-----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, Ww2qoBwg5SGTZ3LnjB5q129x0mUNQkD7GjZU3JVt0MfdnlnkQ6fbBJFa/u7lOhHJ eOI1wLECiBPKlXoJfIboOg== 0000927356-97-000124.txt : 19970222 0000927356-97-000124.hdr.sgml : 19970222 ACCESSION NUMBER: 0000927356-97-000124 CONFORMED SUBMISSION TYPE: 424B4 PUBLIC DOCUMENT COUNT: 1 FILED AS OF DATE: 19970212 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: 424B4 SEC ACT: 1933 Act SEC FILE NUMBER: 333-19363 FILM NUMBER: 97526974 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 424B4 1 FINAL PROSPECTUS [LOGO OF BARRETT RESOURCES CORPORATION APPEARS HERE] $150,000,000 BARRETT RESOURCES CORPORATION 7.55% SENIOR NOTES DUE 2007 ---------------- The 7.55% Senior Notes due 2007 of Barrett Resources Corporation will be senior unsecured obligations of the Company and will mature on February 1, 2007. Interest on the Notes is payable on February 1 and August 1 of each year, commencing August 1, 1997. The Notes may be redeemed at any time, at the option of the Company, in whole or in part, at a price equal to 100% of the principal amount plus accrued and unpaid interest (if any) to the date of redemption plus a Make-Whole Premium, if any, relating to the then prevailing Treasury Yield and the remaining life of the Notes. The Notes will rank pari passu in right of payment with any existing and future senior unsecured indebtedness of the Company, including under its bank credit facility, and senior in right of payment to all existing and future subordinated indebtedness of the Company. See "Description of Notes." The Company will use the net proceeds of the Offering to repay in full indebtedness under its bank credit facility, to fund a portion of its planned exploration and development activities and for other general corporate purposes, including possible acquisitions. See "Use of Proceeds." The Notes will be evidenced by a Global Certificate in fully registered form without coupons, deposited with a custodian for and registered in the name of a nominee of The Depository Trust Company. Except as described herein, beneficial interests in the Global Certificate will be shown on, and transfers thereof will be effected only through, records maintained by DTC and its direct and indirect participants. See "Description of Notes." The Notes are not entitled to any sinking fund. The Company does not intend to apply for listing of the Notes on any securities exchange or for inclusion of the Notes in any automated quotation system. SEE "RISK FACTORS" COMMENCING ON PAGE 9 FOR INFORMATION THAT SHOULD BE CONSIDERED BY PROSPECTIVE INVESTORS IN CONNECTION WITH AN INVESTMENT IN THE NOTES. ---------------- THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE. ----------------
INITIAL PUBLIC UNDERWRITING PROCEEDS TO OFFERING PRICE(1) DISCOUNT(2) COMPANY(1)(3) ----------------- ------------ ------------- Per Note..................................... 99.732% 2.000% 97.732% Total........................................ $149,598,000 $3,000,000 $146,598,000
- -------- (1) Plus accrued interest from February 1, 1997. (2) The Company has agreed to indemnify the Underwriters against certain liabilities, including liabilities under the Securities Act of 1933. See "Underwriting." (3) Before deducting estimated expenses of $450,000 payable by the Company. ---------------- The Notes offered hereby are offered severally by the Underwriters, as specified herein, subject to receipt and acceptance by them and subject to their right to reject any order in whole or in part. It is expected that the Notes will be ready for delivery in book-entry form only through the facilities of DTC in New York, New York, on or about February 14, 1997, against payment therefor in immediately available funds. GOLDMAN, SACHS & CO. CHASE SECURITIES INC. LEHMAN BROTHERS PETRIE PARKMAN & CO. ---------------- The date of this Prospectus is February 11, 1997. [CORE AREAS OF ACTIVITY MAP APPEARS HERE] IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE NOTES OFFERED HEREBY AT A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN MARKET. SUCH STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME. 2 PROSPECTUS SUMMARY The following summary is qualified in its entirety by the more detailed information and financial statements appearing elsewhere in this Prospectus and in the documents incorporated by reference into this Prospectus. As used herein, the "Company" or "Barrett" means Barrett Resources Corporation and its subsidiaries unless the context requires otherwise. Unless otherwise indicated, all references to annual or quarterly periods refer to the Company's fiscal year ending December 31. Unless otherwise indicated herein, the information in this Prospectus includes the effects of the restatement of the Company's financial, operating and reserve information to include Plains Petroleum Company ("Plains") on a combined basis effective for all periods as a result of the July 18, 1995 merger with Plains, which was accounted for as a pooling of interests. Investors should carefully consider the information set forth under the heading "Risk Factors." Certain terms used herein relating to the oil and gas industry are defined in "Certain Definitions" included on pages 55 and 56 of this Prospectus. THE COMPANY GENERAL 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 72.3 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. 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 September 30, 1996, the Company owned interests in 2,124 producing wells and operated 1,131 of these wells. These operated wells contributed approximately 82% of Barrett's natural gas and oil production for the nine months ended September 30, 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 3 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 "Business and Properties--Natural Gas and Oil Marketing and Trading." BUSINESS STRATEGY Barrett's business strategy is to generate strong growth in reserves, production, earnings and cash flow through exploration, development and selective acquisitions of natural gas and oil properties in its core areas of activity. The Company implements this strategy through a series of continuing initiatives: SPECIALIZED GEOLOGIC EXPERTISE. Both the CEO and President of Barrett are experienced, practicing geologists. They have established a team of geologists and geophysicists with expertise in the Company's core areas of activity. Prior to undertaking projects in new areas, the Company assembles specialized geologic expertise to identify and evaluate drilling prospects. ACTIVE DRILLING PROGRAM. Barrett maintains a high quality, balanced portfolio of lower risk development projects complemented by higher potential exploration prospects. The Company's preliminary 1997 capital expenditure budget is $278 million, approximately 75% of which is allocated to drilling and production activities. This budget, which is subject to revision based upon market conditions and other factors, contemplates that the Company will participate in drilling approximately 290 gross wells in 1997 as compared with 196 gross wells drilled in 1996. The Company expects to continue high levels of drilling activity after 1997. ADVANCED TECHNOLOGY. The Company makes extensive use of advanced technologies, including 3-D seismic and in-house analytical and processing capabilities, to better define drilling prospects. The Company also uses advanced production techniques, such as alkaline surfactant polymer ("ASP") technology, in its enhanced recovery operations. OPERATING CORE PROPERTIES. At September 30, 1996, Barrett served as operator for 1,131 wells, which contributed approximately 82% of the Company's production during the nine months ended September 30, 1996. As operator, the Company coordinates drilling activities and arranges for the production, gathering and sale of its natural gas and oil from operated wells. Serving as operator enables the Company to exert greater control over the cost and timing of its exploration, development and production activities. CONTINUING COST MANAGEMENT. The Company continually strives to reduce expenses through implementation of cost control programs and active management of its operations, personnel and administrative activities. Current cost management initiatives include entering into multi-well and longer term contracts with drilling companies and participating in alliances with oil field service companies to obtain more favorable terms. FINANCIAL STRENGTH. The Company is committed to maintaining financial flexibility in order to pursue exploration and development activities and to take advantage of other opportunities that may arise. Historically, the Company has funded its growth primarily through the issuance of common stock, including four public stock offerings, its 1995 stock-for-stock merger with Plains and several recent acquisitions financed with common stock. The issuance of the Notes offered hereby (the "Notes") adds ten-year fixed rate debt financing to the Company's capital structure, which will improve Barrett's liquidity, diversify its capital base and enhance the Company's ability to pursue its business strategy. SELECTIVE RESERVE AND LEASEHOLD ACQUISITIONS. From time to time the Company seeks to augment activities in its core areas, establish operations in new areas and build acreage positions for 4 exploration prospects through selective acquisitions. As a result of acquisitions completed during 1996, the Company increased its working interests in the Piceance Basin, expanded its operations in the Uinta Basin and substantially increased its leased acreage position in the Gulf of Mexico. RECENT DEVELOPMENTS CAPITAL EXPENDITURES. The Company's preliminary 1997 capital expenditure budget for natural gas and oil activities is $278 million. Total estimated 1997 expenditures are allocated approximately 41% to the Gulf of Mexico Region, 25% to the Rocky Mountain Region, 19% to the Mid-Continent Region, 6% to international activities and 9% to possible acquisitions. This budget is subject to revision based upon market conditions and other factors. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Business and Properties--Core Areas of Activities." OFFSHORE FEDERAL LEASE SALES. At the September 1996 Western Gulf of Mexico Offshore Lease Sale, the Company significantly expanded its position in the Gulf of Mexico. The Minerals Management Service ("MMS") awarded the Company leases covering 17 blocks. 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. As a result of these transactions, Barrett holds interests in 46 lease blocks in the Gulf of Mexico covering approximately 185,000 gross acres. See "Business and Properties--Core Areas of Activity--Gulf of Mexico Region." UINTA BASIN ACQUISITIONS. In November 1996, the Company expanded its operations in the Uinta Basin of northeastern Utah when it 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 100,000 gross and 72,000 net acres of leasehold interests. The total purchase price was approximately $32 million, including approximately $14 million in cash, 50,000 shares of the Company's common stock, and certain non-strategic producing properties owned by the Company. In January 1997, the Company acquired additional interests in the Altamont-Bluebell Field for an aggregate purchase price of $3.5 million in cash. 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. See "Business and Properties--Core Areas of Activity-- Rocky Mountain Region--Uinta Basin." PARTICIPATION IN MARANON BASIN, PERU. In late January 1997, the Company entered into an agreement with industry partners that provided the Company with a license covering approximately 2.0 million gross acres located in the Maranon Basin of northeastern Peru. The Company and its partners intend to acquire and analyze 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. It is anticipated that the Company will be designated operator for operations in this area in mid-1997. See "Business and Properties--Core Areas of Activity-- International Operations." 5 THE OFFERING Issuer Barrett Resources Corporation. Securities Offered $150,000,000 principal amount of 7.55% Senior Notes due 2007. Maturity Date February 1, 2007. Interest Payment Dates February 1 and August 1 of each year, beginning on August 1, 1997. Optional Redemption The Notes may be redeemed at any time, at the option of the Company, in whole or in part, at a price equal to 100% of the principal amount plus accrued and unpaid interest (if any) to the date of redemption plus a Make- Whole Premium (if any) relating to the then prevailing Treasury Yield and the remaining life of the Notes. Mandatory Redemption None. Ranking The Notes will be senior unsecured obligations of the Company and will rank pari passu in right of payment with any existing and future senior unsecured indebtedness of the Company, including under its bank credit facility, and senior in right of payment to all existing and future subordinated indebtedness of the Company. Certain Covenants The indenture (the "Indenture") relating to the Notes will contain limitations on, among other things, the Company's ability to (i) incur indebtedness secured by certain liens, (ii) engage in certain sale/leaseback transactions, and (iii) engage in certain merger, consolidation or reorganization transactions. See "Description of Notes." Use of Proceeds The net proceeds from the offering of the Notes will be used to repay in full indebtedness under the Company's bank credit facility ($70 million outstanding as of December 31, 1996 and $85 million outstanding as of February 7, 1997), to fund a portion of the Company's planned exploration and development activities and for other general corporate purposes, including possible acquisitions. See "Use of Proceeds."
6 SELECTED CONSOLIDATED FINANCIAL, RESERVE AND OPERATING DATA The following table sets forth the selected historical consolidated financial, reserve and operating data of Barrett for each of the periods indicated. The historical financial data of Barrett for the three-year period ended December 31, 1995 have been derived from Barrett's audited consolidated financial statements. The historical financial data for the nine months ended September 30, 1995 and 1996 are derived from unaudited financial statements of the Company. Production data for all periods are unaudited. Barrett's previously reported data for 1995 and prior years have been restated to reflect the merger with Plains under the pooling of interests method of accounting and the change in fiscal year end from September 30 to December 31. The selected consolidated financial, reserve and operating data set forth below should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Consolidated Financial Statements and notes thereto and other information included elsewhere in this Prospectus and the documents incorporated herein by reference.
YEAR ENDED DECEMBER NINE MONTHS ENDED 31, SEPTEMBER 30, ----------------------- ------------------- 1993 1994 1995(1) 1995(1) 1996 ------ ------ ------- ---------- -------- (UNAUDITED) (DOLLARS IN MILLIONS, EXCEPT PER SHARE AND SALES PRICE DATA) INCOME STATEMENT DATA (2): Revenues.......................... $106.1 $109.5 $128.0 $ 92.7 $ 136.1 Depreciation, depletion and amortization..................... 20.2 22.8 33.5 23.6 31.9 Interest expense(3)............... 0.7 0.9 4.6 3.3 3.2 Income (loss) before income taxes and cumulative effect of change in method of accounting for postretirement benefits.......... 21.0 16.4 (0.4) (3.1) 27.4 Net income (loss)................. 13.7 11.3 (2.2) (5.9) 17.0 Net income (loss) per share....... 0.55 0.46 (0.09) (0.23) 0.62 CASH FLOW STATEMENT DATA: Cash flow from operations before changes in working capital....... $ 40.5 $ 39.0 $ 33.4 $ 19.5 $ 57.5 Cash flow from operations after changes in working capital....... 41.6 36.6 35.5 16.5 62.7 Cash flow used in investing activities....................... 33.2 91.0 82.3 46.7 122.1 Cash flow provided by financing activities....................... 11.2 37.2 41.9 36.5 61.3 OTHER FINANCIAL DATA: EBITDA(4)......................... $ 41.2 $ 39.3 $ 37.0 $ 23.3 $ 61.7 Additions to property, plant and equipment........................ 45.5 95.6 82.8 46.9 124.1 EBITDA/Interest expense(5)........ 56.9x 37.1x 7.3x 6.4x 19.5x Ratio of earnings to fixed charges(6)....................... 20.3x 12.2x 0.9x 0.1x 8.8x RESERVE AND OPERATING DATA: Estimated proved reserves(7) Natural gas (Bcf)................ 364.8 458.8 513.5 -- -- Oil and condensate (MMBbls)...... 6.9 11.4 13.0 -- -- Total (Bcfe).................... 406.5 527.5 591.3 -- -- Present value of estimated future net revenues before future income taxes discounted at 10%(7)(8).... $277.6 $322.7 $432.6 -- -- Standardized measure of discounted net cash flows (9)............... $203.1 $242.6 $309.9 -- -- Production Natural gas (Bcf)................ 31.7 33.3 47.7 33.9 44.1 Oil and condensate (MMBbls)...... 1.3 1.3 1.7 1.3 1.4 Total (Bcfe)(7)................. 39.5 41.0 57.9 41.7 52.5 Reserves to production ratio (years)(7)....................... 10.3 12.9 10.2 -- -- Average sales price Natural gas ($/Mcf).............. $ 1.94 $ 1.83 $ 1.47 $ 1.48 $ 1.73 Oil and condensate ($/Bbl)....... 14.93 13.95 15.76 15.84 18.61
7
AS OF AS OF DECEMBER 31, SEPTEMBER 30, 1996 ------------------- ----------------------- 1994 1995 ACTUAL AS ADJUSTED (10) --------- --------- ------ ---------------- (UNAUDITED) (IN MILLIONS) BALANCE SHEET DATA: Cash and cash equivalents.......... $ 12.3 $ 7.5 $ 9.4 $ 143.6 Working capital.................... 2.5 3.7 2.0 136.2 Total assets....................... 311.0 340.4 472.1 610.1 Total debt......................... 53.0 89.0 12.0 150.0 Stockholders' equity............... 188.1 191.8 363.6 363.6 Total capitalization(11)........... 241.1 280.8 375.6 513.6
- -------- (1) Excluding 1995 nonrecurring transaction costs relating to the Plains merger totaling $14.2 million ($13.2 million for the nine months ended September 30, 1995), net income (loss) for the year ended December 31, 1995 and the nine months ended September 30, 1995 would be $9.5 million and $7.0 million, respectively, EBITDA would be $51.2 million and $36.5 million, respectively, and cash flow from operations before changes in working capital would be $47.6 million and $32.7 million, respectively. EBITDA and cash flow from operations before changes in working capital are not measures determined pursuant to generally accepted accounting principles ("GAAP") nor are they alternatives to GAAP income or cash flow provided by operations. See "Management's Discussion and Analysis of Financial Condition and Results of Operations." (2) Plains used the successful efforts method of accounting and adopted the full cost method used by Barrett in the retroactively restated financial statements. See Note 2 to the Consolidated Financial Statements. (3) Interest expense is net of capitalized interest of $0, $0.1 million and $0.4 million for the years ended December 31, 1993, 1994 and 1995, respectively, and $0.3 million and $0, for the nine months ended September 30, 1995 and 1996, respectively. On a pro forma basis, assuming the sale of the Notes and the application of a portion of the net proceeds therefrom to repay $70 million under the bank credit facility at the beginning of each period, interest expense would be $11.7 million for the year ended December 31, 1995 and $8.8 million for the nine months ended September 30, 1996. (4) EBITDA is defined as income before income taxes less interest income, plus interest expense, plus depreciation, depletion and amortization expense. EBITDA does not purport to reflect any measure of operations or cash flow. (5) Represents the ratio of EBITDA to interest expense. On a pro forma basis, assuming the sale of the Notes and the application of a portion of the net proceeds therefrom to repay $70 million under the bank credit facility at the beginning of each period, and excluding the nonrecurring 1995 merger costs, EBITDA/Interest expense would be 4.2x for the year ended December 31, 1995 and 7.0x for the nine months ended September 30, 1996. (6) For purposes of determining the ratio of earnings to fixed charges, earnings are computed as net income (loss) before income taxes, plus fixed charges. Fixed charges consist of interest expense, whether expensed or capitalized, on all indebtedness plus amortization of debt issuance costs. For the year ended December 31, 1995 and the nine months ended September 30, 1995, earnings were not sufficient to cover historical fixed charges due to the incurrence of $14.2 million of nonrecurring merger costs ($13.2 million for the nine months ended September 30, 1995). On a pro forma basis, assuming the sale of the Notes and the application of a portion of the net proceeds therefrom to repay $70 million under the bank credit facility at the beginning of each period, and excluding the nonrecurring 1995 merger costs, the ratio of earnings to fixed charges would be 1.7x for the year ended December 31, 1995 and 3.7x for the nine months ended September 30, 1996. (7) At December 31, 1996, the Company's estimated proved reserves were 674.9 Bcf of natural gas and 23.2 MMBbls of oil and condensate, for a total of 814.3 Bcfe with an implied reserve life of 11.3 years based on 1996 total production of 72.3 Bcfe. At December 31, 1996, the Present value of estimated future net revenues on a non-escalated basis was $1,121.5 million based on weighted average prices realized by the Company of $3.46 per Mcf of natural gas and $24.12 per Bbl of oil at December 31, 1996. (8) 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 and $1.77 per Mcf of natural gas and $17.35 per Bbl of oil at December 31, 1995. (9) 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%. (10) As adjusted to give effect to the issuance and sale of the $150,000,000 principal amount of the Notes and the application of net proceeds therefrom. See "Use of Proceeds" and "Management's Discussion and Analysis of Financial Condition and Results of Operations." (11) The sum of total debt and stockholders' equity. 8 RISK FACTORS In addition to the other information contained in this Prospectus, including but not limited to information under the heading "Disclosure Regarding Forward-Looking Statements," the following risk factors should be considered when evaluating an investment in the Notes offered hereby: VOLATILITY OF PRICES AND AVAILABILITY OF MARKETS The Company's revenues, profitability and future rate of growth are dependent in part upon prevailing prices for natural gas and oil, which can be extremely volatile. There can be no assurance that current price levels can be sustained. Prices also are affected by actions of state and local agencies, the United States and foreign governments, and international cartels. These external factors and the volatile nature of the energy markets make it difficult to estimate future prices of natural gas and oil. Any substantial or extended decline in the price of natural gas would have a material adverse effect on the Company's financial condition and results of operations, including reduced cash flow and borrowing capacity. All of these factors are beyond the control of the Company. The marketability of the Company's production depends in part upon the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities. Federal and state regulation of natural gas and oil production and transportation, general economic conditions, changes in supply and changes in demand all could adversely affect the Company's ability to produce and market its natural gas and oil. If market factors were to change dramatically, the financial impact on the Company could be substantial. For the year ended December 31, 1995, the Company's production and reserve base were approximately 82% and 87% natural gas, respectively, on an energy equivalent basis. For the year ended December 31, 1996, the Company's production and reserve base were approximately 84% and 83% natural gas, respectively, on an energy equivalent basis. As a result, the Company's earnings and cash flow are more sensitive to fluctuations in the price of natural gas than to fluctuations in the price of oil. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Business and Properties--Natural Gas and Oil Marketing and Trading." The Company engages in hedging activities with respect to some of its natural gas and oil production through a variety of financial arrangements designed to protect against price declines, including swaps. To the extent that Barrett engages in such activities, it may be prevented from realizing the benefits of price increases above the levels of the hedges. Risks related to hedging activities include the risk that counterparties to hedge transactions will default on obligations to the Company. The Company maintains a Risk Management Committee to oversee its production hedging and trading activities. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Business and Properties--Natural Gas and Oil Marketing and Trading." The Company reports its operations using the full cost method of accounting for natural gas and oil properties. Under full cost accounting rules, the net capitalized costs of natural gas and oil properties may not exceed a "ceiling" limit of the present value of estimated future net revenues from proved reserves, discounted at 10%, plus the lower of cost or fair market value of unproved properties. This rule requires calculating future revenues at unescalated prices in effect as of the end of each fiscal quarter and requires a write-down if the net capitalized costs of the natural gas and oil properties exceed the ceiling limit, even if price declines are temporary. The risk that the Company will be required to write-down the carrying value of its natural gas and oil properties increases when natural gas and oil prices are depressed or unusually volatile. A ceiling limitation write-down is a one-time charge to earnings, which does not impact cash flow from operating activities. OTHER INDUSTRY AND BUSINESS RISKS The Company competes in the areas of natural gas and oil exploration, production, development and transportation with other companies, many of which may have substantially greater financial and other resources. The nature of the natural gas and oil business also involves a variety of risks, 9 including the risks of operating hazards such as fires, explosions, cratering, blow-outs, encountering formations with abnormal pressures and, in horizontal wellbores, the increased risk of mechanical failure and collapsed holes, and damage or loss from adverse weather and seas, the occurrence of any of which could result in losses to the Company. The operation of the Company's natural gas processing plant and its natural gas gathering systems involves certain risks, including explosions and environmental hazards caused by pipeline leaks and ruptures. The effect of these hazards are increased with respect to the Company's Gulf of Mexico activities due to the difficulty of containing leaks and ruptures in offshore locations as well as hazards inherent in marine operations, such as capsizing, grounding, collision and damage from weather or sea conditions or unsound location. In accordance with customary industry practices, the Company maintains insurance against some, but not all, of these risks in amounts that management believes to be reasonable. The occurrence of a significant event that is not fully insured could have a material adverse effect on the Company's financial position. International operations are subject to certain risks, including expropriation of assets, governmental changes in applicable law, policies and contract terms, foreign government approvals, political instability, guerilla activity, payment delays, and currency exchange and repatriation losses. The Company's revenues depend on its level of success in acquiring or finding additional reserves. Certain areas in which the Company is engaged in, or planning, significant exploration and development activities are experiencing increased activity by other companies. This may result in shortages of, or delays in the availability of, drilling rigs and other equipment and increased costs as more users pursue available rigs. Except to the extent that the Company acquires properties containing proved reserves or conducts successful exploration and development activities, or both, the proved reserves of the Company will decline as reserves are produced. There can be no assurance that the Company's planned exploration and development projects will result in additional reserves or that the Company will have future success in drilling productive wells. Natural gas trading activities involve a high degree of risk because of the inherent uncertainties associated with the natural gas trading process. These uncertainties include the lack of predictability in natural gas prices, risk of non-performance by counterparties, market imperfections caused by regional price differentials, possible lack of liquidity in the trading markets and possible failure of physical delivery. Although the possibility of lower natural gas prices tends to add risk to the Company's exploration and development activities, it is the possibility of unexpected price volatility that represents a primary risk for the Company's natural gas trading activities. In addition, natural gas trading is highly competitive and the Company competes with several other companies, many of which have more experience, personnel and other resources available to them. However, the Company does not believe that any one competitor is dominant in the industry. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Business and Properties--Natural Gas and Oil Marketing and Trading." ENGINEERS' ESTIMATES OF RESERVES AND FUTURE NET REVENUES This Prospectus contains estimates of reserves and of future net revenues which have been prepared by the Company and have been reviewed by independent petroleum engineers. However, petroleum engineering is not an exact science and involves estimates based on many variable and uncertain factors. Estimates of reserves and of future net revenues prepared by different petroleum engineers may vary substantially depending, in part, on the assumptions made and may be subject to adjustment either up or down in the future. The actual amounts of production, revenues, taxes, development expenditures, operating expenses, and quantities of recoverable natural gas and oil reserves to be encountered may vary substantially from the engineers' estimates. Estimates of reserves also are extremely sensitive to the market prices for natural gas and oil. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Business and Properties--Reserves." 10 FUTURE CAPITAL NEEDS The Indenture under which the Notes will be issued restricts the Company's ability to grant liens. However, the Company will be able to incur substantial amounts of additional debt. Existing and possible future leverage of the Company poses risks to the holders of the Notes. These risks include higher interest rates on floating rate debt and the risk that the Company might not be able to generate sufficient cash to service or repay the Notes and its other existing and possible future debt and to adequately fund its capital expenditures. Existing and possible future leverage also may reduce the ability of the Company to respond to changing business and economic conditions, particularly the ability to make capital expenditures or to withstand competitive pressures. GOVERNMENT REGULATION AND ENVIRONMENTAL RISKS The production and sale of natural gas and oil are subject to a variety of federal, state and local government regulations that may be changed from time to time in response to economic or political conditions. The regulations concern, among other matters, the prevention of waste, the discharge of materials into the environment, the conservation of natural gas and oil, pollution, permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, the unitization and pooling of properties, and various other matters including taxes. The Company currently has a dispute with the Internal Revenue Service. Although the Company believes it will prevail in its position, there can be no assurance of a favorable outcome. See Note 11 to the Consolidated Financial Statements. Many jurisdictions have at various times imposed limitations on the production of natural gas and oil by restricting the rate of flow for natural gas and oil wells below their actual capacity to produce. In addition, many states have raised state taxes on energy sources and additional increases may occur, although there can be no certainty of the effect that increases in state energy taxes would have on natural gas and oil prices. Although the Company believes it is in substantial compliance with applicable environmental and other government laws and regulations and to date such compliance has not had a material adverse effect on the earnings or competitive position of the Company, there can be no assurance that significant costs for compliance will not be incurred in the future. Compliance with environmental laws, including the preparation of environmental assessments and impact statements, can delay drilling activity, thereby potentially reducing revenue and cash flow. See "Business and Properties--Core Areas of Activity--Rocky Mountain Region--Wind River Project" and "--Government Regulation of the Oil and Gas Industry." 11 USE OF PROCEEDS The net proceeds to the Company from the sale of the Notes are estimated to be $146.1 million after deducting underwriting discounts and estimated offering expenses payable by the Company. The Company intends to use these net proceeds to repay the outstanding balance on its bank credit facility, which had $85 million outstanding as of February 7, 1997 at an average interest rate of 6.08%. The remainder of the net proceeds will be used to fund a portion of the Company's planned exploration and development activities and for other general corporate purposes, including possible acquisitions. See "Capitalization," "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources," and "Business and Properties--Core Areas of Activity." The estimated amounts and uses set forth above indicate the Company's intentions for use of the net proceeds from the sale of the Notes. The Company may reallocate the proceeds or utilize the proceeds for other natural gas and oil opportunities the Company deems to be in its best interests, due to a change in circumstances concerning matters such as economic conditions, availability of additional debt financing or the existence of a property acquisition or development opportunity. The excess of net proceeds from the Offering after paying the outstanding balance of the Company's bank credit facility will be placed temporarily in certificates of deposit, short-term obligations of the United States government, or other money-market instruments that are rated investment grade or its equivalent until used for the purposes described above. To date, funds borrowed under the Company's bank credit facility, which matures on October 31, 2000, have been used primarily for the Company's natural gas and oil activities. Texas Commerce Bank is a lending agent under the Company's bank credit facility and is affiliated with Chase Securities Inc., one of the Underwriters of the Offering. See "Underwriting." 12 CAPITALIZATION The following table sets forth the capitalization of the Company as of September 30, 1996 and as adjusted to give effect to the sale of the Notes as of such date and the application of the net proceeds therefrom (assumed to be approximately $146.1 million) as described under "Use of Proceeds." This table should be read in conjunction with "Selected Consolidated Financial, Reserve and Operating Data," "Use of Proceeds," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Consolidated Financial Statements and notes thereto and other information included elsewhere in this Prospectus.
SEPTEMBER 30, 1996 -------------------- ACTUAL AS ADJUSTED ------- ----------- (IN MILLIONS) Cash and cash equivalents................................. $ 9.4 $ 143.6 ======= ======= Debt: Bank credit facility(1)................................. $ 12.0 $ -- Notes offered hereby.................................... -- 150.0 ------- ------- Total debt............................................ $ 12.0 $ 150.0 Stockholders' equity: Common stock, $.01 par value: 35,000,000 shares autho- rized, 31,319,193 issued and outstanding(2)............ 0.3 0.3 Additional paid-in capital.............................. 241.4 241.4 Retained earnings....................................... 122.8 122.8 Treasury stock, at cost................................. (1.0) (1.0) ------- ------- Total stockholders' equity............................ $ 363.6 $ 363.6 ------- ------- Total capitalization.................................. $ 375.6 $ 513.6 ======= =======
- -------- (1) As of December 31, 1996, the outstanding balance under the Company's bank credit facility was $70 million with interest at the average rate of 6.51% per annum, and as of February 7, 1997 the outstanding balance was $85 million with interest at the average rate of 6.08% per annum. See "Use of Proceeds," "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources" and Note 6 to Consolidated Financial Statements for certain terms of the Company's bank credit facility. (2) Does not include 1,338,892 shares of common stock issuable upon exercise of outstanding stock options. 13 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS On July 18, 1995, the Company consummated the 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. Also on July 18, 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. The pooling of interests method combines previously reported results as though the combination had occurred at the beginning of the periods being presented. Merger costs have been expensed during the 1995 year. The financial statements of the Company and Plains for 1993 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 Company or Plains. The following discussion should be read in conjunction with the Consolidated Financial Statements and Notes thereto presented elsewhere in this Prospectus. LIQUIDITY AND CAPITAL RESOURCES Capital Expenditures. Capital expenditures were $156 million for the nine months ended September 30, 1996 as compared to $47 million for the nine months ended September 30, 1995. Full year 1996 capital expenditures were approximately $235 million and the preliminary capital expenditure budget for 1997 is $278 million. Capital Sources. The Company's drilling activities and its acquisitions have increased its reserve base and its productive capacity and, therefore, its potential cash flow. The Company anticipates that funds available from the Company's operations, the Notes offered hereby and borrowings under the Company's bank credit facility will be sufficient to fund the capital expenditures described above. At September 30, 1996, the Company had cash and short-term investments of $9.4 million, working capital of $2.0 million, property and equipment of $422.2 million and total assets of $472.1 million. Compared to December 31, 1995, cash and short-term investments increased $1.9 million, working capital decreased $1.7 million and property and equipment increased $121.5 million. Total assets increased by $131.4 million, funded by the Company's cash flow and the issuance of 5.4 million shares of the Company's common stock in June 1996. As of December 31, 1996, as adjusted for the sale of the Notes and repayment of the $70 million outstanding under the bank credit facility, the Company's cash and cash equivalents will increase by $76.1 million. During the first nine months of 1996 and 1995, the Company generated operating cash flow of $57.5 million and $19.5 million, respectively, before working capital changes. After working capital changes, cash flow provided by operations was $62.7 million and $16.5 million, respectively. Excluding merger costs, cash flow from operations before working capital changes for the first nine months of 1995 was $32.7 million ($29.7 million after working capital changes). As of September 30, 1996 and December 31, 1995, respectively, the outstanding balance under the bank credit facility was $12 million and $89 million, as compared with $53 million at December 31, 1994. The Company's bank credit facility is an unsecured $200 million facility entered into by the Company in July 1995 with a consortium of six banks. The amount of borrowing base under the bank credit facility at any time is determined by the lenders with reference to the collateral value of the Company's proved reserves and the Company's projected cash requirements. The current borrowing base is $205 million, based on the banks' review of June 30, 1996 proved reserve information and the Company's projected cash requirements. Upon issuance of the Notes, representing $150 million of senior indebtedness of the Company, the borrowing base will be reduced to $75 million. Also upon the issuance of the Notes, the banks will cancel the guarantees of the bank credit facility by the Company's 14 subsidiaries, and the Company will undertake to merge or consolidate certain of its subsidiaries, including Plains Petroleum Operating Company, into or with the Company. At the Company's election at the time of borrowing funds, interest begins to accrue on those funds either at the London interbank eurodollar rate (LIBOR) plus a spread ranging from 0.5% to 1.0% (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. As of December 31, 1996, the outstanding balance under the bank credit facility was $70 million, which was accruing interest at an average rate of 6.51% per annum. As of February 7, 1997, the outstanding balance was $85 million with interest accruing at the average rate of 6.08% per annum. 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. The Company maintains a Risk Management Committee to oversee its production hedging and trading activities. See "Business and Properties-- Natural Gas and Oil Marketing and Trading." RESULTS OF OPERATIONS NINE MONTHS ENDED SEPTEMBER 30, 1996 AS COMPARED TO NINE MONTHS ENDED SEPTEMBER 30, 1995 The following discussion of operating results is based on historical consolidated financial information that has been restated to reflect the merger of the Company and Plains on July 18, 1995 under the pooling of interests method of accounting. Net income for the nine months ended September 30, 1996 was $17.0 million ($.62 per share) compared with a net loss of $5.9 million ($.23 per share) for the 1995 period. This increase is primarily due to increased natural gas and oil production revenue, a 17% increase in average natural gas sales prices, a 17% increase in average oil sales prices, a $1.3 million increase in gross profit from natural gas trading and the merger costs of $13.2 million that were incurred in the first nine months of 1995. Total revenues for the nine months ended September 30, 1996 were $136.1 million, an increase of 47% from $92.7 million for the same period in 1995. This increase is attributable to higher production revenues and a 52% increase in trading revenues. 15 Production revenues for the nine months ended September 30, 1996 increased 45% from $70.5 million to $102.4 million. Production revenues and related volumes and average prices during the periods presented were as follows:
NINE MONTHS ENDED SEPTEMBER 30, ----------------- 1996 1995 -------- -------- Natural Gas Revenues (in millions)...................... $ 76.4 $ 50.1 Natural Gas Production (Bcf)............................ 44.1 33.9 Average Price per Mcf................................... $ 1.73 $ 1.48 Oil Revenues (in millions).............................. $ 26.0 $ 20.4 Oil Production (MBbls).................................. 1,397 1,288 Average Price per Barrel................................ $ 18.61 $ 15.84
Natural gas revenues increased 53% during the nine months ended September 30, 1996 as compared with the same period in 1995, principally due to a 30% increase in production volumes and a 17% increase in average natural gas prices. The 28% increase for the nine months ended September 30, 1996 in oil revenues from the same period in 1995 is directly attributable to an 8% increase in production volumes and a 17% increase in average oil prices. For the nine months ended September 30, 1996, revenues from trading were $30.5 million compared with $20.2 million for the same period in 1995. The associated costs of trading increased to $28.4 million from $19.4 million due to the increase in natural gas trading volumes. Gross profit from trading was $2.1 million and $771,000 for the respective nine months ended September 30, 1996 and 1995. To reduce its exposure to natural gas and oil price fluctuations, the Company enters into hedging arrangements from time to time for both trading and producing activities. During the nine months ended September 30, 1996, the Company hedged approximately 21% of the Company's natural gas production at an average price of $1.99 per Mcf. For the fourth quarter of 1996, the Company hedged approximately 30% of the Company's natural gas production at an average price of $2.05 per Mcf. As of December 31, 1996, the Company held positions to hedge approximately 8.8 Bcf of the Company's future natural gas production at an average price of $1.87 per Mcf. In addition, during January 1997 the Company hedged 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 at an average price of $1.75 per Mcf and on February 10, 1997 the Company hedged an aggregate of an additional approximately 18.2 Bcf of natural gas production from the Rocky Mountain Region for the same period at an average price of $1.735 per Mcf. Production costs increased in the first nine months of 1996 compared to 1995 due to increases in sales and higher operating costs in the winter months in the first quarter of 1996. Depreciation, depletion and amortization increased to $31.9 million from $23.6 million due to a 26% increase in gas and oil equivalent production. During the 1996 and 1995 periods, depletion, depreciation and amortization was $.58 and $.53 per Mcfe, respectively. Interest expense for the nine months ended September 30, 1996 decreased from $3.3 million in 1995 to $3.2 million in 1996. This decrease is attributable to the repayment in June 1996 of the Company's debt under the bank credit facility with proceeds from the June 1996 common stock offering. The Company's largest source of operating income is from sales of its natural gas and oil production. Therefore, the levels of the Company's revenues and earnings are affected by prices at 16 which natural gas and oil are being sold. This is particularly true with respect to natural gas, which accounted for approximately 75% of the Company's production revenue for the nine months ended September 30, 1996. As a result, the Company's operating results for any prior period are not necessarily indicative of future operating results because of the fluctuations in natural gas and oil prices and the lack of predictability of those fluctuations as well as changes in production levels. YEAR ENDED DECEMBER 31, 1995 AS COMPARED TO YEAR ENDED DECEMBER 31, 1994 During 1995, the Company incurred a net loss of $2.2 million ($0.09 per share) compared to net income of $11.3 million ($0.46 per share) in 1994. The 1995 results include merger and reorganization costs of $14.2 million. Excluding these merger costs, the Company's net income after taxes would have been $9.5 million ($0.38 per share). Revenues increased 17% from 1994 to $128.0 million, and operating expenses, including $14.2 million of merger and reorganization costs, increased 38% to $128.4 million. Oil and natural gas production revenue increased 23% 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 primarily due to a 43% increase in natural gas production to 47.7 Bcf (130.7 MMcf per day). Oil production increased 32% to 1,702,000 barrels (4,660 barrels per day). Average natural gas sales prices decreased 20% to $1.47 per Mcf, while average oil prices increased 13% to $15.76 per barrel. Natural gas production accounted for 82% of total production on an energy equivalent basis. The Hugoton Embayment and Piceance Basin properties accounted for 37% and 14%, respectively, of total natural gas production. The Powder River and Permian Basins accounted for 43% and 32%, respectively, of total oil production. The decreased natural gas sales price was due to an overall deterioration in natural gas markets during most of the year. Lease operating expenses of $34.5 million was $0.60 per Mcfe compared to $0.69 per Mcfe in 1994. Depreciation, depletion and amortization increased $10.7 million primarily due to production increases. During 1995, depreciation, depletion and amortization on natural gas and oil production was provided at an average rate of $0.55 per Mcfe compared to an average rate of $0.52 per Mcfe in 1994. The gross margin on trading activities was virtually unchanged from 1994 at $943,000. Natural gas trading volumes increased 26% to 22.2 Bcf in 1995. During 1995, the Company hedged 4.9 Bcf (22%) of its natural gas trading volumes to lock in margins on specific transactions at a cost of $2.1 million. In addition, the Company hedged 11.0 Bcf (23%) of natural 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. The Company enters into the hedging arrangements to reduce its exposure to price risks associated with commodities markets. Although hedging transactions associated with its 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. At the end of December 1995, the basis differential between the commodities markets and the market price of the Company's natural gas widened to historically high levels. Because the increase in the commodities price was not accompanied by a similar increase in the market price of the Company's natural gas, the Company recorded an expense for the difference due to the inefficient hedge and positions that did not qualify for hedge accounting treatment. With respect to trading activities, the Company generally will not enter into a commitment for either a purchase or a sale unless (i) it has established a commitment for an offsetting sale or purchase, or (ii) it has established a hedge arrangement with a counter party that creates the same matching position. 17 General and administrative expenses of $13.4 million were 1% 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 companies' expenses, because 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. The Company expects to eliminate duplicative costs in 1996. Interest expense increased significantly from $0.9 million 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 Barrett and Plains and to integrate the separate companies' operations. 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. See "Underwriting." 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. The Company's results of operations depend primarily on the production of natural gas which accounted for 87% of the Company's reserves and 82% of its production during 1995. Therefore, the Company's future results will depend on both the volume of natural gas production and the sales price for gas. The Company continues to explore for natural gas and oil to increase its production. The lack of predictability of both production volumes and sales prices may influence future operating results. YEAR ENDED DECEMBER 31, 1994 AS COMPARED TO YEAR ENDED DECEMBER 31, 1993 During 1994, the Company earned net income of $11.3 million ($0.46 per share) compared to net income of $13.7 million ($0.55 per share) in 1993. The 1994 results include a tax benefit of $2.1 million due to an increase in financial reporting value of the Company's net operating loss carryover. Without the tax benefit from the net operating loss carryover, the Company's net income after taxes in 1994 would have been $9.2 million ($0.37 per share). The 1993 results include a tax benefit of $1.5 million from the value of the tax loss carryover and an expense of $656,000 for the cumulative effect of adopting Statement No. 106 of the Financial Accounting Standards Board to recognize accumulated postretirement benefit liabilities as of January 1, 1993. Net income before income taxes and the cumulative effect of the change in accounting method was $16.4 million in 1994 compared to $21.0 million in 1993. Revenues increased 3% from 1993 to $109.5 million, and operating expenses increased 9% to $93.0 million. Production revenue decreased $2.1 million, and trading revenues increased $5.2 million. These changes were offset by a decrease of $2.2 million in lease operating expenses, an increase of $2.6 million in depreciation, depletion and amortization and an increase of $5.5 million in the cost of trading. Production revenues decreased $2.1 million as a 5% increase in gas production was offset by a 6% decrease in the average natural gas sales price and a 7% decline in the average oil sales price. Oil production was virtually unchanged from 1993 to 1994. During 1994, the Company produced 91.2 MMcf of natural gas per day and 3.5 MBbls of oil per day. Natural gas production accounted for 81% of total production on an energy equivalent basis of 41.0 Bcfe. During 1994, the average natural gas sales price was $1.83 per Mcf ($1.94 in 1993) and the average oil sales price was $13.95 per barrel ($14.93 in 1993). The decreased natural gas and oil sales prices were due to an overall market reduction in the commodity prices of the products. Lease operating expenses of $28.2 million averaged $0.69 per Mcfe compared with $0.77 per Mcfe in 1993. Depreciation, depletion and amortization increased $2.6 million primarily due to production increases. During 1994, depreciation, depletion and amortization was $0.52 per Mcfe compared to $0.48 per Mcfe in 1993. 18 The gross margin on trading activities decreased to $924,000 from $1.3 million in 1993. Natural gas trading volumes increased 62% to 17.5 Bcf in 1994. The reduced results were due to a reduction of margins available for gas trading activities. General and administrative expenses of $13.3 million were 18% greater than the previous year. The 1994 amount is net of $3.4 million of operating fee recoveries compared to a $3.8 million recovery in 1993. The increased general and administrative expense was due to additional costs incurred by the Company to expand its activities and to explore in other areas. During 1994, the Company recorded a $5.1 million net income tax expense compared to a $6.7 net income tax expense in 1993. The 1994 expense is net of a $2.1 million reduction in the valuation allowance provided for the deferred income tax benefit of the net operating loss carryover. DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS This Prospectus 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 Prospectus, including without limitation statements under "Prospectus Summary," "Risk Factors," "Management's Discussion and Analysis of Financial Condition and Results of Operations," and "Business and Properties," 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 the "Risk Factors" section and elsewhere in this Prospectus. All written and oral forward-looking statements attributable to the Company or persons acting on its behalf subsequent to the date of this Prospectus are expressly qualified in their entirety by the Cautionary Statements. 19 BUSINESS AND PROPERTIES OVERVIEW 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 72.3 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. 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, 1996. As of September 30, 1996, the Company owned interests in 2,124 producing wells and operated 1,131 of these wells. These operated wells contributed approximately 82% of Barrett's natural gas and oil production for the nine months ended September 30, 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." BUSINESS STRATEGY Barrett's business strategy is to generate strong growth in reserves, production, earnings and cash flow through exploration, development and selective acquisitions of natural gas and oil properties in its core areas of activity. The Company implements this strategy through a series of continuing initiatives: SPECIALIZED GEOLOGIC EXPERTISE. Both the CEO and President of Barrett are experienced, practicing geologists. They have established a team of geologists and geophysicists with expertise in the Company's core areas of activity. Prior to undertaking projects in new areas, the Company assembles specialized geologic expertise to identify and evaluate drilling prospects. ACTIVE DRILLING PROGRAM. Barrett maintains a high quality, balanced portfolio of lower risk development projects complemented by higher potential exploration prospects. The Company's 20 preliminary 1997 capital expenditure budget is $278 million, approximately 75% of which is allocated to drilling and production activities. This budget, which is subject to revision based upon market conditions and other factors, contemplates that the Company will participate in drilling approximately 290 gross wells in 1997 as compared with 196 gross wells drilled in 1996. The Company expects to continue high levels of drilling activity after 1997. ADVANCED TECHNOLOGY. The Company makes extensive use of advanced technologies, including 3-D seismic and in-house analytical and processing capabilities, to better define drilling prospects. The Company also uses advanced production techniques, such as ASP technology, in its enhanced recovery operations. OPERATING CORE PROPERTIES. At September 30, 1996, Barrett served as operator for 1,131 wells, which contributed approximately 82% of the Company's production during the nine months ended September 30, 1996. As operator, the Company coordinates drilling activities and arranges for the production, gathering and sale of its natural gas and oil from operated wells. Serving as operator enables the Company to exert greater control over the cost and timing of its exploration, development and production activities. CONTINUING COST MANAGEMENT. The Company continually strives to reduce expenses through implementation of cost control programs and active management of its operations, personnel and administrative activities. Current cost management initiatives include entering into multi-well and longer term contracts with drilling companies and participating in alliances with oil field service companies to obtain more favorable terms. FINANCIAL STRENGTH. The Company is committed to maintaining financial flexibility in order to pursue exploration and development activities and to take advantage of other opportunities that may arise. Historically, the Company has funded its growth primarily through the issuance of common stock, including four public stock offerings, its 1995 stock-for-stock merger with Plains and several recent acquisitions financed with common stock. The issuance of the Notes adds ten-year fixed rate debt financing to the Company's capital structure, which will improve Barrett's liquidity, diversify its capital base and enhance the Company's ability to pursue its business strategy. SELECTIVE RESERVE AND LEASEHOLD ACQUISITIONS. From time to time the Company seeks to augment activities in its core areas, establish operations in new areas and build acreage positions for exploration prospects through selective acquisitions. As a result of acquisitions completed during 1996, the Company increased its working interests in the Piceance Basin, expanded its operations in the Uinta Basin and substantially increased its leased acreage position in the Gulf of Mexico. RECENT DEVELOPMENTS CAPITAL EXPENDITURES. The Company's preliminary 1997 capital expenditure budget for natural gas and oil activities is $278 million. Total estimated 1997 expenditures are allocated approximately 41% to the Gulf of Mexico Region, 25% to the Rocky Mountain Region, 19% to the Mid-Continent Region, 6% to international activities and 9% to possible acquisitions. This budget is subject to revision based upon market conditions and other factors. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "--Core Areas of Activities." OFFSHORE FEDERAL LEASE SALES. At the September 1996 Western Gulf of Mexico Offshore Lease Sale, the Company significantly expanded its position in the Gulf of Mexico. The MMS awarded the Company leases covering 17 blocks. 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. As a result of these transactions, Barrett holds interests in 46 lease blocks in the Gulf of Mexico covering approximately 185,000 gross acres. See "--Core Areas of Activity-- Gulf of Mexico Region." 21 UINTA BASIN ACQUISITIONS. In November 1996, the Company expanded its operations in the Uinta Basin of northeastern Utah when it 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 100,000 gross and 72,000 net acres of leasehold interests. The total purchase price was approximately $32 million, including approximately $14 million in cash, 50,000 shares of the Company's common stock, and certain non-strategic producing properties owned by the Company. In January 1997, the Company acquired additional interests in the Altamont-Bluebell Field for an aggregate purchase price of $3.5 million in cash. 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. See "--Core Areas of Activity--Rocky Mountain Region-- Uinta Basin." PARTICIPATION IN MARANON BASIN, PERU. In late January 1997, the Company entered into an agreement with industry partners that provided the Company with a license covering approximately 2.0 million gross acres located in the Maranon Basis of northeastern Peru. The Company and its partners intend to acquire and analyze 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. It is anticipated that the Company will be designated operator for operations in this area in mid-1997. See "--Core Areas of Activity--International Operations." CORE AREAS OF ACTIVITY [CORE AREAS OF ACTIVITY MAP APPEARS HERE] 22 The following table sets forth certain information concerning these core areas of activity:
PRELIMINARY AVERAGE DAILY 1997 ESTIMATED PROVED ESTIMATED PROVED PRODUCTION FOR CAPITAL RESERVES AT RESERVES AT THREE MONTHS ENDED EXPENDITURE BASIN OR FIELD DECEMBER 31, 1995 DECEMBER 31, 1996 SEPTEMBER 30, 1996 BUDGET -------------- ----------------- ----------------- ------------------ ------------- (BCFE) (BCFE) (MMCFE) (IN MILLIONS) Rocky Mountain Region Wind River............ 88.1 95.8 45.9 $ 25 Piceance.............. 119.1 201.7 32.3 25 Powder River.......... 30.0 32.0 16.5 6 Green River........... 12.5 14.8 1.5 1 Uinta................. 4.2 92.2 6.2 12 Mid-Continent Region Arkoma................ 27.4 26.7 12.6 18 Anadarko.............. 33.7 46.2 22.5 27 Hugoton Embayment..... 200.7 211.9 38.8 2 Permian............... 39.1 31.8 14.0 6 Gulf of Mexico Region... 8.7 23.8 4.5 114 International(1)........ -- -- -- 16 Other Natural Gas and Oil Activities(2)...... 27.8 37.4 6.6 26 ----- ----- ----- ---- Total............... 591.3 814.3 201.4 $278 ===== ===== ===== ====
- -------- (1) Consists of the Company's Republic of Peru project. (2) Reserves primarily located in northeastern Colorado, the Paradox Basin (Utah and Colorado) and Nevada. Also includes preliminary 1997 capital budget of $25 million for possible acquisitions. 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 Cave Gulch Federal Unit #1 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 September 30, 1996 was 42.9 MMcf of natural gas and 160 barrels of oil. In February 1997, the Company reached total depth on the Cave Gulch #16 deep test well, which was drilled to 19,106 feet 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 plans to run production casing and begin testing the well in mid-March 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 operators in the area. As a result, the Company drilled four wells in 1996, with the Cave Gulch #16 drilling at year-end. 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 23 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. The Company's natural gas production is currently constrained to a production rate of approximately 39 MMcf per day due to pipeline take-away capacity in the Cave Gulch area of operation and the Wind River Basin. 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 is in the process of starting up 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. Once fully operational, estimated to be in February 1997, the Company believes that this temporary facility will be able to increase its natural gas production in the Cave Gulch area to approximately 59 MMcf per day. See "--Natural Gas and Oil Marketing and Trading." 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 nine wells in 1997 to test the Muddy Formation. However, the BLM is imposing restrictions on winter drilling activities and drilling is not expected to resume 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 and one exploratory test well in the central portion of the Basin. At December 31, 1995, the Wind River Basin represented 15% of the Company's estimated proved reserves. At December 31, 1996, this Basin represented 12% of the Company's estimated proved reserves, and for the year ended December 31, 1996, it represented 21% of the Company's total production. In 1997, 9% of Barrett's preliminary 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 17 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 present, the Company owns interests in 297 wells and operates 285 wells in the Piceance Basin. 24 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. 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 Rulison, Grand Valley and Parachute 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 Grand Valley and Rulison Fields and are scheduled to be drilled in early 1997. 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, 1995, the Piceance Basin represented 20% of the Company's estimated proved reserves. At December 31, 1996, this Basin represented 25% of the Company's estimated proved reserves, and for the year ended December 31, 1996, it represented 14% of the Company's total production. The Company currently is continuously operating three drilling rigs in the Basin. In 1997, the Company intends to spend 9% of its preliminary capital expenditure budget in the Piceance Basin for development and exploration, including participating in drilling up to 56 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. 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 40% of the Company's daily oil production. The Company currently anticipates that additional activity will concentrate on development drilling and enhanced recovery projects utilizing 3-D seismic technology where appropriate. The Company has initiated or is planning the use of 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. At December 31, 1995, the Powder River Basin represented 5% of the Company's estimated proved reserves. At December 31, 1996, this Basin represented 4% of the Company's estimated proved reserves, and for the year ended December 31, 1996, it represented 8% of the Company's total 25 production. In 1997, the Company intends to spend 2% of its preliminary capital expenditure budget for development, enhanced recovery projects utilizing 3-D seismic technology, and exploration opportunities in the Powder River Basin, including participating in drilling up to 15 wells. GREEN RIVER BASIN/WYOMING OVERTHRUST. The Company owns leasehold interests within the greater Green River Basin, primarily in the Moxa Arch, Rock Springs Uplift and Wamsutter Arch areas, 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, 1995, the Green River Basin represented 2% of the Company's estimated proved reserves. At December 31, 1996, this Basin represented 2% of the Company's estimated proved reserves, and for the year ended December 31, 1996, it represented 2% of the Company's total production. In 1997, the Company intends to spend approximately $626,000 for capital expenditures in drilling up to six wells and recompleting three additional wells in the Green River Basin. 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 47% to 100% in 32 producing wells, a gathering and transmission system, and 40,000 gross acres, covering approximately 34,000 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 640 barrels of black wax crude oil per day. The Company plans extensive work in this Field during 1997, including a 15- 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 approximately 126,000 gross and 91,000 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 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. In 1997, the Company plans a 30 well recompletion/restimulation program and the drilling of six development and extension wells in the Uinta Basin. Expenditures for this activity in 1997 are expected to total $12 million, or 4% of the Company's preliminary capital expenditure budget. With this activity 26 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. 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 five areas of the Arkoma Basin in Oklahoma: South Panola 3-D area, Limestone Ridge area, Wilburton Field, the Choctaw Thrust 3-D area, and Alderson area. At December 31, 1995, the Arkoma Basin represented 5% of the Company's estimated proved reserves. At December 31, 1996, this Basin represented 3% of the Company's estimated proved reserves, and for year ended December 31, 1996, it represented 7% of the Company's total production. In 1997, the Company intends to spend 7% of its preliminary capital expenditure budget for drilling in the Arkoma Basin, including participating in drilling up to 22 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 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 play and the Sentinel Field area. At December 31, 1995, the Anadarko Basin represented 6% of the Company's estimated proved reserves. At December 31, 1996, this Basin represented 6% of the Company's estimated proved reserves, and for the year ended December 31, 1996, it represented 11% of the Company's total production. The Company plans to spend 10% of its preliminary 1997 capital expenditure budget in the Anadarko Basin for development and exploration drilling, including participating in drilling up to 60 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. At December 31, 1995, the Hugoton Embayment represented 34% of the Company's estimated proved reserves. At December 31, 1996, this Basin represented 26% of the Company's estimated proved reserves, and for the year ended December 31, 1996, it represented 21% of the Company's total production. Hugoton and Guymon-Hugoton Fields. In the Hugoton and Guymon-Hugoton Fields, the Company has working interests in 359 gross wells and operates 314 of them. The Hugoton and the Guymon-Hugoton Fields produce from the Chase Formation. Six wells were drilled in the Hugoton Field in 1996, three of which are on production and the remaining three of which are expected to begin production in February 1997. 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 55 gross Panoma wells and operates 51 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 27 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 gross recoverable natural gas reserves decline to 50 Bcf or less. As of December 31, 1995, the gross proved natural gas reserves attributable to the leases burdened by this agreement were estimated to be 176.4 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. Barrett intends to spend $2 million of its preliminary 1997 capital expenditure budget on the Hugoton Embayment for development drilling and increased deliverability through compression, including participating in drilling eight 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 224 gross wells (170 net wells) located in the Permian Basin, which produce approximately 2,200 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, 1995, the Permian Basin represented 7% of the Company's estimated proved reserves. At December 31, 1996, this Basin represented 4% of the Company's estimated proved reserves, and for the year ended December 31, 1996, it represented 7% of the Company's total production. Barrett intends to spend 2% of its preliminary 1997 capital expenditure budget in the Permian Basin, including participating in drilling up to 31 wells. If a pending down- spacing request regarding the Spraberry Trend area is approved, which would allow an optional well on each existing 80 acre well site, the Company intends to drill approximately 15 additional infill wells in 1997. 28 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 offshore Louisiana and Texas. The Company believes that this area has significant reserve potential and is well suited to its 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, 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 Sale in September 1996. The Company was high bidder on 19 blocks in water depths ranging from 33 feet to 315 feet. The MMS awarded the Company leases covering 17 of these blocks. 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. The MMS rejected the two remaining high bids submitted by the Company because the MMS deemed these bids insufficient. In 1996, the Company participated in 15 Gulf of Mexico wells, 12 of which were successful. The preliminary 1997 Gulf of Mexico capital expenditure budget is estimated at $114 million to drill 31 wells, acquire additional 3-D seismic for future prospects, lease additional future prospects and to put into production eight wells drilled in 1996. This amount represents 41% of the Company's preliminary 1997 capital expenditure budget. At December 31, 1995, the Gulf of Mexico represented 1% of the Company's estimated proved reserves. At December 31, 1996, the Gulf of Mexico represented 3% of the Company's estimated proved reserves, and for the year ended December 31, 1996, it represented 3% of the Company's total production. INTERNATIONAL OPERATIONS With an industry partner, the Company obtained in November 1996 a license to evaluate, explore and develop 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%. Pursuant to the license, the Republic of Peru receives a variable royalty payment on production that is anticipated to average approximately 23%. 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. 29 In late January 1977, the Company entered into an agreement with industry partners that provided the Company with a license covering approximately 2.0 million gross acres located in the Maranon Basin of northeastern Peru. The Company and its partners intend to acquire and analyze 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 this area in mid-1997. Estimated capital expenditures for international operations for 1997 constitute approximately 6% of the Company's preliminary capital expenditure budget. 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. See "Risk Factors-- Volatility of Prices and Availability of Markets" and "--Other Industry and Business Risks." 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 October 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 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 transportation arrangements to support future expansions of Rocky Mountain interstate pipelines. These expansions are 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 terms ranging from five years to 10 years. These expansions are subject to Federal Energy Regulatory Commission ("FERC") approval and are 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. 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. 30 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. On February 10, 1997, the Company entered into a transaction to hedge an aggregate of an additional approximately 18.2 Bcf of natural gas production from the Rocky Mountain Region for the same five-year period. For the year ended December 31, 1995, revenues from trading activities, which includes the cost of natural gas purchased or sold for trading purposes, were $28.6 million, which constituted 22% of the Company's consolidated revenues and generated a gross margin of $943,000. For the nine months ended September 30, 1996, revenues from trading activities were $30.5 million, which constituted 22% of the Company's consolidated revenues and generated a gross margin of $2.1 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 $26.0 million for the nine months ended September 30, 1996 and represented 19% of the Company's total revenues for that period. The Company does not engage in oil trading activities. PRODUCTION The table below sets forth information with respect to the Company's net interests in producing natural gas and oil properties for each of its last three years and for the nine months ended September 30, 1996 and 1995, respectively:
NATURAL GAS AND OIL PRODUCTION ---------------------------------- NINE MONTHS YEAR ENDED ENDED DECEMBER 31, SEPTEMBER 30, -------------------- ------------- 1993 1994 1995 1995 1996 ------ ------ ------ ------ ------ Quantities Produced and Sold Natural gas (Bcf).......................... 31.7 33.3 47.7 33.9 44.1 Oil and condensate (MMBbls)................ 1.3 1.3 1.7 1.3 1.4 Average Sales Price Natural gas ($/Mcf)........................ $ 1.94 $ 1.83 $ 1.47 $ 1.48 $ 1.73 Oil and condensate ($/Bbl)................. 14.93 13.95 15.76 15.84 18.61 Average Production Costs/Mcfe............... $ 0.77 $ 0.69 $ 0.60 $ 0.61 $ 0.65
31 PRODUCTIVE WELLS AND DEVELOPED ACREAGE 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 DEVELOPED ACREAGE ------------ ------------ ----------------- GROSS NET GROSS NET GROSS NET ----- ------ ----- ------ ----------------- Rocky Mountain Region Wind River............. 462 23.24 0 0.00 5,115 3,411 Piceance............... 308 161.31 0 0.00 36,560 20,336 Powder River........... 39 3.25 335 80.74 42,848 26,319 Green River............ 45 22.64 3 1.80 22,055 7,038 Uinta.................. 1 .78 135 115.58 97,580 60,940 Mid-Continent Region Arkoma................. 121 32.06 0 0.00 51,200 14,450 Anadarko............... 149 64.89 13 12.60 83,265 49,920 Hugoton Embayment...... 412 347.80 0 0.00 88,332 84,946 Permian................ 54 17.63 210 145.69 45,701 15,143 Gulf of Mexico Region... 21 5.86 3 1.00 34,765 9,255 Other................... 88 60.84 74 5.78 41,225 28,209 ----- ------ --- ------ -------- -------- Total.................. 1,203 640.87 854 332.27 548,646 319,967 ===== ====== === ====== ======== ========
- -------- (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 .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. 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 certain portions having been reviewed by Ryder Scott Company, an independent reservoir engineer, and the other portions having been 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 32 engineers; however, on a well by well basis, differences of greater than 10% may exist. See "Risk Factors--Engineers' Estimates of Reserves and Future Net Revenues."
ESTIMATED PROVED RESERVES ------------------------------------------------ DECEMBER 31, ------------------------------------------------ 1993 1994 1995 1996 ----------- ----------- ----------- ------------ (DOLLARS IN MILLIONS EXCEPT SALES PRICE DATA) Estimated Proved Reserves(1): Natural gas (Bcf).......... 364.8 458.8 513.5 674.9 Oil and condensate (MMBbls).................. 6.9 11.4 13.0 23.2 Total (Bcfe)............. 406.5 527.5 591.3 814.3 Proved developed reserves (Bcfe)...................... 375.6 440.1 489.7 606.3 Natural gas price as of De- cember 31 ($/Mcf)........... $ 1.95 $ 1.67 $ 1.77 $ 3.46 Oil price as of December 31 ($/Bbl)..................... $ 11.05 $ 14.43 $ 17.35 $ 24.12 Present value of estimated future net revenues before future income taxes discounted at 10%(2)...... $ 277.6 $ 322.7 $ 432.6 $ 1,121.5 Standardized measure of discounted net cash flows(3).................... $ 203.1 $ 242.6 $ 309.9 --
- -------- (1) The Company's annual reserve reports were prepared by the Company. With respect to the reserve estimates as of and prior to December 31, 1995, certain portions of the reserve report were reviewed by Ryder Scott Company, an independent reservoir engineer. The remaining portions of these reports concerning the reserves that are held by the Company's Plains subsidiary were reviewed or prepared by Netherland, Sewell & Associates, Inc., an independent reservoir engineering firm that reviewed Plains' reserve reports from 1988 through 1995. (2) 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. (3) 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 Prospectus 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 33 containing proved reserves or conducts successful exploration and development activities, or both, the proved reserves of the Company will decline as reserves are produced. Volumes generated from future activities of the Company are therefore highly dependent upon the level of success in acquiring or finding additional reserves and the costs incurred in doing so. Reference should be made to "Supplemental Gas and Oil Information" on pages F-23 and F-24 following the Consolidated Financial Statements included in this Prospectus for additional information pertaining to the Company's proved natural gas and oil reserves as of the end of each of the last three fiscal 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 Prospectus as compared to those in the EIA report. UNDEVELOPED ACREAGE The gross and net acres of 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.
UNDEVELOPED ACREAGE(1) ----------------- UNITED STATES - --------------------------------------------------------- GROSS NET - --------------------------------------------------------- --------- ------- Colorado (Piceance and other basins)..................... 125,506 59,035 Oklahoma (Anadarko and Arkoma Basins).................... 75,429 65,706 Texas (Permian Basin).................................... 5,952 1,313 Utah (Uinta Basin)....................................... 57,168 44,346 Wyoming (Wind River, Greater Green River, Powder River and other basins)................................................. 228,257 157,244 Gulf of Mexico .......................................... 179,791 114,093 Other.................................................... 16,050 7,537 INTERNATIONAL - --------------------------------------------------------- Peru..................................................... 820,000 451,000 --------- ------- Total.................................................. 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. 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: 34
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. GOVERNMENT REGULATION OF THE OIL AND GAS INDUSTRY GENERAL The Company's exploration, production and marketing operations are regulated extensively at the federal, state and local levels. Natural gas and oil exploration, development and production activities are subject to various laws and regulations governing a wide variety of matters. For example, hydrocarbon- producing states have statutes or regulations addressing conservation practices and the protection of correlative rights, and such regulations may affect the Company's operations and limit the quantity of hydrocarbons the Company may produce and sell. Other regulated matters include marketing, pricing, transportation, and valuation of royalty payments. Certain operations the Company conducts are on federal oil and gas leases, which the MMS administers. The MMS issues such leases through competitive bidding. These leases contain relatively standardized terms and require compliance with detailed MMS regulations and orders pursuant to the Outer Continental Shelf Lands Act ("OCSLA"), which are subject to change by the MMS. For offshore operations, lessees must obtain MMS approval for exploration plans and development and production plans prior to the commencement of such operations. In addition to permits required from other agencies (such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency), lessees must obtain a permit from the MMS prior to the commencement of drilling. The MMS has promulgated regulations requiring offshore production facilities located on the OCS to meet stringent engineering and construction specifications. The MMS proposed additional safety-related regulations concerning the design and operating procedures for OCS production platforms and pipelines. These proposed regulations were withdrawn pending further discussions among interested federal agencies. The MMS also has issued regulations restricting the flaring or venting of natural gas and liquid hydrocarbons without prior authorization. Similarly, the MMS has promulgated regulations governing the plugging and abandonment of wells located offshore and the removal of all production facilities. To cover the various obligations of lessees on the OCS, the MMS generally requires that lessees post substantial bonds or other acceptable assurances that such obligations will be met. The cost of such bonds or other surety can be substantial and there is no assurance that bonds or other surety can be obtained in all cases. Under certain circumstances, the MMS may require any Company operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect the Company's financial condition and operations. 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." 35 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. 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. See "Risk Factors--Government Regulation and 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. EMPLOYEES AND OFFICES The Company currently has 179 full time employees, including 12 officers (five of whom are geologists and two of whom are petroleum engineers), 14 geologists, six geophysicists, 13 engineers, 36 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. MANAGEMENT The directors and executive officers of the Company, their respective positions and ages, 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 68 Chief Executive Officer, Chairman of the 1983 (1)(2)(3).............. Board, and a Director C. Robert Buford 63 1983 (4)(5)................. Director Derrill Cody (4)(5)..... 58 Director 1995 James M. Fitzgibbons 62 1987 (4)(5)(6).............. Director Hennie L.J.M. Gieskes 57 1985 (4)(5)................. Director William W. Grant, III 64 1995 (4).................... Director J. Frank Keller (1)..... 53 Chief Financial Officer, Executive Vice 1983 President, Secretary, and a Director Paul M. Rady............ 43 President, Chief Operating Officer, and a 1994 Director A. Ralph Reed........... 59 Executive Vice President--Operations and a 1990 Director James T. Rodgers 62 1993 (4)(5)................. Director Philippe S.E. Schreiber 56 1985 (4)(5)................. Director Harry S. Welch (5)...... 73 Director 1995 Joseph P. Barrett (2)... 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........ 37 Vice President--Marketing -- Robert W. Howard........ 42 Senior Vice President--Finance and -- Treasurer Eugene A. Lang, Jr...... 43 Senior Vice President--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) William J. Barrett and J. Frank Keller are brothers-in-law. (2) Joseph P. Barrett is the son of William J. Barrett. (3) William J. Barrett's retirement plans include remaining as Chairman of the Board until January 1999 and remaining as Chief Executive Officer until the Company's 1997 Annual Meeting of Stockholders. (4) Member of the Audit Committee of the Board of Directors. (5) Member of the Compensation Committee of the Board of Directors. (6) James M. Fitzgibbons served as a director of the Company from July 1987 until October 1992. He was reelected to the Board of Directors in January 1994. 37 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 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 the Company's 1997 Annual Meeting of Stockholders. 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 First Bancorp of Wichita, Kansas, a bank holding company, and Lonestar Steakhouse & Saloon, Inc., a restaurant company headquartered in Wichita, Kansas. 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 Insurance Company, American Textile Manufacturers Institute and a Trustee of 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. 38 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 an Executive Vice President of the Company from December 1983 through September 1995. 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. Prior to that time 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. A. RALPH REED has been an Executive Vice President of the Company since November 1989 and a director of the Company 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, a wholly owned exploration and production subsidiary of United Energy Resources, Inc. Prior to joining Cotton Petroleum Corporation 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. From October 1985 through June 1992, Mr. Schreiber served as a director, and from July 1990 until June 1991 as Managing Director, of Owl Creek Investments Plc, a publicly traded English oil and gas company. 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. 39 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 General Manager of the Gulf of Mexico Region for the Company since January 1996 and Vice President-General Manager of the Gulf of Mexico Region for the Company since June of 1996. Prior to joining the Company, Mr. Foss served from January 1973 to 1996 in various positions with Cockrell Oil Corporation as Geologist, District Geologist, Exploration Manager and Vice President of Exploration and Exploitation. 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. ROBERT W. HOWARD has been Senior Vice President of the Company since March 1992. Mr. Howard served as the Executive Vice President--Finance from December 1989 until March 1992 and served as Vice President--Finance of the Company from December 1983 until December 1989. Mr. Howard has been the Treasurer of the Company since March 1986. During 1982, Mr. Howard was a Manager/Accountant with Weiss & Co., a certified public accounting firm. EUGENE A. LANG, JR. has been Senior Vice President--General Counsel of the Company since September 1995. 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 Division since July 1996. From October 1991 to July 1996 Mr. Storm was retained by the Company as a consultant to develop drilling opportunities in the Anadarko and Arkoma Basins. From September 1984 through October 1991 Mr. Storm worked for other independent exploration and production companies in various exploration geologist and management positions. 40 BENEFICIAL OWNERS OF SECURITIES The following table summarizes certain information as of January 28, 1997 with respect to the ownership by each director, 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 5% of the Common Stock:
NUMBER OF SHARES NAME OF BENEFICIAL OWNER BENEFICIALLY OWNED PERCENT OF CLASS ------------------------ ------------------ ---------------- William J. Barrett....................... 390,172(1) 1.2% C. Robert Buford......................... 652,366(2) 2.1% Derrill Cody............................. 12,560(3) * James M. Fitzgibbons..................... 11,000(3) * Hennie L.J.M. Gieskes.................... 898,714(3) 2.9% William W. Grant, III.................... 25,650(3) * J. Frank Keller.......................... 74,036(3) * Eugene A. Lang, Jr....................... 49,852(3) * Paul M. Rady............................. 78,122(3) * A. Ralph Reed............................ 80,328(4) * James T. Rodgers......................... 11,500(3) * Philippe S.E. Schreiber.................. 19,507(3) * Harry S. Welch........................... 19,300(3) * All Directors and Executive Officers as a Group (20 persons)...................... 2,410,993(5) 7.6% Fidelity Management and Research Corporation 82 Devonshire Street Boston, MA 02109........................ 3,300,000(6) 10.5% State Farm Mutual Automobile Insurance Company and affiliates One State Farm Plaza Bloomington, IL 61710................... 2,278,233(6)(7) 7.3%
- -------- * Less than 1% of the Common Stock outstanding. (1) The number of shares indicated includes 36,292 shares owned by Louise K. Barrett, Mr. Barrett's wife, 230,000 shares owned by the Barrett Family L.L.L.P., a Colorado limited partnership for which Mr. Barrett and his wife are general partners and owners of an aggregate of 62.9% of the partnership interests, and 55,000 shares underlying options that currently are exercisable or become exercisable within the next 60 days. Pursuant to Rule 16a-1(a)(4) under the Exchange 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% of the outstanding common stock of Zenith. The number of shares of the Company's stock indicated for Mr. Buford also includes 10,000 shares that are owned by Aguilla Corporation, which is owned by Mr. Buford's wife and adult children. Mr. Buford disclaims beneficial ownership of the shares held by Aguilla Corporation pursuant to Rule 16a-1(a)(4) under the Exchange Act. The number of shares indicated also includes 10,500 shares underlying options currently exercisable. 41 (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, 12,300; James M. Fitzgibbons, 9,000; Hennie L.J.M. Gieskes, 9,500; William W. Grant, III, 15,900; J. Frank Keller, 32,300; Eugene A. Lang, Jr., 43,259; Paul M. Rady, 48,000; James T. Rodgers, 11,500; Philippe S.E. Schreiber, 9,500; and Harry S. Welch, 16,700. (4) The number of shares indicated includes 10,150 shares owned by Mary C. Reed, Mr. Reed's wife and 45,048 shares underlying options that currently are exercisable or that become exercisable within the next 60 days. (5) The number of shares indicated includes the shares owned by Zenith that are beneficially owned by Mr. Buford as described in note (2), the aggregate of 318,507 shares underlying the options described in notes (1), (2), (3) and (4), an aggregate of 25,086 shares owned by seven executive officers not named in the above table, and an aggregate of 62,800 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 Commission by the named stockholder 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 Exchange Act. 42 DESCRIPTION OF NOTES The Notes will be issued pursuant to an Indenture to be dated as of February 1, 1997 (the "Indenture") among the Company, and Bankers Trust Company, as trustee (the "Trustee"), a copy of the form of which is filed as an exhibit to the Registration Statement of which this Prospectus is a part. The following summaries of certain provisions of the Notes and the Indenture do not purport to be complete and are subject to, and are qualified in their entirety by reference to, the Notes and the Indenture, including the definitions therein of certain capitalized terms used but not defined herein. GENERAL Each Note will mature on February 1, 2007 and will bear interest at the rate per annum stated on the cover page hereof from February 1, 1997 payable semiannually on February 1 and August 1 of each year, commencing August 1, 1997, to the person in whose name the Note is registered at the close of business on the January 15 or July 15 preceding such interest payment date. Interest will be computed on the basis of a 360-day year of twelve 30-day months. Principal and interest will be payable at the offices of the Trustee and the Paying Agent. In addition, in the event the Notes do not remain in book-entry form, at the option of the Company payment of interest will be made by check mailed to the address of the person entitled thereto as it appears in the register of the Notes (the "Note Register") maintained by the Registrar. The aggregate principal amount of the Notes that may be issued will be limited to $150,000,000. The Notes will be transferable and exchangeable at the office of the Registrar and any co-registrar and will be issued in fully registered form, without coupons, in denominations of $1,000 and any whole multiple thereof. The Company may require payment of a sum sufficient to cover any tax or other governmental charge payable in connection with certain transfers and exchanges. The Notes will be senior unsecured obligations of the Company and will rank pari passu in right of payment with the Company's obligations under all existing and future senior unsecured indebtedness of the Company (including the bank credit facility) and senior in right of payment to all existing and future indebtedness of the Company that is, by its terms, expressly subordinated to the Notes. OPTIONAL REDEMPTION The Notes will be redeemable, at the option of the Company, at any time in whole or from time to time in part, upon not less than 30 and not more than 60 days' notice mailed to each holder of Notes to be redeemed at the holder's address appearing in the Note Register, on any date prior to maturity at a price equal to 100% of the principal amount thereof plus accrued interest to the Redemption Date (subject to the right of holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the Redemption Date) plus a Make-Whole Premium, if any (the "Redemption Price"). In no event will the Redemption Price ever be less than 100% of the principal amount of the Notes plus accrued interest to the Redemption Date. The amount of the Make-Whole Premium with respect to any Note (or portion thereof) to be redeemed will be equal to the excess, if any, of: (i) the sum of the present values, calculated as of the Redemption Date, of: A. each interest payment that, but for such redemption, would have been payable on the Note (or portion thereof) being redeemed on each Interest Payment Date occurring after the Redemption Date (excluding any accrued interest for the period prior to the Redemption Date); and B. the principal amount that, but for such redemption, would have been payable at the final maturity of the Note (or portion thereof) being redeemed; over (ii)the principal amount of the Note (or portion thereof) being redeemed. 43 The present values of interest and principal payments referred to in clause (i) above will be determined in accordance with generally accepted principles of financial analysis. Such present values will be calculated by discounting the amount of each payment of interest or principal from the date that each such payment would have been payable, but for the redemption, to the Redemption Date at a discount rate equal to the Treasury Yield (as defined below) plus 25 basis points. The Make-Whole Premium will be calculated by an independent investment banking institution of national standing appointed by the Company; provided, that if the Company fails to make such appointment at least 45 business days prior to the Redemption Date, or if the institution so appointed is unwilling or unable to make such calculation, such calculation will be made by Goldman, Sachs & Co. or, if such firm is unwilling or unable to make such calculation, by an independent investment banking institution of national standing appointed by the Trustee (in any such case, an "Independent Investment Banker"). For purposes of determining the Make-Whole Premium, "Treasury Yield" means a rate of interest per annum equal to the weekly average yield to maturity of United States Treasury Notes that have a constant maturity that corresponds to the remaining term to maturity of the Notes, calculated to the nearest 1/12th of a year (the "Remaining Term"). The Treasury Yield will be determined as of the third business day immediately preceding the applicable Redemption Date. The weekly average yields of United States Treasury Notes will be determined by reference to the most recent statistical release published by the Federal Reserve Bank of New York and designated "H.15(519) Selected Interest Rates" or any successor release (the "H.15 Statistical Release"). If the H.15 Statistical Release sets forth a weekly average yield for United States Treasury Notes having a constant maturity that is the same as the Remaining Term, then the Treasury Yield will be equal to such weekly average yield. In all other cases, the Treasury Yield will be calculated by interpolation, on a straight-line basis, between the weekly average yields on the United States Treasury Notes that have a constant maturity closest to and greater than the Remaining Term and the United States Treasury Notes that have a constant maturity closest to and less than the Remaining Term (in each case as set forth in the H.15 Statistical Release). Any weekly average yields so calculated by interpolation will be rounded to the nearest 1/100th of 1%, with any figure of 1/200% or above being rounded upward. If weekly average yields for United States Treasury Notes are not available in the H.15 Statistical Release or otherwise, then the Treasury Yield will be calculated by interpolation of comparable rates selected by the Independent Investment Banker. If less than all of the Notes are to be redeemed, the Trustee will select the Notes to be redeemed by such method as the Trustee shall deem fair and appropriate. The Trustee may select for redemption Notes and portions of Notes in amounts of $1,000 or whole multiples of $1,000. The Notes will not be entitled to the benefit of any sinking fund or other mandatory redemption provisions. CERTAIN COVENANTS LIMITATION ON LIENS. Nothing in the Indenture or the Notes will in any way limit the amount of indebtedness or securities (other than the Notes) that the Company or any of its Subsidiaries may incur or issue. The Indenture will provide that the Company will not, and will not permit any Restricted Subsidiary to, issue, assume or guarantee any Indebtedness for borrowed money secured by any Lien on any property or asset now owned or hereafter acquired by the Company or such Restricted Subsidiary without making effective provision whereby any and all Notes then or thereafter outstanding will be secured by a Lien equally and ratably with any and all other obligations thereby secured for so long as any such obligations shall be so secured. 44 The foregoing restriction will not, however, apply to: (a) Liens existing on the date on which the Notes are originally issued or provided for under the terms of agreements existing on such date; (b) Liens on property securing (i) all or any portion of the cost of exploration, drilling or development of such property, (ii) all or any portion of the cost of acquiring, constructing, altering, improving or repairing any property or assets, real or personal, or improvements used or to be used in connection with such property or (iii) Indebtedness incurred by the Company or any Restricted Subsidiary to provide funds for the activities set forth in clauses (i) and (ii) above; (c) Liens securing Indebtedness owed by a Restricted Subsidiary to the Company or to any other Restricted Subsidiary; (d) Liens on property existing at the time of acquisition of such property by the Company or a Subsidiary or Liens on the property of any corporation or other entity existing at the time such corporation or other entity becomes a Restricted Subsidiary of the Company or is merged with the Company in compliance with the Indenture and in either case not incurred as a result of (or in connection with or in anticipation of) the acquisition of such property or such corporation or other entity becoming a Restricted Subsidiary of the Company or being merged with the Company, provided that such Liens do not extend to or cover any property or assets of the Company or any of its Restricted Subsidiaries other than the property so acquired; (e) Liens on any property securing (i) Indebtedness incurred in connection with the construction, installation or financing of pollution control or abatement facilities or other forms of industrial revenue bond financing or (ii) Indebtedness issued or guaranteed by the United States or any State thereof or any department, agency or instrumentality of either; (f) any Lien extending, renewing or replacing (or successive extensions, renewals or replacements of) any Lien of any type permitted under clauses (a) through (e) above, provided that such Lien extends to or covers only the property that is subject to the Lien being extended, renewed or replaced; (g) certain Liens arising in the ordinary course of business of the Company and the Restricted Subsidiaries; (h) any Lien resulting from the deposit of moneys or evidences of indebtedness in trust for the purpose of defeasing Indebtedness of the Company or any Subsidiary; or (i) Liens (exclusive of any Lien of any type otherwise permitted under clauses (a) through (h) above) securing Indebtedness of the Company or any Restricted Subsidiary in an aggregate principal amount which, together with the aggregate amount of Attributable Indebtedness deemed to be outstanding in respect of all Sale/Leaseback Transactions entered into pursuant to clause (a) of the covenant described under "Limitation on Sale/Leaseback Transactions" below (exclusive of any such Sale/Leaseback Transactions otherwise permitted under clauses (a) through (h) above), does not at the time such Indebtedness is incurred exceed 5% of the Consolidated Net Tangible Assets of the Company (as shown in the most recent audited consolidated balance sheet of the Company and its Subsidiaries). The following types of transactions will not be prohibited or otherwise limited by the foregoing covenant: (i) the sale, granting of Liens with respect to, or other transfer of, crude oil, natural gas or other petroleum hydrocarbons in place for a period of time until, or in an amount such that, the transferee will realize therefrom a specified amount (however determined) of money or of such crude oil, natural gas or other petroleum hydrocarbons; (ii) the sale or other transfer of any other interest in property of the character commonly referred to as a production payment, overriding royalty, forward sale or similar interest; (iii) the entering into of Currency Hedge Obligations, Interest Rate Hedging Agreements or Oil and Gas Hedging Contracts although Liens securing any Indebtedness for borrowed money that is the subject of any such obligation shall not be permitted hereby unless permitted under 45 clauses (a) through (i) above; and (iv) the granting of Liens required by any contract or statute in order to permit the Company or any Restricted Subsidiary to perform any contract or subcontract made by it with or at the request of the United States or any State thereof or any department, agency or instrumentality of either, or to secure partial, progress, advance or other payments to the Company or any Restricted Subsidiary by such governmental unit pursuant to the provisions of any contract or statute. LIMITATION ON SALE/LEASEBACK TRANSACTIONS. The Indenture will provide that the Company will not, and will not permit any Restricted Subsidiary to, enter into any Sale/Leaseback Transaction with any person (other than the Company or a Restricted Subsidiary) unless: (a) the Company or such Restricted Subsidiary would be entitled to incur Indebtedness, in a principal amount equal to the Attributable Indebtedness with respect to such Sale/Leaseback Transaction, secured by a Lien on the property subject to such Sale/Leaseback Transaction pursuant to the covenant described under "Limitation on Liens" above without equally and ratably securing the Notes pursuant to such covenant; (b) after the date on which the Notes are originally issued and within a period commencing six months prior to the consummation of such Sale/Leaseback Transaction and ending six months after the consummation thereof, the Company or such Restricted Subsidiary shall have expended for property used or to be used in the ordinary course of business of the Company and the Restricted Subsidiaries (including amounts expended for the exploration, drilling or development thereof, and for additions, alterations, repairs and improvements thereto) an amount equal to all or a portion of the net proceeds of such Sale/Leaseback Transaction and the Company shall have elected to designate such amount as a credit against such Sale/Leaseback Transaction (with any such amount not being so designated to be applied as set forth in clause (c) below); or (c) the Company, during the 12-month period after the effective date of such Sale/Leaseback Transaction, shall have applied to the voluntary defeasance or retirement of Notes or any Pari Passu Indebtedness an amount equal to the greater of the net proceeds of the sale or transfer of the property leased in such Sale/Leaseback Transaction and the fair value, as determined by the Board of Directors of the Company, of such property at the time of entering into such Sale/Leaseback Transaction (in either case adjusted to reflect the remaining term of the lease and any amount expended by the Company as set forth in clause (b) above), less an amount equal to the principal amount of Notes and Pari Passu Indebtedness voluntarily defeased or retired by the Company within such 12-month period and not designated as a credit against any other Sale/ Leaseback Transaction entered into by the Company or any Restricted Subsidiary during such period. SUBSIDIARY GUARANTORS. Upon issuance, the Notes will not be guaranteed by any Subsidiary of the Company. The Indenture will provide that if any Subsidiary of the Company guarantees any Funded Indebtedness of the Company at any time in the future, then the Company will cause the Notes to be equally and ratably guaranteed by such Subsidiary. LIMITATIONS ON MERGERS AND CONSOLIDATIONS The Indenture will provide that the Company will not consolidate or merge with or into any Person, or sell, lease, convey or otherwise dispose of all or substantially all of its assets, or assign any of its obligations under the Indenture or under the Notes, to any Person, unless: (i) the Person formed by or surviving such consolidation or merger (if other than the Company), or to which such sale, lease, conveyance or other disposition or assignment shall be made (collectively, the "Successor"), is a corporation organized and existing under the laws of the United States or any State thereof or the District of Columbia and the Successor assumes by supplemental indenture in a form satisfactory to the Trustee all of the obligations of the Company under the Indenture and under the Notes; and (ii) immediately after giving effect to such transaction, no Default or Event of Default shall have occurred and be continuing. 46 CERTAIN DEFINITIONS The following is a summary of certain defined terms to be used in the Indenture. Reference is made to the Indenture for the full definition of all such terms and for the definitions of other capitalized terms used herein and not defined below. "Attributable Indebtedness", when used with respect to any Sale/Leaseback Transaction, means, as at the time of determination, the present value (discounted at a rate equivalent to the Company's then current weighted average cost of funds for borrowed money as at the time of determination, compounded on a semi-annual basis) of the total obligations of the lessee for rental payments during the remaining term of the lease included in such Sale/Leaseback Transaction (including any period for which such lease can be extended). "Capitalized Lease Obligation" of any Person means any obligation of such Person to pay rent or other amounts under a lease of property, real or personal, that is required to be capitalized for financial reporting purposes in accordance with generally accepted accounting principles; and the amount of such obligation shall be the capitalized amount thereof determined in accordance with generally accepted accounting principles. "Consolidated Net Tangible Assets" means, for the Company and its Restricted Subsidiaries on a consolidated basis determined in accordance with generally accepted accounting principles, the aggregate amounts of assets (less depreciation and valuation reserves and other reserves and items deductible from gross book value of specific asset accounts under generally accepted accounting principles) that would be included on a balance sheet after deducting therefrom (a) all liability items except deferred income taxes, commercial paper, short term bank indebtedness, Funded Indebtedness, other long-term liabilities and shareholders' equity and (b) all goodwill, trade names, trademarks, patents, unamortized debt discount and expense and other like intangibles. "Currency Hedge Obligations" means, at any time as to any Person, the obligations of such Person at such time that were incurred in the ordinary course of business pursuant to any foreign currency exchange agreement, option or futures contract or other similar agreement or arrangement designed to protect against or manage such Person's or any of its Subsidiaries' exposure to fluctuations in foreign currency exchange rates. "Funded Indebtedness" means all Indebtedness (including Indebtedness incurred under any revolving credit, letter of credit or working capital facility) that matures by its terms, or that is renewable at the option of any obligor thereon to a date, more than one year after the date on which such Indebtedness is originally incurred. "Indebtedness" of any Person at any date means, without duplication, (i) all indebtedness of such Person for borrowed money (whether or not the recourse of the lender is to the whole of the assets of such Person or only to a portion thereof), (ii) all obligations of such Person evidenced by bonds, debentures, notes or other similar instruments, (iii) all obligations of such Person in respect of letters of credit or other similar instruments (or reimbursement obligations with respect thereto), other than standby letters of credit incurred by such Person in the ordinary course of business, (iv) all obligations of such Person to pay the deferred and unpaid purchase price of property or services, except trade payables and accrued expenses incurred in the ordinary course of business, (v) all Capitalized Lease Obligations of such Person, (vi) all Indebtedness of others secured by a Lien on any asset of such Person, whether or not such Indebtedness is assumed by such Person, (vii) all Indebtedness of others guaranteed by such Person to the extent of such guarantee and (viii) all obligations of such Person in respect of Currency Hedge Obligations, Interest Rate Hedging Agreements and Oil and Gas Hedging Contracts. 47 "Interest Rate Hedging Agreements" means, with respect to any Person, the obligations of such Person under (i) interest rate swap agreements, interest rate cap agreements and interest rate collar agreements and (ii) other agreements or arrangements designed to protect such Person or any of its Subsidiaries against fluctuations in interest rates. "Lien" means, with respect to any asset, any mortgage, lien, pledge, charge, security interest or encumbrance of any kind in respect of such asset (including, without limitation, any production payment, advance payment or similar arrangement with respect to minerals in place), whether or not filed, recorded or otherwise perfected under applicable law. For the purposes of the Indenture, the Company or any Restricted Subsidiary shall be deemed to own subject to a Lien any asset which it has acquired or holds subject to the interest of a vendor or lessor under any conditional sale agreement, Capitalized Lease Obligation (other than any Capitalized Lease Obligation relating to any building, structure, equipment or other property used or to be used in the ordinary course of business of the Company and the Restricted Subsidiaries) or other title retention agreement relating to such asset. "Oil and Gas Hedging Contracts" means any oil and gas purchase or hedging agreement, and other agreement or arrangement, in each case, that is designed to provide protection against oil and gas price fluctuations. "Pari Passu Indebtedness" means any Indebtedness of the Company, whether outstanding on the date on which the Notes are originally issued or thereafter created, incurred or assumed, unless, in the case of any particular Indebtedness, the instrument creating or evidencing the same or pursuant to which the same is outstanding expressly provides that such Indebtedness shall be subordinated in right of payment to the Notes. "Restricted Subsidiary" means each of the existing Subsidiaries of the Company and any Subsidiary of the Company that is a successor corporation of any of the existing Subsidiaries, except for BGP Inc. The status of any Subsidiary of the Company as a Restricted Subsidiary shall continue so long as it is a Subsidiary of the Company. "Sale/Leaseback Transaction" means any arrangement with any Person providing for the leasing by the Company or any Restricted Subsidiary, for a period of more than three years, of any real or tangible personal property, which property has been or is to be sold or transferred by the Company or such Restricted Subsidiary to such Person in contemplation of such leasing. EVENTS OF DEFAULT An Event of Default will be defined in the Indenture as being: (i) default by the Company for 30 days in payment of any interest on the Notes; (ii) default by the Company in any payment of principal of or premium, if any, on the Notes; (iii) default by the Company in performance of any other covenant or agreement in the Notes, or the Indenture which shall not have been remedied within 60 days after written notice by the Trustee or by the holders of at least 25% in principal amount of the Notes then outstanding; (iv) the acceleration of the maturity of any Indebtedness of the Company or any Restricted Subsidiary (other than the Notes) having an outstanding principal amount of $5 million or more individually or in the aggregate, or a default in the payment of any principal or interest in respect of any Indebtedness of the Company or any Restricted Subsidiary (other than the Notes) having an outstanding principal amount of $5 million or more individually or in the aggregate and such default shall be continuing for a period of 30 days without the Company or such Restricted Subsidiary, as the case may be, effecting a cure of such default; (v) failure by the Company or any Restricted Subsidiary to pay final, non-appealable judgments aggregating in excess of $10 million, which judgments are not paid, discharged or stayed for a period of 60 days; or (vi) certain events involving bankruptcy, insolvency or reorganization of the Company or any Restricted Subsidiary. The Indenture will provide 48 that the Trustee may withhold notice to the holders of the Notes of any default (except in payment of principal of, or premium, if any, or interest on the Notes) if the Trustee considers it in the interest of the holders of the Notes to do so. The Indenture will provide that if an Event of Default occurs and is continuing with respect to the Indenture, the Trustee or the holders of not less than 25% in principal amount of the Notes outstanding may declare the principal of and premium, if any, and accrued and unpaid interest on all the Notes to be due and payable. Upon such a declaration, such principal, premium, if any, and interest will be due and payable immediately. If an Event of Default relating to certain events of bankruptcy, insolvency or reorganization of the Company or any Restricted Subsidiary occurs and is continuing, the principal of and premium, if any, and interest on all the Notes will become and be immediately due and payable without any declaration or other act on the part of the Trustee or any holders of the Notes. The amount due and payable on the acceleration of any Note will be equal to 100% of the principal amount of such Note, plus accrued interest to the date of payment. Under certain circumstances, the holders of a majority in principal amount of the outstanding Notes may rescind any such acceleration with respect to the Notes and its consequences. The Indenture will provide that no holder of a Note may pursue any remedy under the Indenture unless (i) the Trustee shall have received written notice of a continuing Event of Default, (ii) the Trustee shall have received a request from holders of at least 25% in principal amount of the Notes to pursue such remedy, (iii) the Trustee shall have been offered indemnity satisfactory to it and (iv) the Trustee shall have failed to act for a period of 60 days after receipt of such notice and offer of indemnity; however, such provision does not affect the right of a holder of a Note to sue for enforcement of any overdue payment thereon. The holders of a majority in principal amount of the Notes then outstanding will have the right to direct the time, method and place of conducting any proceeding for exercising any remedy available to the Trustee under the Indenture, subject to certain limitations specified in the Indenture. The Indenture will require the annual filing by the Company with the Trustee of a written statement as to compliance with the covenants contained in the Indenture. MODIFICATION AND WAIVER The Indenture will provide that modifications and amendments to the Indenture or the Notes may be made by the Company and the Trustee with the consent of the holders of a majority in principal amount of the Notes then outstanding; provided that no such modification or amendment may, without the consent of the holder of each Note then outstanding affected thereby, (i) reduce the percentage in principal amount of Notes whose holders must consent to an amendment, supplement or waiver; (ii) reduce the rate of or change the time for payment of interest, including default interest, on any Note; (iii) reduce the principal of or change the fixed maturity of any Note or alter the premium or other provisions with respect to redemption; (iv) make any Note payable in money other than that stated in the Note; (v) impair the right to institute suit for the enforcement of any payment of principal of, or premium, if any, or interest on, any Note; (vi) make any change in the percentage of principal amount of Notes necessary to waive compliance with certain provisions of the Indenture; or (vii) waive a continuing Default or Event of Default in the payment of principal of, or premium, if any, or interest on the Notes. The Indenture will provide that modifications and amendments of the Indenture may be made by the Company and the Trustee without the consent of any holders of Notes in certain limited circumstances, including (a) to cure any ambiguity, omission, defect or inconsistency, (b) to provide for guarantees of the Notes or addition of any Subsidiary of the Company as a guarantor of the Notes, (c) to provide for the assumption of the obligations of the Company under the Indenture upon the merger, consolidation or sale or other disposition of all or substantially all of the assets of the Company, (d) to provide for uncertificated Notes in addition to or in place of certificated Notes, (e) to comply with any requirement in order to effect or maintain the qualification of the Indenture under the Trust Indenture Act of 1939 or (f) to make any change that does not adversely affect the rights of any holder of Notes in any material respect. 49 The Indenture will provide that the holders of a majority in aggregate principal amount of the Notes then outstanding may waive any past default under the Indenture, except a default in the payment of principal, or premium, if any, or interest. DISCHARGE AND TERMINATION DEFEASANCE OF CERTAIN OBLIGATIONS. The Indenture will provide that the Company may terminate certain of its obligations under the Indenture, including those described under the section "Certain Covenants," if (i) the Company irrevocably deposits in trust with the Trustee money or U.S. Government Obligations sufficient to pay principal of and interest on the Notes to maturity, and to pay all other sums payable by it under the Indenture, provided that the Trustee shall have been irrevocably instructed to apply such money or the proceeds of such U.S. Government Obligations to the payment of said principal and interest with respect to the Notes as the same shall become due; (ii) the Company delivers to the Trustee an Officers' Certificate stating that all conditions precedent to satisfaction and discharge of the Indenture have been complied with, and an Opinion of Counsel to the same effect; (iii) no Default or Event of Default shall have occurred and be continuing on the date of such deposit; and (iv) the Company shall have delivered to the Trustee an Opinion of Counsel from nationally recognized counsel acceptable to the Trustee or a tax ruling to the effect that the holders of the Notes will not recognize income, gain or loss for Federal income tax purposes as a result of the Company's exercise of its option under such section and will be subject to Federal income tax on the same amount and in the same manner and at the same times as would have been the case if such option had not been exercised. In order to have money available on a payment date to pay principal of or interest on the Notes, the U.S. Government Obligations shall be payable as to principal or interest on or before such payment date in such amounts as will provide the necessary money. U.S. Government Obligations shall not be callable at the issuer's option. The Company's payment obligation shall survive until the Notes are no longer outstanding. DISCHARGE. The Indenture will provide that the Indenture shall cease to be of further effect (subject to certain exceptions relating to compensation and indemnity of the Trustee and repayment to the Company of excess money or securities) when (i) either (A) all outstanding Notes theretofore authenticated and issued (other than destroyed, lost or stolen Notes that have been replaced or paid) have been delivered to the Trustee for cancellation; or (B) all outstanding Notes not theretofore delivered to the Trustee for cancellation: (x) have become due and payable, or (y) will become due and payable at their stated maturity within one year or (z) are to be called for redemption within one year under arrangements satisfactory to the Trustee for the giving of notice of redemption by the Trustee in the name, and at the expense, of the Company, and the Company, in the case of clause (x), (y) or (z) above, has deposited or caused to be deposited with the Trustee as funds (immediately available to the holders in the case of clause (x) ) in trust for such purpose an amount which, together with earnings thereon, will be sufficient to pay and discharge the entire indebtedness on such Notes for principal, premium, if any, and interest to the date of such deposit (in the case of Notes which have become due and payable) or to the stated maturity or Redemption Date, as the case may be; (ii) the Company has paid or caused to be paid all other sums payable by it under the Indenture; and (iii) the Company has delivered to the Trustee an Officers' Certificate stating that all conditions precedent to satisfaction and discharge of the Indenture have been complied with, together with an Opinion of Counsel to the same effect. GOVERNING LAW The Indenture will provide that it will be governed by, and construed in accordance with, the laws of the State of New York. THE TRUSTEE Bankers Trust Company will be the Trustee under the Indenture. Its address is Four Albany Street, New York, New York 10006. The Company has also appointed the Trustee as the initial Registrar and as the initial Paying Agent under the Indenture. 50 The Indenture will contain certain limitations on the right of the Trustee, should it become a creditor of the Company, to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. In the event the Trustee acquires any conflicting interest (as defined in the Trust Indenture Act of 1939), however, it must eliminate such conflict or resign. The Indenture will provide that in case an Event of Default shall occur (and be continuing), the Trustee will be required to use the degree of care and skill of a prudent man in the conduct of his own affairs. The Trustee will be under no obligation to exercise any of its powers under the Indenture at the request of any of the holders of the Notes, unless such holders shall have offered the Trustee indemnity reasonably satisfactory to it. BOOK-ENTRY, DELIVERY AND FORM The Notes to be sold as set forth herein will be issued in the form of a fully registered Global Certificate (the "Global Certificate"). The Global Certificate will be deposited on the date of the closing of the sale of the Notes offered hereby (the "Closing Date") with, or on behalf of, The Depository Trust Company (the "Depositary") and registered in the name of its nominee (such nominee being referred to herein as the "Global Certificate Holder") or will remain in the custody of the Trustee pursuant to a FAST Balance Certificate Agreement or similar agreement between the Depositary and the Trustee. Except as set forth below, the Global Certificate may be transferred, in whole and not in part, only to another nominee of the Depositary or to a successor of the Depositary or its nominee. The Depositary has advised the Company and the Underwriters as follows: It is a limited-purpose trust company which was created to hold securities for its participating organizations (the "Participants") and to facilitate the clearance and settlement of transactions in such securities between Participants through electronic book-entry changes in accounts of its Participants. Participants include securities brokers and dealers (including the Underwriters), banks, trust companies, clearing corporations and certain other organizations. Access to the Depositary's book-entry system is also available to others, such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a Participant, either directly or indirectly ("indirect participants"). Persons who are not Participants may beneficially own securities held by the Depositary only through Participants or indirect participants. The Depositary has also advised that pursuant to procedures established by it (i) upon the issuance by the Company of the Notes, the Depositary will credit the accounts of Participants designated by the Underwriters with the principal amount of the Notes purchased by the Underwriters, and (ii) ownership of beneficial interests in the Global Certificate will be shown on, and the transfer of that ownership will be effected only through, records maintained by the Depositary (with respect to Participants' interests), the Participants and the indirect participants. The laws of some states require that certain persons take physical delivery in definitive form of securities which they own. Consequently, the ability to transfer beneficial interests in the Global Certificate is limited to such extent. All payments on the Global Certificate registered in the name of the Depositary's nominee will be made by the Company through the Paying Agent to the Depositary's nominee as the registered owner of the Global Certificate. Under the terms of the Indenture, the Company and the Trustee will treat the persons in whose names the Notes are registered as the owners of such Notes for the purpose of receiving payments of principal and interest on such Notes and for all other purposes whatsoever. Therefore, neither the Company, the Trustee nor the Paying Agent has any direct responsibility or liability for the payment of principal or interest on the Notes to owners of beneficial interests in the Global Certificate. The Depositary has advised the Company and the Trustee that its present practice is, upon receipt of any payment of principal or interest, to credit immediately the accounts of the 51 Participants with payment in amounts proportionate to their respective holdings in principal amount of beneficial interests in the Global Certificate as shown on the records of the Depositary. Payments by Participants and indirect participants to owners of beneficial interests in the Global Certificate will be governed by standing instructions and customary practices, as is now the case with securities held for the accounts of customers in bearer form or registered in "street name" and will be the responsibility of such Participants or indirect participants. The Company will issue Notes in definitive form in exchange for the Global Certificate if, and only if, either (1) the Depositary is at any time unwilling or unable to continue as depositary and a successor depositary is not appointed by the Company within 90 days, (2) an Event of Default has occurred and is continuing and the Registrar has received a request from the Depositary to issue Notes in definitive form in lieu of all or a portion of the Global Certificate (in which case the Company shall deliver Notes in definitive form within 30 days of such request), or (3) the Company determines not to have the Notes represented by a Global Certificate. In any instance, an owner of a beneficial interest in the Global Certificate will be entitled to have Notes equal in principal amount to such beneficial interest registered in its name and will be entitled to physical delivery of such Notes in definitive form. Notes so issued in definitive form will be issued in denominations of $1,000 and integral whole multiples thereof and will be issued in registered form only, without coupons. So long as the Global Certificate Holder is the registered owner of the Global Certificate, the Global Certificate Holder will be considered the sole Holder under the Indenture of any Notes evidenced by the Global Certificates. Beneficial owners of Notes evidenced by the Global Certificate will not be considered the owners or Holders thereof under the Indenture for any purpose, including with respect to the giving of any directions, instructions or approvals to the Trustee thereunder. Neither the Company nor the Trustee will have any responsibility or liability for any aspect of the records of the Depositary or for maintaining, supervising or reviewing any records of the Depositary relating to the Notes. SETTLEMENT AND PAYMENT Settlement for the Notes will be made by the Underwriters in immediately available funds. If the total outstanding principal amount of the Notes is represented by a Global Certificate, all payments of principal of and any premium and interest on the Notes will be made by the Company in immediately available funds; otherwise, payments on definitive physical certificates will be made in U.S. Clearing House funds. Secondary market trading activity in the Notes will also settle in immediately available funds. 52 UNDERWRITING Subject to the terms and conditions of the Underwriting Agreement, the Company has agreed to sell to each of the Underwriters named below, and each of such Underwriters has severally agreed to purchase from the Company, the aggregate principal amount of Notes set forth opposite its name below:
PRINCIPAL AMOUNT UNDERWRITER OF NOTES ----------- ---------------- Goldman, Sachs & Co. ....................................... $ 82,500,000 Chase Securities Inc........................................ 30,000,000 Lehman Brothers Inc......................................... 30,000,000 Petrie Parkman & Co., Inc................................... 7,500,000 ------------ Total..................................................... $150,000,000 ============
Under the terms and conditions of the Underwriting Agreement, the Underwriters are committed to take and pay for all of the Notes, if any are taken. The Underwriters propose to offer the Notes in part directly to the public at the initial public offering price set forth on the cover page of this Prospectus and in part to certain securities dealers at such price less a concession of 1.00% of the principal amount of the Notes. The Underwriters may allow, and such dealers may reallow, a concession not to exceed 0.25% of the principal amount of the Notes to certain brokers and dealers. After the Notes are released for sale to the public, the offering price and other selling terms may from time to time be varied by the Underwriters. The Notes are a new issue of securities with no established trading market. The Company has been advised by the Underwriters that the Underwriters intend to make a market in the Notes but are not obligated to do so and may discontinue market making at any time without notice. No assurance can be given as to the liquidity of the trading market for the Notes. The Company has agreed to indemnify the several Underwriters against certain liabilities, including liabilities under the Securities Act. Under Rule 2710(c)(8) of the National Association of Securities Dealers, Inc. (the "NASD"), Chase Securities Inc. may be deemed to have a conflict of interest with the Company because more than 10% of the net proceeds of the sale of the Notes is expected to be paid to an affiliate of such Underwriter in its capacity as a lender under the Company's bank credit facility. See "Use of Proceeds." This Offering is being conducted in accordance with Rule 2710(c)(8), which provides that, among other things, when an NASD member participates in the underwriting of debt securities of a company with which it or its associated persons, parent or affiliates have a conflict of interest, the yield to maturity can be no lower than that recommended by a "qualified independent underwriter" meeting certain standards. In accordance with this requirement, Goldman, Sachs & Co. will serve in such role and will recommend a minimum yield to maturity in compliance with the requirements of Rule 2710(c)(8). Goldman, Sachs & Co. will receive compensation from the Company in the amount of $10,000 for serving in such role. In connection with the Offering, Goldman, Sachs & Co. in its role as qualified independent underwriter has performed due diligence investigations and reviewed and participated in the preparation of this Prospectus and the Registration Statement of which this Prospectus forms a part. Goldman, Sachs & Co. provided Plains, and Petrie Parkman & Co., Inc. provided the Company with investment banking services in connection with the merger of Plains and the Company. Goldman, Sachs & Co. and Petrie Parkman & Co., Inc. each provided the Company with investment banking services in connection with the public offering of 5.4 million shares of the Company's common stock in June 1996. 53 LEGAL MATTERS Certain legal matters regarding the Offering have been passed upon on behalf of the Company by Bearman Talesnick & Clowdus Professional Corporation, Denver, Colorado. Attorneys employed by that law firm beneficially own approximately 14,700 shares of the Company's common stock. Vinson & Elkins L.L.P., Houston, Texas, as special counsel to the Company, has passed upon the validity of the issuance of the Notes. Certain legal matters in connection with the Notes will be passed upon for the Underwriters by Andrews & Kurth L.L.P., New York, New York. EXPERTS The consolidated financial statements and schedules of the Company as of December 31, 1995 and 1994 and for each of the three years in the period ended December 31, 1995 included in this Prospectus and elsewhere in the Registration Statement of which this Prospectus forms a part have been audited by Arthur Andersen LLP, independent public accountants, as indicated in their reports with respect thereto, and are included herein in reliance upon the authority of such firm as experts in giving such reports. The information included and incorporated by reference herein regarding the total proved reserves of the Company was prepared by the Company. With respect to the reserve estimates as of and prior to December 31, 1995, a portion was reviewed by Ryder Scott Company and the remaining portion was reviewed or prepared by Netherland, Sewell & Associates, Inc., as stated in their respective letter reports with respect thereto. The reserve estimates as of December 31, 1996 were reviewed solely by Ryder Scott Company. The reserve review letters of Ryder Scott Company and Netherland, Sewell & Associates, Inc. are filed as exhibits to the Registration Statement of which this Prospectus is a part, in reliance upon the authority of said firms as experts with respect to the matters covered by their reports and the giving of their reports. AVAILABLE INFORMATION This Prospectus constitutes a part of a Registration Statement on Form S-3 (herein together with all amendments thereto referred to as the "Registration Statement") filed by the Company with the Commission under the Securities Act. This Prospectus does not contain all the information set forth in the Registration Statement and exhibits thereto, and statements included in this Prospectus as to the content of any contract or other document referred to are not necessarily complete. For further information, reference is made to the Registration Statement and to the exhibits and schedules filed therewith. All these documents may be inspected at the Commission's principal office in Washington, D.C. without charge, and copies of them may be obtained from the Commission upon payment of prescribed fees. Statements contained in this Prospectus as to the contents of any contract or other document filed as an exhibit to the Registration Statement are not necessarily complete, and in each instance reference is hereby made to the copy of such contract or other document filed as an exhibit to the Registration Statement, each such statement being qualified in all respects by such reference. The Company is subject to the informational requirements of the Exchange Act, and, in accordance therewith files reports, proxy statements and other information with the Commission. Such reports, proxy statements and other information can be inspected and copied at the public reference facilities maintained by the Commission at 450 Fifth Street, N.W., Washington, D.C. 20549, Room 1024 and at the following Regional Offices of the Commission: 500 West Madison Street, Suite 1400, Chicago, Illinois 60661-2511, and 7 World Trade Center, New York, New York 10048. Copies of such material also can be obtained at prescribed rates by writing to the Commission, Public Reference Section, 450 Fifth Street, N.W., Washington, D.C. 20549. In addition, such material may also be 54 inspected and copied at the offices of the New York Stock Exchange, Inc., 20 Broad Street, New York, New York 10005. In addition, such materials filed electronically by the Company with the Commission are available at the Commission's World Wide Web site at http://www.sec.gov. INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE The following documents that previously were, or are required in the future to be, filed with the Commission (File No. 1-13446) pursuant to the Exchange Act are incorporated herein by reference: (i) the Company's Annual Report on Form 10-K for the year ended December 31, 1995; (ii) the Company's Quarterly Reports on Form 10-Q for each of the quarters ended March 31, 1996, June 30, 1996, and September 30, 1996; (iii) the Company's Current Reports on Form 8-K dated each of June 20, 1996, November 4, 1996, January 8, 1997 and February 10, 1997; (iv) the description of the Company's Common Stock contained in the Company's registration statement on Form 8-A as filed with the Commission on October 27, 1994; (v) the Company's Proxy Statement dated April 11, 1996 concerning the Company's Annual Meeting of Stockholders held June 5, 1996; and (vi) all documents filed by the Company pursuant to Sections 13(a), 13(c), 14 or 15(d) of the Exchange Act subsequent to the date of this Prospectus and prior to the termination of the offering made hereby. Any statement contained in a document incorporated by reference herein shall be deemed to be modified or superseded for purposes of this Prospectus to the extent that such statement is modified or replaced by a statement contained in this Prospectus or in any other subsequently filed document that also is or is deemed to be incorporated by reference into this Prospectus. Any such statement so modified or superseded shall not be deemed, except as so modified or replaced, to constitute a part of this Prospectus. The Company will provide without charge to each person to whom a copy of this Prospectus has been delivered, upon the written or oral request of any such person, a copy of any or all of the documents referred to above that have been or may be incorporated in this Prospectus by reference, other than exhibits to such documents. Written or oral requests for such copies should be directed to Donald H. Stevens, Vice President, Barrett Resources Corporation, 1515 Arapahoe Street, Tower 3, Suite 1000, Denver, Colorado 80202, (303) 572-3900. CERTAIN DEFINITIONS Unless otherwise indicated in this Prospectus, 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 Prospectus, 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 55 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. "Behind-pipe recompletion" is the completion of an existing well for production from a formation that exists behind the casing of the well. "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 key fee, state and federal leases, and natural gas and oil prices. "Reserve replacement cost" means the cost to the Company of additions to the Company's reserve base divided by the aggregate costs of developing or acquiring those additional reserves. 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 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%. "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 developed behind-pipe reserves" includes those reserves that exist behind the casing of existing wells when the cost of making such reserves available for production is relatively small compared to the cost of a new well. "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. 56 INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Report Of Independent Public Accountants................................. F-2 Consolidated Balance Sheets as of September 30, 1996 (unaudited) and at December 31, 1995 and 1994.............................................. F-3 Consolidated Statements Of Income for the nine months ended September 30, 1996 and 1995 (unaudited) and each of the three years in the period ended December 31, 1995................................................. F-4 Consolidated Statements Of Stockholders' Equity for the nine months ended September 30, 1996 and 1995 (unaudited) and each of the three years in the period ended December 31, 1995...................................... F-5 Consolidated Statements Of Cash Flows for the nine months ended September 30, 1996 and 1995 (unaudited) and each of the three years in the period ended December 31, 1995................................................. F-6 Notes to the Consolidated Financial Statements........................... F-7 Supplemental Oil And Gas Information..................................... F-23
F-1 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, 1995 and 1994, and the related consolidated statements of income, stockholders' equity and cash flows for each of the three years in the period ended December 31, 1995. 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, 1995 and 1994, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1995, in conformity with generally accepted accounting principles. As explained in Note 8 to the financial statements, effective January 1, 1993, the Company changed its method of accounting for postretirement benefits. Arthur Andersen LLP Denver, Colorado March 1, 1996 F-2 BARRETT RESOURCES CORPORATION CONSOLIDATED BALANCE SHEETS (IN THOUSANDS)
DECEMBER 31, ------------------ SEPTEMBER 30, 1994 1995 1996 -------- -------- ------------- (UNAUDITED) ASSETS Current assets: Cash and cash equivalents.................. $ 12,348 $ 7,529 $ 9,446 Receivables, net........................... 34,522 31,089 38,680 Inventory.................................. 643 554 962 Other current assets....................... 1,099 574 886 -------- -------- -------- Total current assets..................... 48,612 39,746 49,974 Net property and equipment (full cost method)..................................... 261,424 300,666 422,168 Other assets................................. 916 -- -- -------- -------- -------- $310,952 $340,412 $472,142 ======== ======== ======== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable........................... $ 24,587 $ 14,369 $ 14,860 Amounts payable to oil and gas property owners.................................... 16,091 13,366 16,199 Accrued and other liabilities.............. 5,468 8,325 16,913 -------- -------- -------- Total current liabilities................ 46,146 36,060 47,972 Long term debt............................... 53,000 89,000 12,000 Deferred income taxes........................ 21,726 23,524 48,595 Postretirement benefits...................... 927 -- -- Other long term liabilities.................. 1,017 -- -- 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, 31,319,193 outstanding (25,092,246 and 24,694,669 at December 31, 1995 and 1994, respectively............... 247 251 313 Additional paid-in capital................... 78,628 86,154 241,407 Retained earnings............................ 109,304 105,890 122,849 Treasury stock, at cost...................... (43) (467) (994) -------- -------- -------- Total stockholders' equity............... 188,136 191,828 363,575 -------- -------- -------- $310,952 $340,412 $472,142 ======== ======== ========
(See accompanying notes) F-3 BARRETT RESOURCES CORPORATION CONSOLIDATED STATEMENTS OF INCOME (IN THOUSANDS, EXCEPT PER SHARE DATA)
NINE MONTHS ENDED YEARS ENDED DECEMBER 31, SEPTEMBER 30, --------------------------- ------------------ 1993 1994 1995 1995 1996 -------- -------- -------- -------- -------- (UNAUDITED) Revenues: Oil and gas production...... $ 80,911 $ 78,794 $ 96,996 $70,481 $102,412 Trading revenues............ 22,955 28,114 28,554 20,156 30,547 Revenue from gas gathering.. 216 353 1,074 917 1,996 Interest income............. 736 864 714 529 633 Other income................ 1,254 1,333 678 594 465 -------- -------- -------- -------- -------- 106,072 109,458 128,016 92,677 136,053 Operating expenses: Lease operating expenses.... 30,383 28,223 34,525 25,418 34,027 Depreciation, depletion and amortization............... 20,185 22,760 33,480 23,625 31,859 Cost of trading............. 21,675 27,190 27,611 19,385 28,449 General and administrative.. 11,194 13,261 13,426 10,255 11,212 Interest expense............ 725 942 4,631 3,284 3,154 Other expenses, net......... 867 645 588 568 -- Merger and reorganization expense.................... -- -- 14,161 13,207 -- -------- -------- -------- -------- -------- 85,029 93,021 128,422 95,742 108,701 -------- -------- -------- -------- -------- Income (loss) before income taxes and cumulative effect of change in method of accounting for postretirement benefits..................... 21,043 16,437 (406) (3,065) 27,352 Provision for income taxes.... 6,721 5,138 1,834 2,812 10,393 -------- -------- -------- -------- -------- Income (loss) before cumulative effect of change in method of accounting for postretirement benefits...... 14,322 11,299 (2,240) (5,877) 16,959 Cumulative effect of change in accounting for postretirement benefits, net of tax......... (656) -- -- -- -- -------- -------- -------- -------- -------- Net income (loss)............. $ 13,666 $ 11,299 $ (2,240) $ (5,877) $ 16,959 ======== ======== ======== ======== ======== Net income (loss) per common share and common share equivalent before change in method of accounting for postretirement benefits...... $ 0.58 $ 0.46 $ (0.09) $ (0.23) $ 0.62 Net income (loss) per common share and common share equivalent--cumulative effect....................... $ (0.03) $ -- $ -- $ -- $ -- -------- -------- -------- -------- -------- Net income (loss) per common share and common share equivalent................... $ 0.55 $ 0.46 $ (0.09) $ (0.23) $ 0.62 ======== ======== ======== ======== ========
(See accompanying notes) F-4 BARRETT RESOURCES CORPORATION CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (IN THOUSANDS)
ADDITIONAL TOTAL COMMON PAID-IN TREASURY RETAINED STOCKHOLDERS' STOCK CAPITAL STOCK EARNINGS EQUITY ------ ---------- -------- -------- ------------- Balances, October 1, 1992 as previously reported........ $ 97 $ 39,651 $ -- $ 3,567 $ 43,315 Effect of change to December 31 year end Net income for the three month period ending December 31, 1992........ -- -- -- 1,333 1,333 Pooling of interests with Plains Petroleum Company.................. 128 19,163 -- 84,144 103,435 ---- -------- ----- -------- -------- Balance, December 31, 1992 as restated................ 225 58,814 -- 89,044 148,083 Exercise of stock options.................. 1 515 (204) -- 312 Issuance of common stock.. 20 18,881 -- -- 18,901 Cash dividends--Plains common stock............. -- -- -- (2,352) (2,352) Net income for the year ended December 31, 1993.. -- -- -- 13,666 13,666 ---- -------- ----- -------- -------- Balance, December 31, 1993.. 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 3,801 (527) -- 3,276 Issuance of common stock.. 60 151,452 -- -- 151,512 Net income for the nine months ended September 30, 1996 (unaudited)..... -- -- -- 16,959 16,959 ---- -------- ----- -------- -------- Balance, September 30, 1996....................... $313 $241,407 $(994) $122,849 $363,575 ==== ======== ===== ======== ========
(See accompanying notes) F-5 BARRETT RESOURCES CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)
NINE MONTHS ENDED YEAR ENDED DECEMBER 31, SEPTEMBER 30, ---------------------------- ------------------- 1993 1994 1995 1995 1996 -------- -------- -------- -------- --------- (UNAUDITED) Cash flows from operations: Net income (loss)......... $ 13,666 $ 11,299 $ (2,240) $ (5,877) $ 16,959 Adjustments needed to reconcile to net cash flow provided by operations: Depreciation, depletion and amortization....... 20,185 22,760 33,480 23,625 31,859 Unrealized (gain) loss on trading............. (124) 58 1,139 -- (1,138) Deferred income taxes... 5,975 4,788 1,798 2,543 9,778 Other................... 782 70 (787) (770) -- -------- -------- -------- -------- --------- 40,484 38,975 33,390 19,521 57,458 Change in current assets and liabilities: Accounts receivable... (4,304) (8,436) 3,433 9,505 (7,246) Other current assets.. (209) (148) 525 432 (416) Accounts payable...... (1,870) 6,803 (524) (15,305) 457 Amounts due oil and gas property owners.. 5,640 623 (2,725) (942) 7,325 Accrued and other liabilities.......... 1,839 (1,244) 1,439 3,242 5,132 -------- -------- -------- -------- --------- Net cash flow provided by operations................. 41,580 36,573 35,538 16,453 62,710 Cash flows from investing activities: Proceeds from sale of oil and gas properties....... 16,210 458 504 209 1,992 Purchase of short-term in- vestments................ (5,952) (11,322) -- -- -- Maturity of short-term in- vestments................ 1,984 15,290 -- -- -- Acquisition of property and equipment............ (45,488) (95,589) (82,758) (46,945) (124,054) Other..................... 65 146 -- -- -- -------- -------- -------- -------- --------- Net cash flow used in in- vesting activities................. (33,181) (91,017) (82,254) (46,736) (122,062) Cash flows from financing activities: Proceeds from issuance of common stock............. 19,212 301 7,071 6,413 138,269 Purchase of treasury stock.................... -- (78) -- -- -- Borrowing under line of credit................... 1,300 44,000 115,000 69,000 33,000 Payments on line of cred- it....................... (7,800) (4,500) (79,000) (37,000) (110,000) Dividends paid............ (2,352) (2,353) (1,174) (1,179) -- Other..................... 868 (147) -- (767) -- -------- -------- -------- -------- --------- Net cash flow provided by financing activities................. 11,228 37,223 41,897 36,467 61,269 Increase (decrease) in cash and cash equivalents....... 19,627 (17,221) (4,819) 6,184 1,917 Cash and cash equivalents at beginning of period........ 9,942 29,569 12,348 12,348 7,529 -------- -------- -------- -------- --------- Cash and cash equivalents at end of period.............. $ 29,569 $ 12,348 $ 7,529 $ 18,532 $ 9,446 ======== ======== ======== ======== =========
(See accompanying notes) F-6 BARRETT RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED) 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 the areas which are synergistic to the Company's production. Barrett has a gas marketing and trading subsidiary, which allows the Company to market the Company's natural gas production and to purchase and sell other companies' natural gas. 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. Certain reclassifications have been made to 1993 and 1994 amounts to conform to the 1995 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. F-7 BARRETT RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) (INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED) 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 only one cost center since all of its properties are located in the United States. 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 $.55, $.52 and $.48 per Mcfe ($3.28, $3.14 and $2.87 per BOE) during the years ended December 31, 1995, 1994 and 1993, 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. 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, production revenue that the Company, as operator, is collecting and distributing to revenue interest owners and production revenue taxes that the Company, as operator, has withheld for timely payment to the tax agencies. 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 F-8 BARRETT RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) (INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED) hedging position for specific transactions that management deems expose the Company to an unacceptable market price risk. Price swaps or commodities transactions without corresponding scheduled physical transactions (scheduled physical transactions include committed trading activities or production from producing wells) do not qualify for hedge accounting. The Company classifies these positions as trading positions and records these instruments at fair value. Gains and losses are recognized as fair values fluctuate from time to time compared to cost. Gains or losses on hedging transactions are deferred until the physical transaction occurs for financial reporting purposes. Deferred gains and losses and unrealized gains and losses are evaluated in connection with the physical transaction underlying the hedge position. Hedging gains or losses significantly exceeding the price movement of the underlying physical transaction are recorded in the consolidated statements of income in the 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: 1995--24,931,000; 1994--24,967,000 and 1993--24,778,000. 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. Unaudited financial statements: In the opinion of management, the accompanying unaudited consolidated condensed financial statements contain all adjustments necessary to present fairly the financial position of the Company as of September 30, 1996 and the results of operations and cash flows for the periods presented. All such adjustments are of a normal recurring nature. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to the SEC's rules and regulations. The results of operations for the periods presented are not necessarily indicative of the results for the full year. 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 F-9 BARRETT RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) (INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED) connection with the merger, the Company's authorized number of shares of common stock was increased to 35 million. 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 and 1993 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. Certain reclassifications have been made to the historical consolidated financial statements of the separate companies to conform the financial statements to a comparable presentation. There were no intercompany transactions between the Company and Plains. Separate results for the periods preceding the merger, including the conversion to full cost for Plains and the change to a December 31 year-end for the Company, were as follows (in 000's):
SIX MONTH PERIOD ENDED JUNE 30, 1995 BARRETT PLAINS(1) ADJUSTMENTS(2) COMBINED ---------------------- ------- --------- -------------- -------- (UNAUDITED) Net revenues....................... $29,277 $35,823 -- $ 65,100 Net income......................... 2,200 3,771 -- 5,971 12 MONTH PERIOD ENDED 9/30/94 12/31/94 12/31/94 --------------------- ------- --------- -------- Net revenues....................... $41,252 $63,024 $ 5,182 $109,458 Net income......................... 4,439 7,768 (908) 11,299 12 MONTH PERIOD ENDED 9/30/93 12/31/93 12/31/93 --------------------- ------- --------- -------- Net revenues....................... $42,686 $64,998 $(1,612) $106,072 Net income......................... 5,756 8,128 (218) 13,666
- -------- (1) Restated to full cost to conform accounting policies. (2) To conform year ends. In connection with the merger, approximately $14.2 million of merger and reorganization costs and expenses were incurred and have been charged to expense in the Company's third and fourth quarters of fiscal 1995. These nonrecurring costs and expenses consist of (1) investment banker and professional fees of $7.4 million; (2) severance and employee benefit costs of $5.6 million for approximately 38 employees, terminated through consolidation of administrative and operational functions; (3) a non-cash credit of approximately $.9 million associated with the termination of Plains' postretirement benefit plans and other related benefit plans and (4) other merger and reorganization related costs of $2.1 million. F-10 BARRETT RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) (INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED) 3. RECEIVABLES
DECEMBER 31, --------------- 1994 1995 ------- ------- (IN THOUSANDS) Oil and gas revenue receivable.............................. $13,257 $15,535 Joint interest billings..................................... 14,542 7,652 Trading receivables......................................... 6,483 5,665 Other accounts receivable................................... 240 2,237 ------- ------- $34,522 $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, 1995 and 1994, receivables are recorded net of allowance for doubtful accounts of $201,000 and $224,000, respectively. 4. PROPERTY AND EQUIPMENT
DECEMBER 31, ----------------- 1994 1995 -------- -------- (IN THOUSANDS) Oil and gas properties, full cost method: Unevaluated costs, not being amortized................. $ 12,611 $ 10,579 Evaluated costs........................................ 346,950 420,784 Gas gathering systems.................................. 8,388 8,815 Furniture, vehicles and equipment........................ 9,765 9,801 -------- -------- 377,714 449,979 Less accumulated depreciation, depletion, amortization and impairment.......................................... 116,290 149,313 -------- -------- $261,424 $300,666 ======== ========
The Company capitalized interest costs of $403,000 in 1995 with respect to qualifying properties. Total interest costs incurred after recognition of the capitalized interest amount was $4.6 million in 1995. F-11 BARRETT RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) (INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED) 5. UNEVALUATED OIL AND GAS PROPERTY COSTS Unevaluated oil and gas property costs consist of the following:
COSTS INCURRED DURING ------------------------------- 1992 1993 1994 1995 TOTAL ---- ---- ------ ------ ------- (IN THOUSANDS) Acquisition costs............................... $71 $-- $2,130 $5,623 $ 7,824 Exploration costs............................... 11 32 53 2,659 2,755 --- --- ------ ------ ------- $82 $32 $2,183 $8,282 $10,579 === === ====== ====== =======
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 three 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 for a four year period ending July 19, 1999. 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, 1995 (which was based on the March 31, 1995 and December 31, 1994 reserve reports), the Company has a borrowing limit of $160 million. In order to reduce the commitment fees, the Company voluntarily requested that the lenders limit the maximum borrowing to $90 million through December 31, 1995. Subsequent to December 31, 1995, the lenders increased the collateral value to $205 million based on the June 30, 1996 reserve report. The lenders also extended the maturity date to October 31, 2000. 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 0.5% to 1.0% (depending on the Company's indebtedness relative to its borrowing base) for a substantial portion of the outstanding balance. As of December 31, 1995 the Company's outstanding balance under the line of credit was $89 million of which $83 million was accruing interest at an average LIBOR based rate of 6.62% and $6 million was accruing interest on a prime based rate of 8.50%. The line of credit agreement restricts the payment of dividends, borrowings, sale of assets, loans to others, 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. As of September 30, 1996, the Company's outstanding balance under the line of credit was $12 million, all of which was accruing interest at an average rate of six percent. 7. OPTIONS 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, as amended, provided for the granting of 775,000 shares. The 1994 Plan provides for the granting of 400,000 shares of the Company's common stock. In addition, the Company has a non-discretionary stock option plan under which options for an aggregate of 100,000 shares of F-12 BARRETT RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) (INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED) 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 Plains stock option plans 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. Summary of options granted, exercised and outstanding during 1994 and 1995 is as follows:
NUMBER OPTION OPTION OF SHARES PRICE VALUE --------- ------------- -------- ($000'S) Outstanding at December 31, 1993......... 336,500 $ 3.88-$13.38 $ 1,949 Plains outstanding options............... 592,611 $15.91-$27.50 13,962 --------- ------------- ------- Outstanding at December 31, 1993, restat- ed...................................... 929,111 $ 3.88-$27.50 15,911 Granted.................................. 585,500 $10.38-$20.88 8,560 Exercised or canceled.................... (154,820) $ 3.88-$12.13 (712) --------- ------------- ------- Outstanding at December 31, 1994......... 1,359,791 $ 3.88-$27.50 23,759 Granted.................................. 110,000 $13.38-$22.75 2,454 Exercised or canceled.................... (477,460) $ 3.88-$27.50 (9,443) --------- ------------- ------- Outstanding at December 31, 1995......... 992,331 $ 5.00-$26.94 $16,770 ========= ============= ======= Exercisable at December 31, 1995......... 354,883 $ 5.13-$26.94 $ 6,349 ========= ============= =======
8. RETIREMENT BENEFITS The Company has a voluntary 401(k) employee savings plan. Under this plan, the Company matches 50% of each of the participating employees' contributions, up to a maximum of 6% of base salary. Effective April 1, 1996, the Company's match was increased to 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. The Company's matching contributions are subject to a vesting schedule. Company contributions were $239,000, $179,000 and $166,000 in 1995, 1994 and 1993, respectively. Plains had several employee benefit plans described below. Pursuant to the terms of the merger agreement between Plains and the Company, these plans were terminated. Plains' qualified, defined benefit retirement plan covered substantially all of its employees. The benefits were based on a specified level of the employee's compensation during plan participation. As of July 18, 1995, the plan froze benefit accruals. Pursuant to the plan, all participants became fully vested. Plan assets consist of cash and equivalents, corporate stocks and bonds, U.S. treasury notes, insured annuity contracts, and accrued interest. Contributions totaled $169,000, $312,000 and $341,000 for the 1995, 1994 and 1993 plan years, respectively. F-13 BARRETT RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) (INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED) The following table sets forth the plan's funded status:
1993 1994 1995 ------- ------- ------- (IN THOUSANDS) Actuarial present value of benefit obligations: Accumulated benefit obligation, including vested benefits of $1,290,000, $1,637,000 and $2,961,000 respectively....................... $(1,383) $(1,666) $(2,961) ======= ======= ======= Projected benefit obligation................... $(2,321) $(2,396) $(2,961) Plan assets at fair value...................... 1,977 2,205 2,709 ------- ------- ------- Projected benefit obligation in excess of plan assets........................................ (344) (191) (252) Unrecognized net (gain) loss................... 16 (141) -- Prior service cost not yet recognized in net periodic pension costs........................ 64 93 -- Unrecognized net obligation being recognized over 9.5 and 10.5 years in 1994 and 1993, respectively.................................. 146 132 -- ------- ------- ------- Accrued pension cost........................... $ (118) $ (107) $ (252) ======= ======= ======= Net pension cost included the following compo- nents: Service cost--benefits earned.................. $ 346 $ 290 $ 140 Interest cost on projected benefit obligation.. 150 157 160 Actual loss (return) on plan assets............ (145) 70 (369) Net amortization of unrecognized obligation and deferral...................................... 28 (216) 347 Curtailment gain............................... -- -- (735) ------- ------- ------- Net periodic pension cost (benefit).............. $ 379 $ 301 $ (457) ======= ======= =======
The weighted average discount rate used in determining the actuarial present value of the projected benefit obligation was 4.5% (termination rates). The rate of increase used for compensation levels was nil in 1995 and 5% in 1994 and 1993, respectively. The expected long-term rate of return on assets was 8.5%. Plains also contributed the lesser of 10% of its net earnings or 10% of employee compensation to a profit sharing plan of Plains. No contributions were made for 1995. Plains contributed $334,000 and $188,000 for 1994 and 1993, respectively. Through June 30, 1995 and during 1994, Plains matched 401(k) plan deferrals with contributions equal to 50% of each deferral up to 6% of current salary. This matching contribution was invested in Plains stock and were subject to a vesting schedule. Participants became fully vested with the merger with and into Barrett. Contributions were approximately $112,000, $192,000 and $250,000 for 1995, 1994 and 1993, respectively. The above described profit-sharing and 401(k) plans were terminated July 1, 1995; the pension plans were 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 in the second quarter of 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 F-14 BARRETT RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) (INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED) employees, directors and their beneficiaries. These plans were terminated effective June 30, 1995 and will be disbursed to the participants by the trustee of the assets over a period ending January 1, 1997. Total accrued liability under these plans at December 31, 1995 and 1994 was $36,000 and $1,006,000, respectively. Concurrently with the effective date of the merger, Plains' postretirement healthcare benefit and salary continuation plans were terminated. Participants in the salary continuation plan received (1) a lump sum benefit equal to the present value of the remaining monthly payments if receiving Death Benefits under the plan at the date of the termination, or (2) insurance polices, the cost of which was limited to the cash values of the life insurance policies owned by Plains. Benefits associated with the postretirement healthcare benefit plan were terminated and, accordingly, accrued postretirement benefit costs were relieved. Effective January 1, 1993, Plains adopted Statement No. 106 (FAS 106) issued by the Financial Accounting Standards Board on accounting for postretirement benefits other than pensions. In accordance with this statement, Plains elected to recognize the accumulated postretirement benefit liability as of the effective date, totaling approximately $800,000 (pretax). With the termination of these plans in 1995, all future obligations were settled and ceased to exist. Obligations for previous periods were as follows:
DECEMBER 31, 1994 ----------------- (IN THOUSANDS) Accumulated postretirement benefit obligation: Active plan participants................................ $(458) Retirees................................................ (302) ----- (760) Plan assets............................................. 0 ----- Net accumulated postretirement benefit obligation....... (760) Unrecognized net gain from past experience different from that assumed and from changes in assumptions...... (167) ----- Accrued postretirement benefit cost..................... $(927) ===== Net periodic postretirement benefit cost included the fol- lowing components: Service cost of benefits earned......................... $ 41 Interest cost on accumulated post-retirement benefit ob- ligation............................................... 61 ----- Net periodic postretirement benefit cost................ $ 102 =====
9. HEDGING ACTIVITIES The Company uses various hedging techniques to reduce the effect of price volatility on the sales price of a portion of its oil and gas sales. The objective of its hedging activities is to achieve more predictable revenues and cash flows. The following is a summary of the Company's hedging transactions in effect as of December 31, 1995. F-15 BARRETT RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) (INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED) A. The Company is the fixed price payor for hedging transactions relating to 6,000 MMBtu of gas per day for 1996 at $1.33 per MMBtu and approximately 7,000 MMBtu of gas per day for January through May 1996 at an average price of $2.12 per MMBtu. Under these price swap arrangements, the Company has agreed to buy gas at a fixed price and sell gas at an index price. These price swaps were entered to accommodate markets desiring fixed price supplies. B. The Company will receive fixed prices ranging from $1.46 to $2.12 per MMBtu in swap transactions associated with an average of 52,000 MMBtu of gas per day to be produced by the Company subsequent to December 31, 1995 through March 1996. The Company is required to pay an index price to its financial counterparty. The Company sold a call option on 20,000 MMBtu per day for April through October 1996. Under this option, the Company will receive $1.86 per MMBtu should the option holder elect to exercise. C. The Company's gas hedges also include a collar in which the Company sold a call and purchased a put with respect to 10,000 MMBtu per day in 1996 with an average floor (put) price of $1.60 per MMBtu and an average ceiling (call) price of $1.92 per MMBtu. Under this arrangement, the Company receives a payment if the index price falls below the floor and makes a payment to the counterparty if the index price exceeds the ceiling. To reduce exposure to increasing index prices, the Company purchased call options with prices averaging $2.673 per MMBtu January--March and $1.969 per MMBtu April-- December, 1996. D. The Company has entered into basis swaps to minimize different index price fluctuations. The Company will receive a payment in the event that the New York Mercantile Exchange ("NYMEX") price per MMBtu for a reference period exceeds the average specified index price by more than an average of $.29 on 10,000 MMBtu of gas per day from January through March 1996 ($.44 on 5,000 MMBtu of gas per day for April 1996). In separate basis swaps, the Company will receive a payment in the event the specified index price exceeds the NYMEX price net of a basis adjustment of an average of $.48 on 10,000 MMBtu of gas per day from January through October 1996. Conversely, the Company will be required to make payments to the counterparty if the opposite situation exists in these swaps. These swaps were entered to offset a portion of the risk associated with the Company's long-term firm transportation portfolio. E. With respect to crude oil production, the Company entered into a price swap whereby the Company will receive a fixed price of $18.00 per Bbl for 1,000 Bbls per day through March 1996. The Company is required to pay the counterparty a NYMEX settlement price. As of December 31, 1995, some of the Company's hedging positions described above 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. Accordingly, the Company recognized hedging losses of $1.2 million in the fourth quarter of 1995. These losses offset hedging gains of $1.6 million realized in 1995. The net hedging gain was included in oil and gas revenues. The Company paid and received certain premiums related to its option contracts for future periods. The unrealized hedging losses and net deferred premium costs have been included in other liabilities. During the first nine months of 1996, the Company recognized net production hedging expense of $1.5 million which was recorded in the consolidated statements of income as adjustments of gas and F-16 BARRETT RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) (INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED) oil production revenue. As of September 30, 1996, the Company held positions to hedge production of approximately 11.5 Bcf of gas through October 1997. During 1995, the Company incurred a net cost of $2.1 million to hedge the index based price for a portion of its gas purchased in various transactions for gas trading activities. These payments allowed the Company to purchase gas on a fixed price basis to satisfy fixed price sales commitments. This hedging allowed the Company to avoid gas price fluctuations for the related transactions so that the Company realized the gross profit margins anticipated upon entering into the trading arrangements. This hedging cost is included in the income statement as a component of "Cost of Trading." 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, 1996................................ $1,012 1997........................................................ 988 1998........................................................ 1,001 1999........................................................ 887 2000........................................................ 610 2001........................................................ 205 ------ $4,703 ======
The Company plans to sublet office space vacated with the consolidation and relocation of its Denver offices and accordingly anticipates a substantial reduction in rental expense for the years 1996 through 1999. Rent expense was $956,000, $859,000 and $788,000 for the years ended December 31, 1995, 1994 and 1993, respectively. Litigation On November 2, 1994, a putative class action was filed in Delaware Chancery Court. In that case, entitled Miller v. Cody, the plaintiff has alleged that certain named former directors of Plains, and Plains, have, among other things, breached their fiduciary duties and otherwise acting to entrench themselves in office. Plaintiff seeks various forms of injunctive relief, damages and an award of plaintiff's costs and disbursements. On May 3, 1995, the same day Plains announced it had executed a merger agreement with the Company, a putative class action, entitled Crandon Capital Partners v Miller, was filed in Delaware Chancery Court against Plains and the then-current members of its Board of Directors. In this suit it is alleged that, among other things, the agreement was inadequate, plaintiff seeks various forms of declaratory and injunctive relief, damages and an award of plaintiff's costs and disbursements. In March 1996, these two putative class actions were dismissed without prejudice. No defendant paid any consideration for such dismissals. F-17 BARRETT RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) (INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED) At December 31, 1995, 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 1995, 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. Major Purchaser During 1995, one purchaser accounted for 18 percent of the Company's total revenue (24 percent of oil and gas revenues.) Sales of gas to this purchaser represented 19 percent and 29 percent of total revenues in 1994 and 1993, respectively. 11. INCOME TAXES The provision for income taxes consists of the following:
1993 1994 1995 ------ ------ ------ (IN THOUSANDS) Current: Federal.............................................. $ 174 $ 233 $ 269 State................................................ 416 117 (233) ------ ------ ------ 590 350 36 Deferred: Federal.............................................. 5,138 4,511 2,039 State................................................ 993 277 (241) ------ ------ ------ 6,131 4,788 1,798 ------ ------ ------ $6,721 $5,138 $1,834 ====== ====== ======
F-18 BARRETT RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) (INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED) 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:
1993 1994 1995 ------- ------- ------ (IN THOUSANDS) Tax by applying the statutory federal income tax rate to pretax accounting income (loss)........ $ 7,365 $ 5,753 $ (138) Increase (decrease) in tax from: Change in valuation allowance................. (1,477) (2,148) 396 State income taxes............................ 1,409 394 (474) Non-deductible merger costs................... -- -- 2,429 Other, net.................................... (576) 1,139 (379) ------- ------- ------ $ 6,721 $ 5,138 $1,834 ======= ======= ======
Long-term deferred tax assets (liabilities) are comprised of the following at December 31, 1995 and 1994:
1994 1995 -------- -------- (IN THOUSANDS) Deferred tax assets: Allowance for losses.................................. $ 624 $ 81 Loss carryforwards and other.......................... 30,221 26,520 -------- -------- Gross deferred tax assets........................... 30,845 26,601 Deferred tax liabilities: Deferred revenue--partnership activities.............. (1,086) (466) Depreciation, depletion and amortization.............. (50,650) (48,460) Capitalized interest on other assets.................. (38) (6) -------- -------- Gross deferred tax liabilities...................... (51,774) (48,932) -------- -------- Net deferred tax liability........................ (20,929) (22,331) Valuation allowance............................... (797) (1,193) -------- -------- $(21,726) $(23,524) ======== ========
Valuation allowances of $1,193,000 and $797,000 were provided at December 31, 1995 and 1994, respectively, based on carryforward amounts which may not be utilized before expiration and the possible effect of exploratory drilling costs. F-19 BARRETT RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) (INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED) The Company has the following net operating loss and investment tax credit carryforwards available:
EXPIRATION NET OPERATING INVESTMENT YEAR LOSS TAX CREDIT ---------- ------------- ---------- (IN THOUSANDS) 1996.............................................. $ 4,227 $172 1997.............................................. 4,673 246 1998.............................................. 8,090 103 1999.............................................. 6,530 100 2000.............................................. 4,900 25 2001.............................................. 3,274 5 2002.............................................. 108 -- 2004.............................................. 197 -- 2005.............................................. 685 -- 2006.............................................. 1,446 -- 2007.............................................. 37 -- 2008.............................................. 22,352 -- 2009.............................................. 6,123 -- ------- ---- Total............................................. $62,642 $651 ======= ====
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 before the Plains merger 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 utilization of the remaining net operating losses for income tax purposes 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. The Internal Revenue Service ("IRS") has examined the federal tax returns of Plains Petroleum Company, a subsidiary of Barrett Resources Corporation, for the 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 F-20 BARRETT RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) (INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED) determination of this matter will involve a lengthy process. On November 29, 1996 the Company filed a petition with the United States Tax Court to request the IRS notice of deficiency be redetermined by allowing the net operating losses deductions as originally reported. During the nine months ended September 30, 1996 the Company acquired oil and gas properties in purchase transactions that qualify as tax-free exchanges for tax purposes. The Company deferred income taxes payable of $10.1 million for the estimated income tax effect of the difference between the financial and tax basis of the properties acquired. 12. SUPPLEMENTAL CASH FLOW SCHEDULES AND INFORMATION CASH PAID DURING YEARS:
1994 1995 1996 ---- ---- ------ (IN THOUSANDS) Income taxes................................................ $426 $338 $ 65 Interest.................................................... 792 711 5,129
SUPPLEMENTAL INFORMATION OF NONCASH INVESTING AND FINANCING ACTIVITIES:
NINE MONTHS ENDED YEAR ENDED DECEMBER 31, SEPTEMBER 30, ----------------------- ------------------ 1993 1994 1995 1995 1996 ------- ------- ------- -------- --------- (IN THOUSANDS) Issuance of common stock for property and related deferred taxes......................... $ -- $ -- $ -- $ -- $ 31,603 Treasury shares purchased in option transactions........... 204 313 545 157 527
In May 1994, Plains completed a contingent provision of the 1990 McAdams, Roux and Associates, Inc. ("MRA") Agreement and Plan of Merger, as it related to the right of the MRA shareholders to receive additional shares of Plains' common stock and cash subject to reserves additions on certain property interests owned by MRA prior to the merger. Under this Agreement, 31,873 shares of Plains' common stock were issued and a cash payment of $1.5 million was paid to MRA's shareholders in settlement of this obligation. 13. RELATED PARTIES During the years ended December 31, 1995, 1994 and 1993 Zenith Drilling Corporation ("Zenith") was billed by the Company as operator, approximately $1,062,000, $1,853,000 and $2,555,000, 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 ownership, the Company distributed oil and gas revenue of approximately $942,000, $936,000 and $1,074,000 to Zenith during 1995, 1994 and 1993, respectively. Zenith owns its working interests subject to the same terms and arrangements that exist for all working interest owners in the properties. Zenith owns approximately three percent of the Company's common stock and its president is a member of the Company's board of directors. F-21 BARRETT RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONCLUDED) (INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED) During 1993, the Company and Zenith both sold their respective interests in the Wattenberg field. The Company and Zenith jointly negotiated the sale but the purchaser independently determined the individual offer prices and entered into separate sales agreements with each party. Grand Valley Corporation owns approximately 10 percent of a pipeline joint venture for gas gathering of which a subsidiary of the Company owns approximately 29 percent. A member of the Company's board of directors owns 10 percent of the outstanding stock, and is the president of Grand Valley Corporation. His three adult children own the remaining 90 percent of the outstanding stock of Grand Valley Corporation. 14. QUARTERLY INFORMATION (UNAUDITED)
THREE MONTHS ENDED ----------------------------------------- 3/31/95 6/30/95 9/30/95 12/31/95 --------- --------- --------- ---------- (IN THOUSANDS, EXCEPT PER SHARE DATA) 1995 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 ----------------------------------------- 3/31/94 6/30/94 9/30/94 12/31/94 --------- --------- --------- ---------- (IN THOUSANDS, EXCEPT PER SHARE DATA) 1994 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 THREE MONTHS ENDED ----------------------------------------- 3/31/93 6/30/93 9/30/93 12/31/93 --------- --------- --------- ---------- (IN THOUSANDS, EXCEPT PER SHARE DATA) 1993 Net revenues..................... $ 30,258 $ 26,157 $ 22,836 $ 24,831 Gross margin..................... 8,832 8,759 6,902 7,346 Income from operations........... 6,163 5,649 4,845 4,386 Income before cumulative effect of change in method of accounting for income taxes..... 3,828 3,492 3,934 3,068 Net income........... ........... 3,172 3,492 3,934 3,068 Earnings per share: From continuing operations..... .16 .14 .16 .12 Net income..................... .13 .14 .16 .12
F-22 SUPPLEMENTAL OIL AND GAS INFORMATION The following is information pertaining to the Company's oil and gas producing activities for the years ended December 31, 1995, 1994 and 1993. Costs incurred in oil and gas property acquisition, exploration, and development activities:
1993 1994 1995 -------- ------- ------- (IN THOUSANDS) Acquisition of evaluated properties............... $ 6,119 $35,234 $ 7,429 Acquisition of unevaluated properties............. 1,013 8,446 8,383 Exploration costs................................. 12,593 36,232 23,272 Development costs................................. 21,538 20,190 33,029 Other, principally proceeds from mineral convey- ances............................................ (15,680) (173) (426) -------- ------- ------- Total additions to oil and gas properties....... $ 25,583 $99,929 $71,687 ======== ======= =======
Oil and gas reserve information (unaudited): The following reserve related information for 1995 is based on estimates prepared by the Company. The 1995 reserve information for the Company, exclusive of the reserves owned by its subsidiary, Plains, were reviewed by Ryder Scott, an independent reservoir engineer. The 1995 reserve information for Plains was reviewed by Netherland, Sewell & Associates, Inc., an independent reservoir engineer. The Company's 1994 and 1993 reserves, exclusive of Plains were prepared by the Company and reviewed by Ryder Scott as of September 30, of each year. The 1994 and 1993 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.
1993 1994 1995 --------------------- --------------------- --------------------- OIL (MBBL) GAS (MMCF) OIL (MBBL) GAS (MMCF) OIL (MBBL) GAS (MMCF) ---------- ---------- ---------- ---------- ---------- ---------- (IN THOUSANDS) Proved developed and undeveloped reserves: Beginning of year....... 10,553 370,621 6,947 364,791 11,444 458,820 Revisions of previous estimates.............. (3,426) (5,418) 772 (5,640) 1,209 (3,805) Purchase of minerals in place.................. 217 6,794 2,533 38,717 831 3,983 Extensions and discover- ies.................... 1,208 28,482 2,547 94,276 1,232 102,329 Production.............. (1,293) (31,712) (1,293) (33,282) (1,702) (47,692) Sale of minerals in place.................. (312) (3,976) (62) (42) (47) (104) ------ ------- ------ ------- ------ ------- End of year............. 6,947 364,791 11,444 458,820 12,967 513,531 ====== ======= ====== ======= ====== ======= Proved developed re- serves: Beginning of year....... 7,398 350,131 5,548 342,287 7,848 393,051 ====== ======= ====== ======= ====== ======= End of year............. 5,548 342,287 7,848 393,051 11,669 419,672 ====== ======= ====== ======= ====== =======
F-23 The following is the standardized measure of discounted future net cash flows relating to proved oil and gas reserves in which the Company has an interest.
1993 1994 1995 --------- --------- ---------- (IN THOUSANDS) Future cash inflows...................... $ 789,693 $ 931,404 $1,132,711 Future production costs.................. (266,920) (310,485) (355,756) Future development costs................. (22,349) (41,972) (46,888) Future income tax expenses............... (135,165) (152,890) (207,922) --------- --------- ---------- Future net cash flows.................. 365,259 426,057 522,145 10% annual discount for estimated timing of cash flows........................... (162,173) (183,436) (212,271) --------- --------- ---------- Standardized measure of discounted future net cash flows.......................... $ 203,086 $ 242,621 $ 309,874 ========= ========= ==========
The future income tax expenses have been computed considering the tax basis of the oil and gas properties, and net operating and other loss carryforwards. The following are the principal sources of changes in the standardized measure of discounted future net cash flows:
1993 1994 1995 -------- --------- -------- (IN THOUSANDS) Net change in sales price and production costs...................................... $ 12,283 $ (22,409) $ 24,558 Changes in estimated future development costs...................................... 11,160 14,492 10,301 Sales and transfers of oil and gas produced, net of production costs.................... (53,594) (50,571) (62,294) Net change due to extensions and discover- ies........................................ 20,739 60,613 85,524 Net change due to purchases and sales of minerals in place.......................... (1,210) 32,726 7,424 Net change due to revisions in quantities... (18,272) (588) (1,393) Net change in income taxes.................. (4,711) (10,202) (33,172) Accretion of discount....................... 26,965 27,589 23,112 Other, principally revisions in estimates of timing of production....................... 5,859 (12,115) 13,193 -------- --------- -------- Net changes................................. (781) 39,535 67,253 Balance, beginning of year.................. 203,867 203,086 242,621 -------- --------- -------- Balance, end of year........................ $203,086 $ 242,621 $309,874 ======== ========= ========
F-24 - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- NO PERSON HAS BEEN AUTHORIZED TO GIVE ANY INFORMATION OR TO MAKE ANY REPRE- SENTATIONS OTHER THAN THOSE CONTAINED IN THIS PROSPECTUS, AND, IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATIONS MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL OR THE SOLICITATION OF AN OFFER TO BUY ANY SECURITIES OTHER THAN THE SECURITIES TO WHICH IT RELATES OR AN OFFER TO SELL OR THE SOLICITATION OF AN OFFER TO BUY SUCH SECURITIES IN ANY CIRCUMSTANCES IN WHICH SUCH OFFER OR SOLICITATION IS UNLAWFUL. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE ANY IMPLICATION THAT THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF THE COMPANY SINCE THE DATE HEREOF OR THAT THE INFOR- MATION CONTAINED HEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT TO ITS DATE. ---------------- TABLE OF CONTENTS
PAGE ---- Prospectus Summary....................................................... 3 Risk Factors............................................................. 9 Use of Proceeds.......................................................... 12 Capitalization........................................................... 13 Management's Discussion and Analysis of Financial Condition and Results of Operations........................................................... 14 Disclosure Regarding Forward-Looking Statements.......................... 19 Business and Properties.................................................. 20 Management............................................................... 37 Beneficial Owners of Securities.......................................... 41 Description of Notes..................................................... 43 Underwriting............................................................. 53 Legal Matters............................................................ 54 Experts.................................................................. 54 Available Information.................................................... 54 Incorporation of Certain Documents by Reference.......................... 55 Certain Definitions...................................................... 55 Index to Consolidated Financial Statements............................... F-1
$150,000,000 BARRETT RESOURCES CORPORATION 7.55% SENIOR NOTES DUE 2007 ---------------- [LOGO OF BARRETT RESOURCES CORPORATION APPEARS HERE] ---------------- GOLDMAN, SACHS & CO. CHASE SECURITIES INC. LEHMAN BROTHERS PETRIE PARKMAN & CO. - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- -----END PRIVACY-ENHANCED MESSAGE-----