owns 89% of Zenith and, at the time of the GVC transaction, was a director of GVC and owned 10% of GVC. Due to these relationships, the terms of these transactions with Zenith and GVC were negotiated on behalf of the Company by a Special Committee of the Board of Directors of the Company, consisting of four independent outside directors. The Company also obtained an opinion from an investment banking firm that the terms of these transactions were fair to the Company. During the years ended December 31, 1996, 1995 and 1994, Zenith was billed by the Company as operator, approximately $77,000, $1,062,000 and $1,853,000, respectively, for Zenith's portion of lease operating expenses and development costs in certain leases operated by the Company. Also, as a result of Zenith's working interest in those leases, Zenith received approximately $448,000, $942,000 and $936,000 as its share of revenues for 1996, 1995 and 1994, respectively. 14. QUARTERLY INFORMATION (UNAUDITED)
THREE MONTHS ENDED ---------------------------------------- 1996 3/31/96 6/30/96 9/30/96 12/31/96 - ---- --------- --------- --------- ---------- (IN THOUSANDS, EXCEPT PER SHARE DATA) Net revenues........................... $ 41,985 $ 46,910 $ 46,060 $ 66,298 Gross margin........................... 10,420 15,190 15,010 23,180 Income from operations................. 5,573 10,651 11,128 17,136 Net income.............. .............. 3,456 6,605 6,898 12,567 Net income per share................... .14 .25 .22 .41
F-16 BARRETT RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
THREE MONTHS ENDED ----------------------------------------- 1995 3/31/95 6/30/95 9/30/95 12/31/95 - ---- --------- --------- --------- ---------- (IN THOUSANDS, EXCEPT PER SHARE DATA) Net revenues......................... $ 33,060 $ 31,277 $ 27,217 $ 35,070 Gross margin......................... 8,611 8,039 6,476 7,882 Income (loss) from operations........ 4,327 3,997 (11,389) 2,659 Net income (loss).................... 3,014 2,957 (11,848) 3,637 Net income (loss) per share.......... .11 .13 (.47) .14 THREE MONTHS ENDED ----------------------------------------- 1994 3/31/94 6/30/94 9/30/94 12/31/94 - ---- --------- --------- --------- ---------- (IN THOUSANDS, EXCEPT PER SHARE DATA) Net revenues......................... $ 25,543 $ 24,420 $ 24,222 $ 33,076 Gross margin......................... 8,572 7,499 6,027 6,990 Income from operations............... 5,217 3,869 2,834 4,517 Net income........................... 3,799 2,610 2,081 2,809 Net income per share................. .15 .12 .08 .11
F-17 SUPPLEMENTAL OIL AND GAS INFORMATION The following information, pertaining to the Company's oil and gas producing activities for the years ended December 31, 1996, 1995 and 1994, is presented in accordance with Statement of Financial Accounting Standards No. 69, "Disclosure About Oil and Gas Producing Activities" (SFAS No. 69). MAJOR PURCHASER During 1996, one natural gas purchaser accounted for 11 percent of the Company's total revenue (15 percent of oil and gas revenues). Sales of gas to this same purchaser represented 18 percent and 19 percent of total revenues in 1995 and 1994, respectively. COST INCURRED IN OIL AND GAS EXPLORATION AND DEVELOPMENT ACTIVITIES The following costs were incurred by the Company in oil and gas property acquisition, exploration, and development activities during the years ended December 31:
1996 1995 1994 -------- ------- ------- (IN THOUSANDS) Acquisition of evaluated properties............... $ 68,157 $ 7,429 $35,234 Acquisition of unevaluated properties: United States................................... 45,051 8,383 8,446 Peru............................................ 1,229 -- -- Exploration costs................................. 32,086 23,272 36,232 Development costs................................. 69,651 33,029 20,190 Other, principally proceeds from mineral conveyances...................................... (1,948) (426) (173) -------- ------- ------- Total additions to oil and gas properties......... $214,226 $71,687 $99,929 ======== ======= =======
Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire a property. Exploration costs include the costs of geological and geophysical activity, dry holes, and drilling and equipping exploratory wells. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells. In addition, the Company incurred costs, including the acquisition of additional interests in existing facilities, of $15.1 million in 1996 for various supporting production facilities consisting principally of natural gas gathering systems and processing plants. Production facility expenditures for 1995 and 1994 were $1.3 million and $5.5 million, respectively. OIL AND GAS RESERVES (UNAUDITED) The following reserve related information for 1996 is based on estimates prepared by the Company. All of the Company's reserves are located in the United States. The 1996 reserve information for the Company was reviewed by Ryder Scott, an independent reservoir engineer. The Company's 1995 and 1994 reserves, exclusive of Plains, were prepared by the Company and reviewed by Ryder Scott as of December 31, 1995 and September 30, 1994. The 1995 and 1994 proved developed reserve estimates of Plains were prepared by Netherland, Sewell & Associates, Inc. whereas the proved undeveloped reserve estimates were prepared by Plains. Reserve estimates are inherently imprecise and are continually subject to revisions based on production history, results of additional exploration and development, prices of oil and gas and other factors. F-18
1996 1995 1994 --------------------- --------------------- --------------------- OIL (MBBL) GAS (MMCF) OIL (MBBL) GAS (MMCF) OIL (MBBL) GAS (MMCF) ---------- ---------- ---------- ---------- ---------- ---------- (IN THOUSANDS) PROVED DEVELOPED AND UNDEVELOPED RESERVES: Beginning of year....... 12,967 513,531 11,444 458,820 6,947 364,791 Revisions of previous estimates.............. (210) (778) 1,209 (3,805) 772 (5,640) Purchase of minerals in place.................. 6,628 95,914 831 3,983 2,533 38,717 Extensions and discoveries............ 6,029 127,547 1,232 102,329 2,547 94,276 Production.............. (1,913) (60,883) (1,702) (47,692) (1,293) (33,282) Sale of minerals in place.................. (270) (438) (47) (104) (62) (42) ------ ------- ------ ------- ------ ------- End of year............. 23,231 674,893 12,967 513,531 11,444 458,820 ====== ======= ====== ======= ====== ======= PROVED DEVELOPED RESERVES: Beginning of year....... 11,669 419,672 7,848 393,051 5,548 342,287 ====== ======= ====== ======= ====== ======= End of year............. 15,773 511,645 11,669 419,672 7,848 393,051 ====== ======= ====== ======= ====== =======
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS The standardized measure of discounted future net cash flows is based on estimated quantities of proved reserves and the future periods in which they are expected to be produced and on year-end economic conditions. Estimated future gross revenues are priced on the basis of year-end prices, except in the case of contracts where the applicable contract price, including fixed and determinable escalations, were used for the duration of the contract. The effects of existing hedging swap agreements discussed in Note 9 were included in determining future cash inflows. Estimated future gross revenues are reduced by estimated future development and production costs, as well as certain abandonment costs and by estimated future income tax expense. Future income tax expenses have been computed considering the tax basis of the oil and gas properties plus available carryforwards and credits. The standardized measure of discounted future net cash flows should not be construed to be an estimate of the fair market value of the Company's proved reserves. Estimates of fair value would also take into account anticipated changes in future prices and costs, the reserve recovery variances from estimated proved reserves and a discount factor more representative of the time value of money and the inherent risks in producing oil and gas. Significant changes in estimated reserve volumes or product prices could have a material effect on the Company's consolidated financial statements.
1996 1995 1994 ---------- ---------- --------- (IN THOUSANDS) Future cash inflows........................ $2,893,217 $1,132,711 $ 931,404 Future production costs.................... (773,233) (355,756) (310,485) Future development costs................... (152,141) (46,888) (41,972) Future income tax expenses................. (628,901) (207,922) (152,890) ---------- ---------- --------- Future net cash flows.................... 1,338,942 522,145 426,057 10% annual discount for estimated timing of cash flows............................. (574,139) (212,271) (183,436) ---------- ---------- --------- Standardized measure of discounted future net cash flows............................ $ 764,803 $ 309,874 $ 242,621 ========== ========== =========
F-19 The following are the principal sources of changes in the standardized measure of discounted future net cash flows:
1996 1995 1994 --------- -------- -------- (IN THOUSANDS) Net change in sales price and production costs......................................... $ 415,937 $ 24,558 $(22,409) Changes in estimated future development costs.. 16,288 10,301 14,492 Sales and transfers of oil and gas produced, net of production costs....................... (110,341) (62,294) (50,571) Net change due to extensions and discoveries... 230,797 85,524 60,613 Net change due to purchases and sales of minerals in place............................. 167,235 7,424 32,726 Net change due to revisions in quantities...... (41,486) (1,393) (588) Net change in income taxes..................... (249,836) (33,172) (10,202) Accretion of discount.......................... 28,053 23,112 27,589 Other, principally revisions in estimates of timing of production.......................... (1,718) 13,193 (12,115) --------- -------- -------- Net changes.................................... 454,929 67,253 39,535 Balance, beginning of year..................... 309,874 242,621 203,086 --------- -------- -------- Balance, end of year........................... $ 764,803 $309,874 $242,621 ========= ======== ========
The December 31, 1996 weighted average prices utilized for purposes of estimating the Company's proved reserves and future net revenues were $24.12 per barrel of oil and $3.46 per Mcf of natural gas. These prices are significantly above the average annual prices received during the past several years. In addition, during the first three months of 1997, prices have declined from the December 31, 1996 levels. F-20 SIGNATURES PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. BARRETT RESOURCES CORPORATION Date: March 20, 1997 By: /s/ William J. Barrett _________________________________ WILLIAM J. BARRETT CHIEF EXECUTIVE OFFICER Date: March 20, 1997 By: /s/ John F. Keller _________________________________ JOHN F. KELLER CHIEF FINANCIAL OFFICER, SECRETARY, AND PRINCIPAL FINANCIAL AND ACCOUNTING OFFICER
SIGNATURE TITLE DATE --------- ----- ---- /s/ William J. Barrett Director March 20, 1997 - ------------------------------------- WILLIAM J. BARRETT /s/ C. Robert Buford Director March 20, 1997 - ------------------------------------- C. ROBERT BUFORD /s/ Derrill Cody Director March 20, 1997 - ------------------------------------- DERRILL CODY /s/ James M. Fitzgibbons Director March 20, 1997 - ------------------------------------- JAMES M. FITZGIBBONS /s/ Hennie L.J.M. Gieskes Director March 20, 1997 - ------------------------------------- HENNIE L.J.M. GIESKES /s/ William W. Grant, III Director March 20, 1997 - ------------------------------------- WILLIAM W. GRANT, III
II-1
SIGNATURE TITLE DATE --------- ----- ---- /s/ John F. Keller Director March 20, 1997 - ------------------------------------- JOHN F. KELLER /s/ Paul M. Rady Director March 20, 1997 - ------------------------------------- PAUL M. RADY /s/ A. Ralph Reed Director March 20, 1997 - ------------------------------------- A. RALPH REED /s/ James T. Rodgers Director March 20, 1997 - ------------------------------------- JAMES T. RODGERS /s/ Philippe S.E. Schreiber Director March 20, 1997 - ------------------------------------- PHILIPPE S.E. SCHREIBER /s/ Harry S. Welch Director March 20, 1997 - ------------------------------------- HARRY S. WELCH
II-2 EXHIBIT INDEX
EXHIBIT ------- 2.1 Agreement And Plan of Merger, dated as of May 2, 1995, among Barrett Resources Corporation ("Barrett" or "Registrant"), Barrett Energy Inc. (formerly known as Vanilla Corporation), and Plains Petroleum Company ("Plains") is incorporated by reference from Annex I to the Joint Proxy Statement/Prospectus of Barrett and Plains dated June 13, 1995. 3.1 Restated Certificate Of Incorporation of Barrett Resources Corporation, a Delaware corporation, is incorporated herein by reference from Exhibit 3.2 of Registrant's Registration Statement on Form S-4 dated June 9, 1995. 3.6 Bylaws of Barrett, as amended, are incorporated herein by reference from Exhibit 3.3 of Registrant's Registration Statement on Form S-4 dated June 9, 1995. 10.1 Non-Qualified Stock Option Plan Of Barrett Resources Corporation is incorporated by reference from Registrant's Registration Statement on Form S-8 dated November 15, 1989. 10.2 Registrant's 1990 Stock Option Plan, as amended, is incorporated by reference from the Registrant's Registration Statement on Form S-8 dated March 15, 1995. 10.3 Registrant's Non-Discretionary Stock Option Plan is incorporated by reference from Registrant's Annual Report on Form 10-K for the year ended September 30, 1991. 10.4 1994 Stock Option Plan, as amended, is incorporated by reference from the Registrant's Registration Statement on Form S-8 dated March 15, 1995. 10.5A Gas Purchase Contract, No. P-1090, dated April 20, 1984, as amended, between Plains and KN Energy, Inc. is incorporated by reference from Plains Petroleum Company's Registration Statement on Form 10 dated August 21, 1985. 10.5B Letter Agreement dated December 19, 1996, amending the Gas Purchase Contract, No. P-1090, dated April 20, 1984, between Plains and KN Energy, Inc. 10.6A Revolving Credit Agreement dated as of July 19, 1995 among Barrett and Texas Commerce Bank National Association, as Agent, and Texas Commerce Bank National Association, Nations Bank of Texas, N.A., Bank of Montreal, Houston Agency, Colorado National Bank, and The First National Bank of Boston, as the "Banks" is incorporated by reference from Exhibit 10.6 to Barrett's Annual Report on Form 10-K for the year ended December 31, 1996. 10.6B First Amendment to Revolving Credit Agreement dated October 31, 1996 between and among Barrett, Agent and the Banks is incorporated by reference from Exhibit 10.1 to Amendment No. 2 to Barrett's Registration Statement on Form S-3 (File No. 333 -19363) dated February 10, 1997. 10.6C Second Amendment to Revolving Credit Agreement dated February 10, 1997 between and among Barrett, the Agent, and the Banks is incorporated by reference from Exhibit 10.2 to Amendment No. 2 to Barrett's Registration Statement on Form S-3 (File No. 333 -19363) dated February 10, 1997. 21 List of Subsidiaries. 23 Consent of Arthur Andersen LLP. 27 Financial Data Schedule.
EX-10.5B 2 LETTER AGREEMENT DATED DECEMBER 19, 1996 [LETTERHEAD OF K N GAS APPEARS HERE] December 19, 1996 Plains Petroleum Operating Company 1515 Arapahoe Street Tower III Suite 1000 Denver, CO 80202 Attn: Mr. Bryan Hassler Vice President RE: Gas Purchase Contract Dated April 20, 1984, As Amended (Contract No. P-1090) Dear Mr. Hassler: Plains Petroleum Operating Company ("Plains") and KN Gas Supply Services, Inc. as the successor-in-interest to K N Energy, Inc. ("KNGSS") are parties to that certain Gas Purchase Contract, dated April 20, 1984, as amended, hereinafter referred to as "Contract P-1090". The purpose of this Letter Agreement is to set forth the agreement reached between Plains and KNGSS with respect to the quantity of gas to be purchased and the price to be paid for gas by KNGSS under Contract P-1090, as well as the release of gas thereunder, during calendar year 1997. The agreement is as follows: A. (1) During calendar year 1997 only, the take-or-pay provisions of Contract P-1090 are hereby suspended and both parties are hereby relieved of the obligations to account for and track take-or-pay status during that period. KNGSS, subject to an event of force majeure, will use good faith efforts to purchase under Contract P-1090 all of the gas tendered and physically made available by Plains to KNGSS at the Delivery Points during the period commencing January 1, 1997 and ending December 31, 1997. (2) Plains will advise KNGSS by the fifteenth (15th) business day prior to a month, the quantity of gas Plains will make available for purchase by KNGSS the following month, including any mid-month adjustments. Once the quantity has been communicated to KNGSS, modifications to the quantity will only be made be mutual agreement of the parties. Plains and KNGSS will use good faith efforts to maintain, on a monthly basis, a balance between Plains' monthly availability and the actual receipt and delivery of gas during a month. Any imbalance between the quantity of gas made available for purchase by Plains for a month and the quantity Plains Petroleum Operating Company 12/19/96 Page 2 actually received by KNGSS shall be corrected as soon as possible in a manner mutually agreed to by the parties. If at the end of a month, Plains delivers, or causes to be delivered for Plains' account, a quantity of gas that is greater or less than that made available and scheduled for receipt and delivery, and such deliveries cause Plains or KNGSS to incur a penalty, cashout, or other charge levied by the gatherer and/or transporter, Plains agrees to bear and pay, or if required to reimburse KNGSS, for such penalty, cashout or charge. If at the end of a month, KNGSS receives, or causes to be received for KNGSS' account, a quantity of gas that is greater or less than that made available and scheduled for receipt and delivery, and such deliveries cause Plains or KNGSS to incur a penalty, cashout, or other charge levied by the gatherer and/or transporter, KNGSS agrees to bear and pay, or if required to reimburse Plains, for such penalty, cashout or charge. Plains and KNGSS agree to provide one another all information necessary to determine what event, or which party caused the imbalance. B. (1) The price to be paid under Contract P-1090 for each MMBtu of gas purchased during calendar year 1997 will be a price equal to the average of the first of the month index prices as published by McGraw-Hill in the first of each month's publication of Inside F.E.R.C.'s Gas Market Report under "Prices of Spot ----------------------------------- Gas Delivered to Pipelines" for Williams Natural Gas Co. (Texas, Oklahoma, Kansas), Panhandle Eastern Pipe Line Co. (Texas, Oklahoma), Northern Natural Gas Co. (Texas, Oklahoma, Kansas), and Natural Gas Pipeline Company of America (Mid-Continent zone), hereinafter referred to as the "Average Index Price", less Fifteen Cents ($0.15) per MMBtu, hereinafter referred to as the "subtrahend", less one percent (1%) fuel to be provided in-kind by Plains. The price is a full price inclusive of any and all costs and reimbursements. (2) In calculating the monthly price to be paid for gas, as provided for in Paragraph B(1) above, the subtrahend will be subject to adjustment, either upward or downward, depending on the actual calculated Average Index Price as follows: If the Average Index Price is: then the Subtrahend is: - ------------------------------ ----------------------- less than $0.75 $0.11 $0.75 up to $1.04 $0.13 $1.05 up to $1.95 $0.15 $1.96 up to $2.25 $0.18 $2.26 or higher $0.20 C. During calendar year 1997, gas which flows south through the valve identified below to the Panhandle Eastern Pipe Line Co. ("Panhandle"), Grant County No. 2 Interconnect, not to exceed a total quantity of 3 Bcf, is hereby temporarily released from Contract P-1090, on a month-to-month basis; provided, however, if KNGSS can flow at least ninety percent (90%) of the quantity released during a month, then KNGSS shall have the preferential right to recall, also on a monthly basis, all gas released during a month for purchase under Contract P-1090 Plains Petroleum Operating Company 12/19/96 Page 3 at the price provided for in this Letter Agreement. If KNGSS intends to recall released gas it shall be required to recall all the gas released for the particular month. KNGSS, at least ten (10) business days before the succeeding month, will notify Plains of the recall of the released gas for purchase by KNGSS the succeeding month. D. During calendar year 1997 only, KNGSS agrees not to exercise its right under Article IV, Section 8 of Contract P-1090 to market out. E. During calendar year 1997, KNGSS can temporarily release up to 25% of the gas made available by Plains pursuant to Paragraph A of this Letter Agreement, on a month to month basis. If KNGSS desires to release a quantity of gas, KNGSS desires to release the gas. Plains shall have the right to market any released gas for the period of the release. K N has the right to exercise this release option in any five (5) of the twelve months in calendar year 1997. The gathering of this released gas will be covered by separate agreement with K N Gas Gathering, Inc. F. Except as specifically provided for herein, all other terms and conditions of Contract P-1090 shall remain in full force and effect. If the foregoing reflects Plains' understanding of the agreement reached between Plains and KNGSS, please so indicate by properly executing both copies of this Letter Agreement in the space provided for below and return one executed original to my attention. Very truly yours, K N Gas Supply Services, Inc. /s/ Daniel E. Watson Vice President ACCEPTED AND AGREED to this 19th day of December, 1996 by Plains Petroleum Operating Company BY: /s/ Bryan Hassler ----------------- Bryan Hassler Vice President EX-21 3 SUBSIDIARIES OF THE REGISTRANT BARRETT RESOURCES CORPORATION Exhibit 21 Subsidiaries of the Registrant
Name of Company State of Incorporation - --------------- ---------------------- Alarado Corporation..............................................Delaware Alarado (Denver) Company.........................................Colorado Bargath, Inc.....................................................Colorado Barrett Fuels Corporation........................................Delaware Barrett Resources International Corporation......................Delaware Barrett Resources (PAC I) Corporation............................Kansas Barrett Resources (PAC II) Corporation...........................Kansas Barrett Resources (Peru) Corporation.............................Delaware BGP Inc. ........................................................Delaware Grand Valley Gathering System (joint venture)....................Colorado Plains Petroleum Company.........................................Delaware Plains Petroleum Gathering Company...............................Delaware Plains Petroleum Operating Company...............................Delaware
All of the subsidiaries named above are included in the consolidated financial statements of the Registrant included herein. EX-23 4 CONSENT OF ARTHUR ANDERSEN LLP CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation by reference in each of the Registration Statements and related prospectuses on Form S-8 (No. 333-18311) pertaining to the 1990 Stock Option Plan, 1994 Stock Option Plan and Non-Discretionary Stock Option Plan of Barrett Resources Corporation, on Form S-8 (No. 333-02529) pertaining to the Retirement Savings Plan of Barrett Resources Corporation, and on Form S-8 (No. 33-61097) pertaining to the 1985 Stock Option Plan, 1985 Stock Option Plan For Non-Employee Directors, 1989 Stock Option Plan, and 1992 Stock Option Plan of Plains Petroleum Company (a wholly-owned subsidiary of Barrett Resources Corporation) of our report dated February 28, 1997, with respect to the consolidated financial statements of Barrett Resources Corporation included in the Annual Report (Form 10-K) for the year ended December 31, 1996. /s/Arthur Andersen LLP ARTHUR ANDERSEN LLP Denver, Colorado March 27, 1997 EX-27 5 FINANCIAL DATA SCHEDULE
5 1,000 12-MOS 12-MOS DEC-31-1996 DEC-31-1995 JAN-01-1996 JAN-01-1995 DEC-31-1996 DEC-31-1995 14,539 7,529 0 0 73,274 31,290 229 201 947 554 89,687 39,746 681,900 449,979 194,642 149,313 576,945 340,412 78,317 36,060 0 0 0 0 0 0 313 251 377,407 191,577 576,945 340,412 198,599 125,550 202,572 128,016 137,453 95,616 137,453 95,616 16,947 28,175 0 0 3,684 4,631 44,488 (406) 14,962 1,834 29,526 (2,240) 0 0 0 0 0 0 29,526 (2,240) 1.02 (0.09) 1.02 (0.09)
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