-----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, T3IWj4Q2bVzx3Nte3HKWNuTPRazipbmJeCD9d9ebgvf98P0foWbcyqH4rF09/wPm 8x2S+A94hGkJhi/i/MKHDQ== 0000950129-98-001129.txt : 19980323 0000950129-98-001129.hdr.sgml : 19980323 ACCESSION NUMBER: 0000950129-98-001129 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 8 CONFORMED PERIOD OF REPORT: 19971231 FILED AS OF DATE: 19980320 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: CABOT OIL & GAS CORP CENTRAL INDEX KEY: 0000858470 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 043072771 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-10447 FILM NUMBER: 98570384 BUSINESS ADDRESS: STREET 1: 15375 MEMORIAL DR CITY: HOUSTON STATE: TX ZIP: 77079 BUSINESS PHONE: 7135894600 10-K 1 CABOT OIL & GAS CORPORATION - DATED 12/31/97 1 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Fiscal year ended December 31, 1997 Commission file number 1-10447 CABOT OIL & GAS CORPORATION (Exact name of registrant as specified in its charter) DELAWARE 04-3072771 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification Number) 15375 MEMORIAL DRIVE, HOUSTON, TEXAS 77079 (Address of principal executive offices including Zip Code) (281) 589-4600 (Registrant's telephone number) Securities registered pursuant to Section 12(b) of the Act: Name of each exchange Title of each class on which registered CLASS A COMMON STOCK, PAR VALUE $.10 PER SHARE NEW YORK STOCK EXCHANGE RIGHTS TO PURCHASE PREFERRED STOCK NEW YORK STOCK EXCHANGE Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. Yes X No --- --- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K [ ]. The aggregate market value of Class A Common Stock, par value $.10 per share ("Common Stock"), held by non-affiliates (based upon the closing sales price on the New York Stock Exchange on February 27, 1998), was approximately $510,000,000. As of February 27, 1998, there were 24,680,936 shares of Common Stock outstanding. DOCUMENTS INCORPORATED BY REFERENCE Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held May 12, 1998 are incorporated herein by reference in Items 10, 11, 12, and 13 of Part III of this report. 2 TABLE OF CONTENTS
PART I PAGE ITEMS 1 AND 2 Business and Properties 2 ITEM 3 Legal Proceedings 16 ITEM 4 Submission of Matters to a Vote of Security Holders 16 Executive Officers of the Registrant 16 PART II ITEM 5 Market for Registrant's Common Equity and Related Stockholder Matters 17 ITEM 6 Selected Historical Financial Data 18 ITEM 7 Management's Discussion and Analysis of Financial Condition and Results of Operations 19 ITEM 8 Financial Statements and Supplementary Data 29 ITEM 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 56 PART III ITEM 10 Directors and Executive Officers of the Registrant 56 ITEM 11 Executive Compensation 56 ITEM 12 Security Ownership of Certain Beneficial Owners and Management 56 ITEM 13 Certain Relationships and Related Transactions 56 PART IV ITEM 14 Exhibits, Financial Statement Schedules and Reports on Form 8-K 57
---------- The statements regarding future financial performance and results and market prices and the other statements which are not historical facts contained in this report are forward-looking statements. The words "expect," "project," "estimate," "believe," "anticipate," "intend," "budget," "predict" and similar expressions are also intended to identify forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including regional basis differentials) of natural gas and oil, results for future drilling and marketing activity, future production and costs and other factors detailed herein and in the Company's other Securities and Exchange Commission filings. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. 1 3 PART I ITEM 1. BUSINESS GENERAL Cabot Oil & Gas Corporation (the "Company") explores for, develops, produces, stores, transports, purchases and markets natural gas and, to a lesser extent, produces and sells crude oil. Substantially all of the Company's operations are in the Appalachian Region of West Virginia and Pennsylvania and in the Western Region, including the Anadarko Basin of southwestern Kansas, Oklahoma and the Texas Panhandle, the Green River Basin of Wyoming, and South Texas. At December 31, 1997, the Company had approximately 938.6 Bcfe of total proved reserves, 96% of which was natural gas. A significant portion of the Company's natural gas reserves is located in long-lived fields with extended production histories. The Company, a Delaware corporation, was organized in 1989 as the successor to the oil and gas business of Cabot Corporation ("Cabot"), which was begun in 1891. In 1990, the Company completed its initial public offering of approximately 18% of the outstanding common stock held by Cabot. Cabot distributed the remaining common stock of the Company to the shareholders of Cabot in 1991. The Company has been publicly traded on the New York Stock Exchange since its initial public offering. Unless the context otherwise requires, all references herein to the Company include Cabot Oil & Gas Corporation, its predecessors and subsidiaries. Similarly, all references to Cabot include Cabot Corporation and its affiliates. All references to wells are gross, unless otherwise stated. The following table summarizes certain information, at December 31, 1997 regarding the Company's proved reserves, productive wells, developed and undeveloped acreage and infrastructure. SUMMARY OF RESERVES, PRODUCTION, ACREAGE AND OTHER INFORMATION BY AREAS OF OPERATION (1)
Total Appalachian Western Company Region Region(2) - -------------------------------------------------------------------------------- RESERVES/PRODUCTION: Proved reserves Developed (Bcfe) 767.9 346.4 421.5 Undeveloped (Bcfe) 170.7 71.5 99.2 --------- ------- ------- Total (Bcfe) 938.6 417.9 520.7 ========= ======= ======= Daily production (Mmcfe) net 185.4 70.2 115.2 Gross productive wells 4,242.0 2,905.0 1,337.0 Net productive wells 3,441.4 2,696.4 745.0 Percent of wells operated 84.8% 96.7% 58.8% ACREAGE: Net acreage Developed acreage 1,003,603 719,840 283,763 Undeveloped acreage 373,946 255,037 118,909 --------- ------- ------- Total 1,377,549 974,877 402,672 ========= ======= ======= - --------------------------------------------------------------------------------
(1) As of December 31, 1997. For additional information regarding the Company's estimates of proved reserves and other data, see "Business--Reserves," and the "Supplemental Oil and Gas Information" to the Consolidated Financial Statements. (2) Includes all properties outside the Appalachian Region, including properties located in Anadarko, the Rocky Mountains and the Gulf Coast areas. 2 4 EXPLORATION, DEVELOPMENT AND PRODUCTION The Company is one of the largest producers of natural gas in the Appalachian basin, where it has conducted operations for more than a century. The Company has had operations in the Anadarko basin for over 60 years. The Company acquired its operations in the Rocky Mountains and the Gulf Coast pursuant to the merger of Washington Energy Resources Company with the Company which was completed in May 1994. Historically, the Company has maintained its reserve base through low-risk development drilling and strategic acquisitions, and recently has stepped up its emphasis on exploration. The Company continues to focus its operations in the Appalachian and Western Regions through development of undeveloped reserves and acreage, acquisition of oil and gas producing properties and new exploration opportunities. While continuing its strong development drilling program, the Company has significantly expanded its exploration program in the last two years. Both the Appalachian and Western Regions added more exploratory wells to their respective drilling programs in 1997, increasing from 25 to 33 wells in Appalachia and from 5 to 13 wells in the West. Both regions had favorable results in the 1997 program with success rates of 76% and 46%, in the Appalachian and Western Regions, respectively. A large part of the exploration activity in the Western Region has been focused in the Gulf Coast area. In 1997, reserves in the Gulf Coast area grew from 27.1 Bcfe to 56.5 Bcfe, or 108%, due primarily to the Company's exploratory drilling strategy. The Company's 1998 exploration program includes drilling expenditures of $17 million, which represents 24% of the planned 1998 drilling program. APPALACHIAN REGION The Company's exploration, development and production activities in the Appalachian Region are concentrated in Pennsylvania, Ohio, West Virginia, and Virginia. Operations are managed by a regional office in Pittsburgh. At December 31, 1997, the Company had approximately 417.9 Bcfe of proved reserves (substantially all natural gas) in the Appalachian Region, constituting 45% of the Company's total proved reserves. The Company has 2,905 productive wells (2,696.4 net), of which 2,810 wells are operated by the Company. There are multiple producing intervals which include the Upper Devonian, Oriskany, Berea, and Big Lime trend formations at depths primarily ranging from 1,500 to 6,000 feet. Average net daily production in 1997 was 70.0 Mmcfe. While natural gas production volumes from Appalachian reservoirs are relatively low on a per-well basis compared to other areas of the United States, the productive life of Appalachian reserves is relatively long. In October 1997, the Company sold 912 wells primarily located in northwest Pennsylvania (the "Meadville properties") which have been producing approximately 15 Mmcfe per day from the Medina formation to Lomak Petroleum Incorporated. In 1997, the Company drilled 120 wells (96.8 net) in the Appalachian Region, of which 87 were development wells (78.7 net). Capital and exploration expenditures, including pipeline expenditures for the year were $38.0 million. In the 1998 drilling program year, the Company has plans to drill 126 wells. At December 31, 1997, the Company had 974,877 net acres in the region, including 719,840 net developed acres. At year end, the Company had identified 205 proved undeveloped drilling locations. The Company also owns and operates a brine treatment plant near Franklin, Pennsylvania. The plant, which began operating in 1985, processes and treats waste fluid generated during the drilling, completion and subsequent production of oil and gas wells. The plant provides services to the Company and certain other oil and gas producers in southwestern New York, eastern Ohio and western Pennsylvania. The Company believes that it gains operational efficiency in the Appalachian Region because of its large acreage position, high concentration of wells, natural gas gathering and pipeline systems and storage capacity. 3 5 WESTERN REGION The Company's exploration, development and production activities in the Western Region are primarily focused in the Anadarko basin in Kansas, Oklahoma and the Panhandle of Texas, in the Green River Basin of Wyoming and in South Texas. Operations for the Western Region are managed from a regional office in Denver and include the Anadarko, Rocky Mountain and Gulf Coast areas. At December 31, 1997, the Company had approximately 520.7 Bcfe of proved reserves (93.8% natural gas) in the Western Region, constituting 55% of the Company's total proved reserves. ANADARKO The Company has 760 productive wells (502.2 net) in the Anadarko area of which 556 wells are operated by the Company. Principal producing intervals in Anadarko are in the Chase, Morrow and Chester formations at depths ranging from 1,500 to 11,000 feet. Average net daily production in 1997 was 46.5 Mmcfe. In 1997, the Company drilled 35 wells (17.8 net) in Anadarko, including 32 development wells (16.2 net). Capital and exploration expenditures for the year were $13.8 million. In the 1998 drilling program year, the Company has plans to drill 45 wells. At December 31, 1997, the Company had approximately 224,860 net acres, including approximately 190,306 net developed acres. At year end, the Company had identified 57 proved undeveloped drilling locations. ROCKY MOUNTAINS The Company has 420 productive wells (185.7 net) in the Rocky Mountain area of which 196 wells are operated by the Company. Principal producing intervals in Rocky Mountain are in the Frontier and Dakota formations at depths ranging from 9,000 to 13,000 feet. Average net daily production in 1997 was 43.0 Mmcfe. In October 1997, the Company acquired oil and gas producing properties from Equitable Resources Energy Company in the Green River Basin of Wyoming (the "Green River properties"). These properties included approximately 72 Bcfe of reserves, interests in 63 wells with estimated daily net production of 10 Mmcfe, and nearly 70 potential drilling locations. This acquisition increased the Company's reserves in the area by 46%. In 1997, the Company drilled 50 wells (26.6 net) in the Rocky Mountains including 49 development wells (26.2 net). Capital and exploration expenditures for the year were $61.9 million, including approximately $45 million for the Green River property acquisition. In the 1998 drilling program year, the Company has plans to drill 68 wells. At December 31, 1997, the Company had approximately 150,421 net acres, including approximately 76,507 net developed acres. At year end, the Company had identified 75 proved undeveloped drilling locations. GULF COAST The Company has 157 productive wells (57.1 net) in the Gulf Coast area of which 34 wells are operated by the Company. Principal producing intervals in Gulf Coast are in the Frio, Wilcox and Vicksburg formations at depths ranging from 6,000 to 14,000 feet. Average net daily production in 1997 was 25.3 Mmcfe. In 1997, the Company drilled 20 wells (10.3 net) in the Gulf Coast including 11 development wells (6.7 net). Capital and exploration expenditures for the year were $25.4 million. In the 1998 drilling program year, the Company has plans to drill 31 wells. At December 31, 1997, the Company had approximately 27,391 net acres, including approximately 16,950 net developed acres. At year end, the Company had identified 5 proved undeveloped drilling locations. 4 6 GAS MARKETING The Company is engaged in a wide array of marketing activities designed to offer its customers long-term, reliable supplies of natural gas. Utilizing its pipeline and storage facilities, gas procurement ability and transportation and natural gas risk management expertise, the Company provides a menu of services that includes gas supply and transportation management, short and long-term supply contracts, capacity brokering and risk management alternatives. The marketing of natural gas has changed significantly as a result of FERC Order 636 ("Order 636"), which was issued by the Federal Energy Regulatory Commission in 1992. Order 636 required pipelines to unbundle their gas sales, storage and transportation services. As a result, local distribution companies and end-users will separately contract these services from gas marketers and producers. Order 636 has had the effect of creating greater competition in the industry while also providing the Company the opportunity to serve broader markets. Since Order 636 was issued, there has been an increase in the number of third-party producers that use the Company to market their gas. In addition, the Company has experienced, as a result of Order 636, increased competition for markets which has placed pressure on the premiums it has received. APPALACHIAN REGION The Company's principal markets for its Appalachian Region natural gas are in the northeastern United States. The Company's marketing subsidiary purchases the Company's natural gas production in the Appalachian Region as well as production from local third-party producers and other suppliers to aggregate larger volumes of natural gas for resale. This marketing subsidiary sells natural gas to industrial customers, local distribution companies ("LDCs") and gas marketers both on and off the Company's pipeline and gathering system. A majority of the Company's natural gas sales volume in the Appalachian Region is being sold at market -responsive prices under contracts with a term of one year or less. Of these short-term sales, spot market sales are made under month-to-month contracts while industrial and utility sales generally are made under year-to-year contracts. Approximately 15% of the Appalachian production is sold on fixed price contracts which typically renew annually. The Company's Appalachian production is generally sold at a premium price compared to production from other producing regions due to its close proximity to eastern markets. However, that premium has been reduced from historic levels due to increased competition in the market place resulting in part from changes in transportation and sales arrangements due to the implementation of pipeline open access tariffs and Order 636. The Company operates a number of gas gathering and pipeline systems, made up of approximately 2,800 miles of pipeline with interconnects to three interstate pipeline systems and five LDCs. The Company's natural gas gathering and pipeline systems enable the Company to connect new wells quickly and to transport natural gas from the wellhead directly to interstate pipelines, LDCs and industrial end-users. Control of its gathering and pipeline systems also enables the Company to purchase, transport and sell natural gas produced by third parties. In addition, the Company can undertake development drilling operations without relying upon third parties to transport its natural gas while incurring only the incremental costs of pipeline and compressor additions to its system. The Company has two natural gas storage fields located in West Virginia, with a combined working capacity of approximately 4 Bcf of natural gas. The Company uses these storage fields to take advantage of the seasonal variations in the demand for natural gas and the higher prices typically associated with winter natural gas sales, while maintaining production at a nearly constant rate throughout the year. The storage fields also enable the Company to periodically increase the volume of natural gas it can deliver by more than 40% above the volume that it could deliver solely from its production in the Appalachian Region. The pipeline systems and storage fields are fully integrated with the Company's producing operations. 5 7 WESTERN REGION The Company's principal markets for Western Region natural gas are in the northwestern, midwestern, and northeastern United States. The Company's marketing subsidiary purchases all of the Company's natural gas production in the Western Region. This marketing subsidiary sells the natural gas to cogenerators, natural gas processors, LDCs, industrial customers and marketing companies. Currently, a majority of the Company's natural gas production in the Western Region is being sold primarily under contracts with a term of one year or less at market-responsive prices. Approximately 15% of the Western Region's production is sold under a 15 year cogeneration contract with 11 years remaining that escalates in price by 5% per year (See Item 3. Legal Proceedings). The Western Region properties are connected to the majority of the Midwestern, Northwestern, and Gulf Coast interstate and intrastate pipelines, affording the Company access to multiple markets. The Company also produces and markets approximately 1,400 barrels a day of crude oil/condensate in the Western Region at market responsive prices. RISK MANAGEMENT In 1997, the Company entered into certain transactions to manage price risks associated with its production and purchase commitments. The Company utilized certain natural gas price swap agreements ("price swaps") to attempt to manage price risk more effectively and improve the Company's realized natural gas prices. These price swaps call for payments to (or to receive payments from) counterparties based upon the differential between a fixed and a variable gas price. The Company plans to continue to evaluate on an ongoing basis the benefit of this strategy in the future. See the Overview section of Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, or Note 13 of the Notes to the Consolidated Financial Statements for further discussion. 6 8 RESERVES CURRENT RESERVES The following table sets forth information regarding the Company's estimates of its net proved reserves at December 31, 1997.
Natural Gas (Mmcf) Liquids(1) (Mbbl) Total(2) (Mmcfe) - ----------------------------------------------------------------------------------------------------------------------- Developed Undeveloped Total Developed Undeveloped Total Developed Undeveloped Total - ----------------------------------------------------------------------------------------------------------------------- Appalachian 343,718 71,500 415,218 447 0 447 346,400 71,500 417,900 Western(3) 395,046 93,165 488,211 4,412 1,010 5,422 421,519 99,224 520,743 ------- ------- ------- ----- ----- ----- ------- ------- ------- Total 738,764 164,665 903,429 4,859 1,010 5,869 767,919 170,724 938,643 ======= ======= ======= ===== ===== ===== ======= ======= ======= - -----------------------------------------------------------------------------------------------------------------------
(1) Liquids include crude oil, condensate and natural gas liquids (Ngl). (2) Natural Gas Equivalents are determined using the ratio of 6.0 Mcf of natural gas to 1.0 Bbl of crude oil or condensate. (3) Includes proved reserves attributable to Anadarko, Rocky Mountains and the Gulf Coast Areas. The proved reserve estimates presented herein were prepared by the Company's petroleum engineering staff and reviewed by Miller and Lents, Ltd., independent petroleum engineers. For additional information regarding the Company's estimates of proved reserves, the review of such estimates by Miller and Lents, Ltd. and certain other information regarding the Company's oil and gas reserves, see the Supplemental Oil and Gas Information to the Consolidated Financial Statements included in Item 8 hereof. A copy of the review letter by Miller and Lents, Ltd., has been filed as an exhibit to this Form 10-K. The Company's estimates of proved reserves set forth in the foregoing table do not differ materially from those filed by the Company with other federal agencies. The Company's reserves are sensitive to natural gas sales prices and their effect on economic producing rates. The Company's reserves are based on oil and gas prices in effect at December 31, 1997. There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond the control of the Company and, therefore, the reserve information set forth in this Form 10-K represents only estimates. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner, and 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 often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based. In general, the volume of production from oil and gas properties owned by the Company declines as reserves are depleted. Except to the extent the Company acquires additional properties containing proved reserves or conducts successful exploration and development activities or both, the proved reserves of the Company will decline as reserves are produced. 7 9 HISTORICAL RESERVES The following table sets forth certain information regarding the Company's estimated proved reserves for the periods indicated.
Oil, Condensate Natural Gas (Mmcf) & NGLs (Mbbl) Total (Mmcfe) - ---------------------------------------------------------------------------------------------------------------------------- APP WEST TOTAL APP WEST TOTAL APP WEST TOTAL - ---------------------------------------------------------------------------------------------------------------------------- DECEMBER 31, 1994 560,494 392,589 953,083 167 7,869 8,036 561,496 439,803 1,001,299 Revisions of prior estimates 3,699 10,333 14,032 65 (713) (648) 4,086 6,061 10,147 Extensions, discoveries and other additions 12,333 22,075 34,408 23 151 174 12,471 22,982 35,453 Production (27,530) (30,191) (57,721) (18) (722) (740) (27,637) (34,525) (62,162) Purchases of reserves in place 576 840 1,416 0 15 15 576 929 1,505 Sales of reserves in place (34,016) (21,352) (55,368) (18) (1,509) (1,527) (34,123) (30,412) (64,535) ------- ------- ------- --- ----- ----- ------- ------- --------- DECEMBER 31, 1995 515,556 374,294 889,850 219 5,091 5,310 516,869 404,838 921,707 ------- ------- ------- --- ----- ----- ------- ------- --------- Revisions of prior estimates (487) 3,261 2,774 (2) (130) (132) (501) 2,481 1,980 Extensions, discoveries and other additions 40,703 29,005 69,708 137 249 386 41,526 30,500 72,026 Production (26,783) (31,979) (58,762) (21) (576) (597) (26,910) (35,435) (62,345) Purchases of reserves in place 21,207 16,190 37,397 8 207 215 21,255 17,430 38,685 Sales of reserves in place (23,337) (2,013) (25,350) (7) (9) (16) (23,377) (2,065) (25,442) ------- ------- ------- --- ----- ----- ------- ------- --------- DECEMBER 31, 1996 526,859 388,758 915,617 334 4,832 5,166 528,862 417,749 946,611 ------- ------- ------- --- ----- ----- ------- ------- --------- Revisions of prior estimates 2,929 3,815 6,744 67 32 99 3,327 4,009 7,336 Extensions, discoveries and other additions 42,609 66,582 109,191 147 647 794 43,493 70,463 113,956 Production (25,340) (38,549) (63,889) (48) (581) (629) (25,628) (42,035) (67,663) Purchases of reserves in place 5,355 68,481 73,836 2 592 594 5,366 72,035 77,401 Sales of reserves in place (137,194) (876) (138,070) (55) (100) (155) (137,520) (1,478) (138,998) ------- ------- ------- --- ----- ----- ------- ------- --------- DECEMBER 31, 1997 415,218 488,211 903,429 447 5,422 5,869 417,900 520,743 938,643 ======= ======= ======= === ===== ===== ======= ======= ========= PROVED DEVELOPED RESERVES: December 31, 1994 474,574 331,339 805,913 167 7,537 7,704 475,576 376,561 852,137 December 31, 1995 430,165 317,070 747,235 219 4,751 4,970 431,477 345,579 777,056 December 31, 1996 434,558 333,540 768,097 334 4,351 4,685 436,560 359,646 796,206 December 31, 1997 343,718 395,046 738,764 447 4,412 4,859 346,400 421,519 767,919 - ------------------------------------------------------------------------------------------------------------------------------------
APP = Appalachian Region WEST = Western Region Note: Natural gas equivalents are determined using the ratio of 6.0 Mcf of natural gas to 1.0 Bbl of crude oil or condensate. VOLUMES AND PRICES; PRODUCTION COSTS The following table sets forth historical information regarding the Company's sales and production volumes and average sales prices received for, and average production costs associated with, its sales of natural gas and crude oil, condensate and natural gas liquids (Ngl) for the periods indicated. 8 10
Year Ended December 31, 1997 1996 1995 - --------------------------------------------------------------------------------------- NET WELLHEAD SALES VOLUME: Natural Gas (Bcf)(1) Appalachian Region 25.3 26.2 26.4 Western Region(2) 38.6 32.6 29.8 Crude/Condensate/Ngl (Mbbl) Appalachian Region 48 21 18 Western Region 584 576 722 PRODUCED NATURAL GAS SALES PRICE $(/MCF)(3) Appalachian Region $ 3.00 $ 2.72 $ 2.22 Western Region $ 2.22 $ 2.02 $ 1.33 Weighted Average $ 2.53 $ 2.34 $ 1.75 Crude/Condensate Sales Price ($/Bbl)(3) $20.13 $ 21.14 $ 17.95 Production Costs ($/Mcfe)(4) $ 0.58 $ 0.56 $ 0.55 - ---------------------------------------------------------------------------------------
(1) Equal to the aggregate of production and the net changes in storage and exchanges. (2) Includes information regarding Anadarko, Rocky Mountains and Gulf Coast. (3) Represents the average sales prices for all production volumes (including royalty volumes) sold by the Company during the periods shown net of related costs (principally purchased gas royalty, transportation and storage). (4) Production costs include direct lifting costs (labor, repairs and maintenance, materials and supplies), and the costs of administration of production offices, insurance and property and severance taxes but is exclusive of depreciation and depletion applicable to capitalized lease acquisition, exploration and development expenditures. 9 11 ACREAGE The following tables summarize the Company's gross and net developed and undeveloped leasehold and mineral acreage at December 31, 1997. Acreage in which the Company's interest is limited to royalty and overriding royalty interests is excluded. LEASEHOLD ACREAGE
At December 31, 1997 Developed Undeveloped Total - ----------------------------------------------------------------------------------------------------------------- Gross Net Gross Net Gross Net - ----------------------------------------------------------------------------------------------------------------- STATE Alabama -- -- 312 312 312 312 Arkansas 240 6 -- -- 240 6 Colorado 24,474 20,771 32,264 29,141 56,738 49,912 Indiana 739 369 53,485 26,457 54,224 26,826 Kansas 33,264 28,850 1,278 896 34,542 29,746 Kentucky 2,680 990 15,679 7,657 18,359 8,647 Louisiana 2,070 357 3,419 542 5,489 899 Michigan 809 178 6,228 1,362 7,037 1,540 Montana 157 52 680 303 837 355 New York 2,520 1,057 3,461 2,853 5,981 3,910 North Dakota 160 20 870 96 1,030 116 Ohio 5,088 1,905 41,060 28,223 46,148 30,128 Oklahoma 182,867 119,611 46,776 31,107 229,643 150,718 Pennsylvania 93,998 77,294 34,913 22,656 128,911 99,950 Texas 77,412 44,290 26,079 11,663 103,491 55,953 Utah 1,740 530 20,653 17,274 22,393 17,804 Virginia 22,091 20,045 24,849 12,279 46,940 32,324 West Virginia 567,650 524,600 119,838 96,088 687,488 620,688 Wyoming 113,729 55,094 59,805 27,019 173,534 82,113 --------- ------- ------- ------- --------- --------- Total 1,131,688 896,019 491,649 315,928 1,623,337 1,211,947 ========= ======= ======= ======= ========= =========
MINERAL FEE ACREAGE
At December 31, 1997 Developed Undeveloped Total - ----------------------------------------------------------------------------------------------------------------- Gross Net Gross Net Gross Net - ----------------------------------------------------------------------------------------------------------------- STATE Colorado 279 40 160 6 439 46 Kansas 160 128 -- -- 160 128 Montana -- -- 589 75 589 75 New York -- -- 4,281 1,070 4,281 1,070 Oklahoma 16,889 13,987 240 49 17,129 14,036 Pennsylvania 86 86 1,573 502 1,659 588 Texas 27 27 857 426 884 453 Virginia 17,817 17,817 100 34 17,917 17,851 West Virginia 89,264 75,499 56,817 55,856 146,081 131,355 --------- --------- ------- ------- --------- --------- Total 124,522 107,584 64,617 58,018 189,139 165,602 ========= ========= ======= ======= ========= ========= Aggregate Total 1,256,210 1,003,603 556,266 373,946 1,812,476 1,377,549 ========= ========= ======= ======= ========= =========
10 12 Total Net Acreage by Area of Operation
At December 31, 1997 Developed Undeveloped Total - ------------------------------------------------------------------------------------------------------ Appalachian Region 719,840 255,037 974,877 Western Region 283,763 118,909 402,672 --------- ------- --------- Total 1,003,603 373,946 1,377,549 ========= ======= =========
PRODUCTIVE WELL SUMMARY(1) The following table reflects the Company's ownership at December 31, 1997 in natural gas and oil wells in the Appalachian Region (consisting of various fields located in West Virginia, Pennsylvania, New York, Ohio, Virginia and Kentucky), and in the Western Region (consisting of various fields located in Louisiana, Oklahoma, Texas, Kansas, North Dakota, Utah, Colorado and Wyoming).
Natural Gas Oil Total Gross Net Gross Net Gross Net - ------------------------------------------------------------------------------------------------------------------ Appalachian Region 2,883 2,684.9 22 11.5 2,905 2,696.4 Western Region 1,134 659.8 203 85.2 1,337 745.0 ---------------------------------------------------------------------------- Total 4,017 3,344.7 225 96.7 4,242 3,441.4 ============================================================================ - ------------------------------------------------------------------------------------------------------------------
(1) "Productive" wells are producing wells and wells capable of production in which the Company has a working interest. DRILLING ACTIVITY The Company drilled, participated in the drilling of, or acquired wells as set forth in the table below for the periods indicated:
Year Ended December 31, 1997 1996 1995 - ---------------------------------------------------------------------------------------------- GROSS NET Gross Net Gross Net - ---------------------------------------------------------------------------------------------- APPALACHIAN REGION: Development Wells Natural Gas 82 73.7 85 81.6 17 16.4 Oil 0 0.0 1 1.0 0 0.0 Dry 5 5.0 12 12.0 5 4.3 Extension Wells Natural Gas 0 0.0 0 0.0 1 0.3 Oil 0 0.0 0 0.0 0 0.0 Dry 0 0.0 0 0.0 1 0.5 Exploratory Wells Natural Gas 20 10.9 10 5.0 2 0.5 Oil 5 0.9 5 0.9 2 0.5 Dry 8 6.3 10 5.2 5 2.0 --- ---- --- ----- -- ---- Total 120 96.8 123 105.7 33 24.5 === ==== === ===== == ==== Wells Acquired(1) Natural Gas 1 40.0 15 11.8 3 3.7 Oil 0 0.0 0 0.0 0 0.0 --- ---- --- ----- -- ---- Total 1 40.0 15 11.8 3 3.7 === ==== === ===== == ==== Wells in Progress at End of Period 4 3.1 2 1.5 3 3.0
11 13
Year Ended December 31, 1997 1996 1995 - ----------------------------------------------------------------------------------------------------------------- GROSS NET Gross Net Gross Net - ----------------------------------------------------------------------------------------------------------------- WESTERN REGION: Development Wells Natural Gas 72 32.3 40 26.5 33 17.1 Oil 1 0.9 0 0.0 3 1.9 Dry 5 3.7 14 8.7 7 3.3 Extension Wells Natural Gas 11 10.6 12 8.3 8 4.6 Oil 1 0.6 1 0.1 0 0.0 Dry 2 1.0 1 1.9 0 0.0 Exploratory Wells Natural Gas 5 1.6 1 0.6 1 0.3 Oil 1 1.0 0 0 0 0.0 Dry 7 2.9 4 2.4 8 3.9 --- ---- -- ---- -- ---- Total 105 54.6 73 48.5 60 31.1 === ==== == ==== == ==== Wells Acquired(1) Natural Gas 63 18.5 25 11.9 0 2.7 Oil 2 0.2 3 0.4 0 0.1 --- ---- -- ---- -- ---- Total 65 18.7 28 12.3 0 2.8 === ==== == ==== == ==== Wells in Progress at End of Period 6 3.3 4 1.5 6 5.3 - -----------------------------------------------------------------------------------------------------------------
(1)Includes the acquisition of net interest in certain wells in the Appalachian Region and in the Western Region in 1997, 1996 and 1995 in which the Company already held an ownership interest. COMPETITION Competition in the Company's primary producing areas is intense. The Company believes that its competitive position is affected by price, contract terms and quality of service, including pipeline connection times, distribution efficiencies and reliable delivery record. The Company believes that its extensive acreage position and existing natural gas gathering and pipeline systems and storage fields give it a competitive advantage over certain other producers in the Appalachian Region which do not have such systems or facilities in place. The Company also believes that its competitive position in the Appalachian Region is enhanced by the absence of significant competition from major oil and gas companies. The Company also actively competes against some companies with substantially larger financial and other resources, particularly in the Western Region. The Company also believes that its competitive position is enhanced by marketing its own gas through the operation of Cabot Oil & Gas Marketing Corporation. OTHER BUSINESS MATTERS MAJOR CUSTOMER The Company had no sales to any customer that exceeded 10% of the Company's total gross revenues in 1997. SEASONALITY Demand for natural gas has historically been seasonal in nature, with peak demand and typically higher prices occurring during the colder winter months. 12 14 REGULATION OF OIL AND NATURAL GAS PRODUCTION The Company's oil and gas production and transportation operations are subject to various types of regulation by federal, state and local authorities. The statutory law affecting the oil and natural gas industry is under constant review for amendment or expansion. Further, numerous departments and agencies, federal, state and local, have issued rules and regulations affecting the oil and natural gas industry and its individual members, compliance with which is often difficult and costly and some of which may carry substantial penalties for non-compliance. The regulatory burden on the oil and natural gas industry increases its cost of doing business and, consequently, affects its profitability. Inasmuch as such laws and regulations are frequently expanded, amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with such regulations. However, the Company does not believe that under present regulations it is affected in a significantly different manner by these regulations than others in the industry. EXPLORATION AND PRODUCTION The exploration and production operations of the Company are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandoning of wells. The Company's operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the density of wells which may be drilled in a given field and the unitization or pooling of oil and natural gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. In this regard, such states as Texas, Oklahoma and Louisiana have in recent years reviewed and substantially revised the methodologies previously used by them to gather the necessary information and make monthly determinations of appropriate field and well production allowables. The effect of these regulations is to limit the amounts of oil and natural gas the Company can produce from its wells, and to limit the number of wells or the locations at which the Company can drill. NATURAL GAS MARKETING, GATHERING AND TRANSPORTATION Federal legislation and regulatory controls have historically affected the price of the natural gas produced by the Company and the manner in which such production is transported and marketed. Under the Natural Gas Act of 1938, the Federal Energy Regulatory Commission (the "FERC") regulates the interstate transportation and the sale in interstate commerce for resale of natural gas. The FERC's jurisdiction over interstate sales of natural gas was substantially modified by the Natural Gas Policy Act, under which the FERC continued to regulate the maximum selling prices of certain categories of gas sold in "first sales" in interstate and intrastate commerce. Effective January 1, 1993, however, the Natural Gas Wellhead Decontrol Act (the "Decontrol Act") deregulated natural gas prices for all "first sales" of natural gas, which includes all sales by the Company of its own production. As a result, all of the Company's domestically produced natural gas may now be sold at market prices, subject to the terms of any private contracts which may be in effect. The FERC's jurisdiction over natural gas transportation was unaffected by the Decontrol Act. The Company's natural gas sales are affected by the regulation of intrastate and interstate gas transportation. In an attempt to restructure the interstate pipeline industry with the goal of providing enhanced access to, and competition among, alternative natural gas suppliers, the FERC, commencing in April 1992, issued Order Nos. 636, 636-A and 636-B ("Order No. 636") which have altered significantly the interstate transportation and sale of natural gas. Previously, the interstate pipelines had acted primarily as wholesalers of natural gas, purchasing the gas from producers in or within the vicinity of the production areas and reselling the gas to large industrial customers and local distribution companies. Among other things, Order No. 636 required interstate pipelines to unbundle their wholesale merchant services into the various constituent services, such as sales, transmission and storage, and to offer these "unbundled" services individually to their customers. By requiring interstate pipelines to "unbundle" their services and to provide their 13 15 customers with direct access to pipeline capacity, Order No. 636 enabled pipeline customers to choose the levels of transportation and storage service they require, as well as to purchase natural gas directly from third-party merchants other than the interstate pipelines and obtain transportation of such gas on a nondiscriminatory basis. Through similar orders pertaining to intrastate pipelines which provide certain interstate services, the FERC has expanded the impact of these so-called "open access" regulations to intrastate commerce. The effect of Order No. 636 and related orders has been to enable the Company to market its natural gas production to a wider variety of potential purchasers. The Company believes that these changes generally have improved the Company's access to transportation and have enhanced the marketability of its natural gas production. To date, Order No. 636 has not had any material adverse effect on the Company's ability to market and transport its natural gas production. However, even though Order No. 636 has been affirmed on appeal, with minor exceptions, and individual interstate pipelines have had final open access tariffs in place for several years, the FERC is continuing to review, assess and modify its transportation regulations and the Company cannot predict what new or different regulations may be adopted by the FERC and other regulatory authorities, or what effect subsequent regulations may have on the Company's activities. In recent years the FERC also has pursued a number of other important policy initiatives which have significantly affected the marketing of natural gas. Some of the more notable of these regulatory initiatives have included (i) a series of orders in individual pipeline proceedings articulating a policy of generally approving the voluntary divestiture of interstate pipeline-owned gathering facilities either to non-affiliated companies (a "spin off") or to the pipeline's nonregulated affiliate (a "spin down "), (ii) the completion of a rulemaking proceeding involving the regulation of pipelines with marketing affiliates under Order No. 497, (iii) FERC's ongoing efforts to promulgate standards for pipeline electronic bulletin boards and electronic data exchange, (iv) a generic inquiry into the pricing of interstate pipeline capacity, (v) efforts to refine FERC's regulations controlling the operation of the secondary market for released pipeline capacity, (vi) a policy statement and a series of orders in individual pipeline dockets regarding market-based rates and other non-cost-based rates for interstate pipeline transmission and storage capacity and (vii) appropriate ratemaking procedures for pipeline expansions and extensions. Several of these initiatives are intended to enhance competition in natural gas markets, although some, such as the so-called "spin-down" of previously regulated gathering facilities by interstate pipelines to their affiliates, may have the adverse effect on some in the industry of increasing the cost of doing business as a result of the potential for monopolization of those facilities by their new, unregulated owners. FERC attempted to address some of these concerns in its orders authorizing such "spin-downs," but one of its principal devices, the use of "default" contracts to assure continuity of gathering services for two years after spin down, was found unlawful on appeal. It remains to be seen what effect the FERC's other activities will have on access to markets and the cost to do business. In response to the FERC's policy of authorizing the interstate pipeline industry's divestiture of these gathering facilities, several states (most notably Oklahoma and Texas) enacted or are considering laws and regulations enhancing state level oversight over gathering. As to all of these recent FERC and state initiatives, the ongoing, or, in some instances, preliminary evolving nature of these regulatory initiatives makes it impossible to predict their ultimate impact upon the Company's activities. The Company's pipeline systems and storage fields are regulated for safety compliance by the U.S. Department of Transportation, the West Virginia Public Service Commission, the Pennsylvania Department of Natural Resources and the New York Department of Public Service. The Company's pipeline systems in each state operate independently and are not interconnected. ENVIRONMENTAL REGULATIONS General. The Company's operations are subject to extensive federal, state and local laws and regulations relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. Permits are required for the operation of various facilities of the Company, and these permits are subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines, injunctions or both. Such government regulation can increase the cost of planning, designing, installing and operating oil and gas facilities. In most instances, the regulatory requirements impose water and air pollution control measures. Although the Company believes that compliance with environmental regulations will not have a material adverse effect on the Company, risks of substantial costs and liabilities related to environmental compliance issues are inherent in oil and gas production operations, and no assurance can be given that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as stricter 14 16 environmental laws and regulations, and claims for damages to property or persons resulting from oil and gas production would result in substantial costs and liabilities to the Company. Solid and Hazardous Waste. The Company currently owns or leases, and has in the past owned or leased, numerous properties that have been used for production of oil and gas for many years. Although the Company has utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other solid wastes may have been disposed or released on or under the properties owned or leased by the Company. In addition, many of the properties have been operated by third parties. The Company had no control over such parties' treatment of hydrocarbons or other solid wastes and the manner in which such substances may have been disposed or released. State and federal laws applicable to oil and gas wastes and properties have gradually become stricter over time. Under these new laws, the Company could be required to remove or remediate previously disposed wastes (including wastes disposed or released by prior owners and operators) or property contamination (including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future contamination. The Company generates some wastes that are subject to the Federal Resource Conservation and Recovery Act ("RCRA") and comparable State statutes. The Environmental Protection Agency ("EPA") has limited the disposal options for certain "hazardous wastes." Furthermore, it is possible that certain wastes currently exempt from treatment as "hazardous wastes" may in the future be designated as "hazardous wastes" under RCRA or other applicable statues, and therefore be subject to more rigorous and costly disposal requirements. Superfund. The Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA") , also known as the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release of a "hazardous substance" into the environment. These persons include the owner and operator of a site and any party that disposed or arranged for the disposal of the hazardous substance found at a site. CERCLA also authorizes the EPA, and in some cases, third parties, to take actions in response to threats to the public health or the environment and to seek to recover from the responsible parties the costs of such action. In the course of the Company's operations, the Company has generated and will generate wastes that may fall within CERCLA's definition of "hazardous substances." The Company may also be an owner of sites on which "hazardous substances" have been released. Therefore, the Company may be responsible under CERCLA for all or part of the costs to clean up sites at which such wastes have been disposed. Oil Pollution Act. The Oil Pollution Act of 1990 (the "OPA") and regulations thereunder impose a variety of regulations on "responsible parties" related to the prevention of oil spills and liability for damages resulting from such spills in "waters of the United States." The term "waters of the United States" has been broadly defined to include inland waste bodies, including wetlands and intermittent streams. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. Air Emissions. The operations of the Company are subject to local, state and federal laws and regulations for the control of emissions from sources of air pollution. Administrative enforcement actions for failure to comply strictly with air regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could require the Company to cease construction or operation of certain air emission sources. The Company believes that it is in substantial compliance with the emission standards under local, state and federal laws and regulations. EMPLOYEES The Company had 342 active employees as of December 31, 1997. The Company believes that its relations with its employees are satisfactory. The Company has not entered into any collective bargaining agreements with its employees. OTHER The Company's profitability depends on certain factors that are beyond its control, such as natural gas and crude oil prices. The nature of the oil and gas business involves a variety of risks, including the risk of experiencing certain 15 17 operating hazards such as fires, explosions, blowouts, cratering, oil spills and encountering formations with abnormal pressures, the occurrence of any of which could result in substantial losses to the Company. The operation of the Company's natural gas gathering and pipeline systems also involves certain risks, including the risk of explosions and environmental hazards caused by pipeline leaks and ruptures. The proximity of pipelines to populated areas, including residential areas, commercial business centers and industrial sites, could exacerbate such risks. At December 31, 1997, the Company owned or operated approximately 2,800 miles of natural gas gathering and pipeline systems. As part of its normal maintenance program, the Company has identified certain segments of its pipelines which it believes require repair, replacement or additional maintenance. In accordance with customary industry practices, the Company maintains insurance against some, but not all, of such risks. ITEM 2. PROPERTIES See Item 1. Business. ITEM 3. LEGAL PROCEEDINGS The Company and its subsidiaries are defendants or parties in numerous lawsuits or other governmental proceedings arising in the ordinary course of business. The Company is also involved in other gas contract issues. In the opinion of the Company, final judgments or settlements, if any, which may be awarded in connection with any one or more of these suits and claims could be significant to the results of operations and cash flows of any period but would not have a material adverse effect on the Company's financial position. On February 10, 1997, Washington Energy Company and Puget Sound Power & Light Company merged to form Puget Sound Energy, Inc. ("Puget"). As a result of the merger, Puget is the holder of 2,133,000 shares of Common Stock and 1,134,000 shares of the Company's 6% Convertible Redeemable Preferred Stock (convertible into 1,972,174 shares of Common Stock), all of which were previously held by Washington Energy Company. Mr. William P. Vititoe, a member of the Company's Board of Directors, is a consultant to Puget and was formerly an officer and director of Washington Energy Company. The Company sells approximately 20,000 Mmbtu of natural gas per day in the Western Region to a cogeneration plant located in Bellingham, Washington and owned by Encogen Northwest, L.P. ("Encogen") under a gas sales contract containing a fixed price that escalates annually, a firm delivery arrangement and a term continuing through June 30, 2008. Encogen sells all the electrical power generated in the plant to Puget under an Agreement for Firm Power Purchase ("Power Agreement"). The Company is aware that a dispute has arisen between Puget and Encogen over the appropriate interpretation of certain provisions of the Power Agreement, which dispute is currently being litigated. Puget has requested the court, among other matters, to declare that Encogen is in material breach of the Power Agreement. A finding by the court that Encogen is in material breach of the Power Agreement could lead to termination of the Power Agreement. Any restructuring or termination of the Power Agreement may have a negative impact on the Company's gas sales arrangement with Encogen. Encogen has requested that the Company consider restructuring its gas sales arrangement with Encogen. To date the Company has been unwilling to restructure its gas sales agreement without being fully compensated for the agreement's value. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS There were no matters submitted to a vote of security holders during the period from October 1, 1997 to December 31, 1997. EXECUTIVE OFFICERS OF THE REGISTRANT The following table shows certain information about the executive officers of the Company as of March 1, 1998, as such term is defined in Rule 3b-7 promulgated under the Securities Exchange Act of 1934, and certain other officers of the Company. 16 18
Name Age Position Officer Since ------------------------------------------------------------------------------------------------------ Charles P. Siess, Jr. 71 Chairman of the Board and 1995 Chief Executive Officer Ray R. Seegmiller 62 President, Chief Operating Officer and Director 1995 James M. Trimble 49 Senior Vice President, Exploration and 1987 Production Jim L. Batt 62 Vice President, Land 1988 Jeff W. Hutton 42 Vice President, Marketing 1995 Gerald F. Reiger 46 Vice President and Regional Manager 1995 H. Baird Whitehead 47 Vice President and Regional Manager 1987 Paul F. Boling 44 Controller 1996 Lisa A. Machesney 42 Corporate Secretary and Managing Counsel 1995 Scott C. Schroeder 35 Treasurer 1997
All officers are elected annually by the Company's Board of Directors. With the exception of the following, all executive officers of the Company have been employed by the Company for at least the last five years. Charles P. Siess, Jr. has been Chairman of the Board and Chief Executive Officer of the Company since May 1995. From February 1993 until January 1994, Mr. Siess served as Acting General Manager of Bridas S.A.P.I.C. (oil exploration in Argentina). Prior thereto, Mr. Siess served as Chairman of the Board, Chief Executive Officer and President of the Company from December 1989 to December 1992. Gerald F. Reiger has been Vice President, Regional Manager of the Company since February 1995. From May 1994 until February 1995, Mr. Reiger served as Regional Manager of the Company. Prior thereto, Mr. Reiger was associated with Washington Energy Resources Company, a subsidiary of Washington Energy Company, from 1992 to 1994. Prior thereto, Mr. Reiger served as U.S. Operations Manager of DeKalb Energy Company. Ray R. Seegmiller joined the Company as Vice President, Chief Financial Officer and Treasurer in August 1995. Mr. Seegmiller served in this position until March 1997 when he was promoted to Executive Vice President, Chief Operating Officer. In September 1997, Mr. Seegmiller was promoted to his current position of President, Chief Operating Officer and Director. Mr. Seegmiller has been designated to replace Charles Siess as Chief Executive Officer upon the expected retirement of Mr. Siess in 1998. From May 1988 until 1993, Mr. Seegmiller served as President and Chief Executive of Terry Petroleum Company. Prior thereto, Mr. Seegmiller held various officer positions with Marathon Manufacturing Company. Scott C. Schroeder has been Treasurer since May 1997. From October 1995 to May 1997, Mr. Schroeder served as Assistant Treasurer. Prior to joining the Company, Mr. Schroeder held various managerial positions with Pride Petroleum Services (now known as Pride International). Prior thereto, Mr. Schroeder server as Manager, Treasury Operations and Planning of DeKalb Energy Company. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The Common Stock is listed and principally traded on the New York Stock Exchange under the ticker symbol "COG". The following table sets forth for the periods indicated the high and low sales prices per share of the Common Stock, as reported in the consolidated transaction reporting system, and the cash dividends paid per share of the Common Stock: 17 19
Cash High Low Dividends - ------------------------------------------------------------------------ 1997 FIRST QUARTER $ 19.75 $ 15.88 $ 0.04 SECOND QUARTER 18.88 15.50 0.04 THIRD QUARTER 23.69 17.38 0.04 FOURTH QUARTER 25.06 16.50 0.04 1996 First Quarter $ 16.88 $ 13.13 $ 0.04 Second Quarter 17.63 13.75 0.04 Third Quarter 18.38 13.75 0.04 Fourth Quarter 18.38 14.38 0.04
As of January 31, 1998, there were 1,397 registered holders of the Common Stock. Shareholders include individuals, brokers, nominees, custodians, trustees and institutions such as banks, insurance companies and pension funds. Many of these hold large blocks of stock on behalf of other individuals or firms. ITEM 6. SELECTED HISTORICAL FINANCIAL DATA The following table sets forth a summary of selected consolidated financial data for the Company for the periods indicated. This information should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations and the Consolidated Financial Statements and related Notes thereto.
Year Ended December 31, (In thousands, except per share amounts) 1997 1996 1995 1994 1993 - ----------------------------------------------------------------------------------------------------------- INCOME STATEMENT DATA: Net Operating Revenues $ 185,127 $ 163,061 $ 121,083 $ 140,295 $ 115,816 Income (Loss) from Operations 63,852 48,787 (116,758) 15,013 20,007 Net Income (Loss) Applicable to Common Stockholders 23,231 15,258 (92,171) (5,444) 2,088 BASIC EARNINGS (LOSS) PER SHARE APPLICABLE TO COMMON STOCKHOLDERS(1) $ 1.00 $ 0.67 $ (4.05) $ (0.25) $ 0.10 DIVIDENDS PER COMMON SHARE $ 0.16 $ 0.16 $ 0.16 $ 0.16 $ 0.16 BALANCE SHEET DATA: Properties and Equipment, Net $ 469,399 $ 480,511 $ 474,371 $ 634,934 $ 400,270 Total Assets 541,805 561,341 528,155 688,352 445,001 Long-Term Debt 183,000 248,000 249,000 268,363 169,000 Stockholders' Equity 184,062 160,704 147,856 243,082 153,529 - -----------------------------------------------------------------------------------------------------------
(1) See "Earnings (Loss) Per Common Share" under Note 20 of the Notes to the Consolidated Financial Statements. 18 20 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following review of operations should be read in conjunction with the Consolidated Financial Statements and the Notes thereto included elsewhere. OVERVIEW The initial upswing in gas prices early in the year, coupled with a 8.5% increase in natural gas production, played an important part in the Company's performance in 1997 with record earnings and operating cash flows. Operating results for 1997 included the benefit of the following: o The average produced natural gas price was $2.53 per Mcf, up 8% compared to 1996, while equivalent production was up 5.4 Bcfe, or 8.5%, compared to 1996. o Under its continued asset rationalization program, involving the divestiture of non-strategic properties, and synergistic growth through new acquisitions, the Company completed a like-kind exchange transaction in October 1997 which matched properties purchased, including 63 wells and 74 potential drilling locations, in the Green River Basin of Wyoming with a portion of the properties divested in the Meadville district of the Appalachian Region, including 912 wells and related assets. This transaction generated net proceeds of $47.7 million. o Net interest costs were down $1.1 million, or 6%, excluding the benefit of the non-recurring $1.7 million of interest income received in 1996 that related to an income tax refund for tax periods prior to 1990. This reduction in interest cost was a result of debt reductions made possible by strong operating cash flow in 1997. o Depreciation, depletion and amortization ("DD&A") expenses were down $1.9 million or $0.09 per Mcfe of production. This improvement was primarily the result of the reduction in high cost depreciable assets due to the disposition of the Meadville properties in September 1997. Operating cash flows reached a record level of $95.0 million, increasing $19.6 million, or 26%, from 1996. Cash flows from operations, along with the $47.7 million of net proceeds from the Meadville/Green River property transaction noted above, predominantly funded (1) $73.5 million of capital and exploration expenditures, (excluding the Green River property acquisition) $12.8 million higher than 1996, (2) $49 million of net debt reductions and (3) $9.4 million of preferred and common stock dividend payments. The Company drilled 151.4 net wells with a net success rate of 88% compared to 154.2 net wells and a net 80% success rate in 1996. Along with the higher success rate in 1997, the Company replaced 179% of production through drilling additions and revisions, versus a 119% production replacement in 1996. In 1998 the Company plans to drill 270 gross wells (173.2 net) and spend $111.0 million in capital and exploration expenditures, 17% higher than 1997 expenditures. Natural gas production equivalent was 67.7 Bcf, an increase of 8.5% over 1996. The 1997 production growth resulted from the Company's expanded drilling programs in 1996 and 1997. Additionally, the underperforming properties sold in the Meadville district, effective September 1, 1997, which would have produced an estimated 1.7 Bcfe in the remaining four months of 1997, were more than offset by the acquired Green River properties which added 1.9 Bcfe to 1997 production. 19 21 The Company's strategic pursuits are sensitive to energy commodity prices, particularly the price of natural gas. Gas prices rose to near record levels in November and December 1996. Although prices rose still further in January 1997, the gas market demonstrated significant price volatility in the spring months. Prices in most regions rose sharply in October and November 1997, but due to the unseasonably warm winter, softened in December and January 1998 to levels significantly below the prices realized in the corresponding months of the prior year. The Company remains focused on its strategies to grow through the drill bit, through synergistic acquisitions and through greater emphasis on marketing. The Company believes that these strategies are appropriate in the current industry environment and establish a firm base which will enable the Company to create shareholder value over the long term. The success of these strategies is measured by the achievement of three goals. The first of these goals is to increase cash flow from both increased production and reduced costs. The Company has made significant progress in this area. During 1997, production increased 8.5% while direct operating cost per Mcfe declined $0.02, contributing to the 26% increase in operational cash flow. The second goal is to maintain reserves per share while increasing production to protect long-term shareholder value. Reserve additions from the 1997 drilling program replaced 168% of 1997 production. In total, reserve levels decreased slightly due to actions taken as part of the asset rationalization program. The Company plans to drill 270 gross wells in 1998 and increase exploratory drilling, lease acquisition and geophysical expenditures. Finally, the Company strives to reduce debt as a percentage of total capitalization without diluting shareholder value. This ratio was 60.7% at the end of 1996 and has improved to 51.9% in 1997 due mainly to a $49 million reduction in total borrowings, made possible from the net proceeds generated from the sale of the Meadville properties. In October 1997, the Company exercised the option to convert all of the $3.125 cumulative preferred stock into approximately 1,649,000 shares of Common Stock. By eliminating the dividends on the $3.125 cumulative preferred shares, an additional $2.2 million of annual earnings will be made available to common shareholders in future years. The preceding paragraphs, discussing the Company's strategic pursuits and goals, contain forward-looking information. See FORWARD-LOOKING INFORMATION on page 25. FINANCIAL CONDITION CAPITAL RESOURCES AND LIQUIDITY The Company's capital resources consist primarily of cash flows from its oil and gas properties and asset-based borrowing supported by its oil and gas reserves. The Company's level of earnings and cash flows depend on many factors, including the price of oil and natural gas and its ability to control and reduce costs. Demand for oil and gas has historically been subject to seasonal influences characterized by peak demand and higher prices in the winter heating season. Natural gas prices were up in 1997 over 1996, resulting in higher cash flows. The primary sources of cash for the Company during 1997 were from funds generated from operations and net cash proceeds from the sale of the Meadville properties and acquisition of the Green River properties. Primary uses of cash were funds used in operations, exploration and development expenditures, acquisitions, dividends on preferred and common stock and repayment of debt. The Company had a net cash inflow of $0.4 million in 1997. Net cash inflow from operating and financing activities totaled $38.9 million, funding the capital and exploration expenditures of $38.4 million, net of the $48.9 million in net proceeds from the sale of assets.
(In millions) 1997 1996 1995 - -------------------------------------------------------------------------------- Cash Flows Provided by Operating Activities $ 95.0 $ 75.5 $ 41.5 ------- ------- -------
20 22 Cash flows provided by operating activities in 1997 were substantially higher, increasing $19.5 million over 1996, due primarily to higher natural gas prices and production, and a significant reduction in trade receivables. Cash flows provided by operating activities in 1996 were higher by $34 million compared with 1995 due predominantly to higher natural gas prices.
(In millions) 1997 1996 1995 - ----------------------------------------------------------------------------- Cash Flows Used by Investing Activities $(38.4) $ (67.6) $ (14.0) ------ ------- -------
Cash flows used by investing activities in 1997 were $29.2 million lower than in 1996 due to net proceeds of $47.7 million received from the Meadville/Green River property transaction, partially offset by the expenses of the stronger 1997 drilling program. Cash flows used by investing activities in 1996 were $53.5 million higher than in 1995 due primarily to $40.6 million of increased capital and exploration expenditures over 1995. The Company's 1995 drilling program was scaled down, drilling only 55.4 net wells, compared to an average of 135 net wells per year over the previous five years. The 1996 capital expenditures were offset in part by proceeds of $5.7 million from the sale of assets.
(In millions) 1997 1996 1995 - ---------------------------------------------------------------------------- Cash Flows Used by Financing Activities $ (56.2) $ (9.6) $ (28.2) -------- ------- -------
Cash flows used by financing activities from 1997 consist primarily of the $49.0 million net reduction in borrowings on the revolving credit facility as well as dividend payments. The 1996 activity was mostly attributable to dividend payments, but also included a $1.0 reduction in debt under the credit facility. Cash flows used by financing activities from 1995 were primarily net payments on the Company's revolving credit facility, reducing the debt under this facility by $19.0 million. The Company's available credit line under the revolving credit facility was $235 million from June 1995 until November 1997. In November 1997, the Company issued $100 million in 7.19% Notes (See Note 5 of the Notes to the Consolidated Financial Statements for further discussion) and reduced the available credit line to $135 million. The available credit line is subject to adjustment on the basis of the projected present value of estimated future net cash flows from proved oil and gas reserves (as determined by an independent petroleum engineer's report incorporating certain assumptions provided by the lender) and other assets. The Company's outstanding indebtedness under the revolving credit facility was $19 million at December 31, 1997. The Company's 1998 interest expense is projected to be approximately $17 million. A principal payment of $16 million on the 10.18% private placement of senior notes is due in the second quarter of 1998. The Company has begun making necessary changes to its computer software in preparation for the year 2000. These projects are on schedule and the Company believes that the related costs will not be material to its results of operations or financial condition. Capitalization information on the Company is as follows:
(In millions) 1997 1996 1995 - ---------------------------------------------------------- Long-Term Debt $183.0 $248.0 $249.0 Current Portion of Long-Term Debt 16.0 -- -- ------ ------ ------ Total Debt 199.0 248.0 249.0 Stockholders' Equity Common Stock 127.4 69.4 56.6 Preferred Stock 56.7 91.3 91.3 ------ ------ ------ Total Equity 184.1 160.7 147.9 ------ ------ ------ Total Capitalization $383.1 $408.7 $396.9 ====== ====== ====== Debt to Capitalization 51.9% 60.7% 62.7% ------ ------ ------
21 23 The Company's capitalization reflects the non-cash impact to equity of the $69.2 million SFAS 121 impairment of long-lived assets recorded in 1995. (See Note 15 of the Notes to the Consolidated Financial Statements for further discussion.) CAPITAL AND EXPLORATION EXPENDITURES The following table presents major components of capital and exploration expenditures for the three years ended December 31, 1997.
(In millions) 1997 1996 1995 - -------------------------------------------------------------------------------- Capital Expenditures: Drilling and Facilities $ 68.2 $ 42.7 $ 19.3 Leasehold Acquisitions 4.3 4.3 2.0 Pipeline and Gathering 6.1 6.3 2.2 Other 2.0 0.7 1.2 ------- ------- ------- 80.6 54.0 24.7 ------- ------- ------- Proved Property Acquisitions(3) 45.6 6.6 -- WERCO Acquisition -- (5.3)(1) (8.4)(2) ------- ------- ------- 45.6 1.3 (8.4) ------- ------- ------- Exploration Expenses 13.9 12.6 8.0 ------- ------- ------- Total $ 140.1 $ 67.9 $ 24.3 ======= ======= ======= - --------------------------------------------------------------------------------
(1) An adjustment to the $40.2 million non-cash component relating to deferred taxes for the difference between the tax and book bases of the acquired properties, as required by SFAS 109, "Accounting for Income Taxes", of the WERCO acquisition as a result of the $8.4 million valuation adjustment received in 1995. (2) A net cash payment received in connection with a valuation adjustment on the 1994 WERCO acquisition. (3) Includes $45.2 million in assets acquired from Equitable Resources Energy Company in a like-kind exchange transaction with a portion of the assets sold in the Meadville properties sale. The substantially reduced level of capital and exploration expenditures in 1995 resulted from the downsized capital expenditures program resulting from depressed gas prices and the absence of a major acquisition. The Company generally funds its capital and exploration activities, excluding major oil and gas property acquisitions, with cash generated from operations and budgets such capital expenditures based upon projected cash flows, exclusive of acquisitions. Planned expenditures for 1998 have been increased 17% compared with 1997, excluding proved property acquisitions. Depending on the level of future natural gas prices, the Company intends to review and adjust the capital and exploration expenditures planned for 1998 as industry conditions dictate. Presently, the Company projects $111 million in capital and exploration expenditures for 1998 including $88.5 million for the drilling and exploration program. The Company plans to drill 270 wells (173.2 net), compared with 225 wells (151.4 net) drilled in 1997. In addition to the drilling and exploration program, other 1998 capital expenditures are planned primarily for producing property and lease acquisitions and for gathering and pipeline infrastructure maintenance and construction. During 1997, dividends were paid on the Company's common stock totaling $3.7 million, on the $3.125 convertible preferred stock totaling $1.7 million, and on the 6% convertible redeemable preferred stock totaling $3.4 million. The Company has paid quarterly common stock dividends of $0.04 per share since becoming publicly traded 22 24 in 1990. The amount of future dividends is determined by the Board of Directors and is dependent upon a number of factors, including future earnings, financial condition, and capital requirements. OTHER ISSUES AND CONTINGENCIES Encogen Gas Contract. See Item 3. Legal Proceedings on page 16 for a discussion of this matter. Corporate Income Tax. The Company generates tax credits for the production of certain qualified fuels, including natural gas produced from tight formations and Devonian Shale. The credit for natural gas from a tight formation ("tight gas sands") amounts to $0.52 per Mmbtu for natural gas sold prior to 2003 from qualified wells drilled in 1991 and 1992. A number of wells drilled in the Appalachian Region during 1991 and 1992 qualified for the tight gas sands tax credit. The credit for natural gas produced from Devonian Shale is approximately $1.05 per Mmbtu in 1997. In 1995 and 1996, the Company completed three transactions to monetize the value of these tax credits, resulting in revenues of $3.6 million in 1997 and approximately $16.4 million over the remaining five years (See Note 18 of the Notes to the Consolidated Financial Statements for further discussion). The Company has benefited in the past and may benefit in the future from the alternative minimum tax ("AMT") relief granted under the Comprehensive National Energy Policy Act of 1992. The Act repealed provisions of the AMT requiring a taxpayer's alternative minimum taxable income to be increased on account of certain intangible drilling costs ("IDC") and percentage depletion deductions. The repeal of these provisions generally applies to taxable years beginning after 1992. The repeal of the excess IDC preference cannot reduce a taxpayer's alternative minimum taxable income by more than 40% of the amount of such income determined without regard to the repeal of such preference. Regulations. The Company's operations are subject to various types of regulation by federal, state and local authorities. See "Regulation of Oil and Natural Gas Production and Transportation" and "Environmental Regulations" in the Other Business Matters section of Item 1. Business for a discussion of these regulations. Restrictive Covenants. The Company's ability to incur debt, to pay dividends on its common and preferred stock, and to make certain types of investments is dependent upon certain restrictive covenants in the Company's various debt instruments. Among other requirements, the Company's 10.18% and 7.19% Notes specify a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0. At December 31, 1997 the calculated ratio for 1997 was 5.3 to 1. CONCLUSION The Company's financial results depend upon many factors, particularly the price of natural gas and its ability to market its production on economically attractive terms. The Company's average 1997 produced natural gas sales price increased 8% compared to 1996, while production volumes increased 8.5%. As a result, the Company experienced its highest level of earnings and operating cash flow since becoming a public company in 1990. While prices in most regions of the U.S. moved up sharply in November and December 1996 and January 1997, price volatility in the gas market has remained prevalent in the last few years, as demonstrated most recently in December 1997 and January 1998, with natural gas prices dropping to levels substantially below the prices of the corresponding months of the prior year. Given this continued price volatility, management cannot predict with certainty what pricing levels will be for the rest of 1998 and beyond. Because future cash flows and earnings are subject to such variables, there can be no assurance that the Company's operations will provide cash sufficient to fully fund its capital requirements if prices should return to the depressed levels of 1995. While the Company's 1998 plans include an increase in capital spending, the Company will periodically assess industry conditions and will adjust its 1998 spending plan to ensure the adequate funding of its capital requirements, including, among other things, reductions in capital expenditures or common stock dividends. The Company believes its capital resources, supplemented, if necessary, with external financing, are adequate to meet its capital requirements. 23 25 The preceding paragraphs contain forward-looking information. See Forward-Looking Information below. * * * FORWARD-LOOKING INFORMATION The statements regarding future financial performance and results and market prices and the other statements which are not historical facts contained in this report are forward-looking statements. The words "expect," "project," "estimate," "believe," "anticipate," "intend," "budget," "predict" and similar expressions are also intended to identify forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including regional basis differentials) of natural gas and oil, results for future drilling and marketing activity, future production and costs and other factors detailed herein and in the Company's other Securities and Exchange Commission filings. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. 24 26 RESULTS OF OPERATIONS For the purpose of reviewing the Company's results of operations, "Net Income (Loss)" is defined as net income (loss) applicable to common stockholders. The Company's Western Region includes operations located in the Anadarko area, the onshore Gulf Coast, and in the Rocky Mountains. SELECTED FINANCIAL AND OPERATING DATA
(In millions except where specified) 1997 1996 1995 - ------------------------------------------------------------------------------- Net Operating Revenues $ 185.1 $ 163.1 $ 121.1 Operating Expenses 121.3 116.0 237.2 Interest Expense 18.0 17.4 24.9 Net Income (Loss) 23.2 15.3 (92.2) Earnings (Loss) Per Share - Basic $ 1.00 $ 0.67 $ (4.05) Natural Gas Production (Bcf) Appalachia 25.3 26.8 27.5 West 38.6 32.0 30.2 -------- ------- -------- Total Company 63.9 58.8 57.7 ======== ======= ======== Produced Natural Gas Sales Price ($/Mcf) Appalachia $ 3.00 $ 2.72 $ 2.22 West $ 2.22 $ 2.02 $ 1.33 Total Company $ 2.53 $ 2.34 $ 1.75 Crude/Condensate Volume (Mbbl) 574 520 618 Price ($/Bbl) $ 20.13 $ 21.14 $ 17.95
The table below presents the after-tax effects of certain selected items ("selected items") on the Company's results of operations for the three years ended December 31, 1997.
(In millions) 1997 1996 1995 - -------------------------------------------------------------------------------- Net Income (Loss) Before Selected Items $ 23.2 $ 12.5 $(17.3) Income tax refund 2.8 SFAS 121 impairment (69.2) Cost reduction program (4.7) Columbia settlement 2.6 Decoupled gas price hedges (2.0) Terminated interest rate swaps (1.6) -------- ------ ------ Net Income (Loss) $ 23.2 $ 15.3 $(92.2) ======== ====== ======
1997 AND 1996 COMPARED Net Income and Revenues. The Company reported net income in 1997 of $23.2 million, or $1.00 per share, up $10.7 million, or $0.45 per share, compared to 1996, excluding the impact of the selected items. The $2.8 million special item, or $0.12 per share, in 1996 related to a $1.8 million tax refund for percentage depletion claimed for certain periods prior to 1990 and $1.7 million of interest income ($1.0 million after tax) earned on the refund amount. Excluding these pre-tax effects of the selected items, 1997 operating income and net operating revenues increased $15.1 million and $22.1 million, respectively. Natural gas sales comprised 87%, or $161.7 million, of net operating revenue in 1997. The increase in net operating revenue was a result of both an 8% increase in the produced natural gas sales price and an 8.5% increase in equivalent production. Operating income and net income were similarly impacted by the 25 27 increases in natural gas prices and equivalent production along with lower depreciation, depletion and amortization expense and interest expense. Effective September 1, 1997, the Company sold proved reserves and acreage located primarily in Northwest Pennsylvania (the "Meadville properties") for $92.9 million to Lomak Petroleum Incorporated. The properties sold included 912 wells, producing approximately 15 Mmcfe net per day primarily from the Medina formation. A portion of these assets were replaced, in a like-kind exchange transaction, with oil and gas producing properties located in the Green River Basin of Wyoming (the "Green River properties") purchased for $45.2 million in a transaction with Equitable Resources Energy Company which closed on October 3, 1997. The purchased properties added an estimated 72 Bcfe of reserves, interests in 63 wells with estimated daily net production of 10 Mmcfe and 74 potential drilling locations to the Western Region. This acquisition increased the Company's presence in the Rocky Mountains area by 46%. Natural gas production volumes were down 1.5 Bcf, or 6%, to 25.3 Bcf in the Appalachian Region as a result of the September sale of the Meadville properties which were estimated to have produced 1.7 Bcfe in 1997 after the sale. Natural gas production volumes were up 6.6 Bcf, or 21%, to 38.6 Bcf in the Western Region due largely to new production from wells drilled and put on line in the Rocky Mountains and Gulf Coast areas during the last half of 1996 and in 1997 and from the acquired Green River properties which produced 1.9 Bcfe. In the Appalachian Region, the average natural gas production sales price increased $0.28 per Mcf, or 10%, to $3.00, increasing net operating revenues by approximately $7.1 million on 25.3 Bcf of production. The average Western Region natural gas production sales price increased $0.20 per Mcf, or 10%, to $2.22, increasing net operating revenues by approximately $7.7 million on 38.6 Bcf of production. The overall weighted average natural gas production sales price increased $0.19 per Mcf, or 8%, to $2.53. Crude oil and condensate sales increased by 54 Mbbl, or 10%, primarily due to new production brought on by the higher rate of drilling activity in 1996 and 1997 compared to 1995 levels. Brokered natural gas margin was down $1.5 million to $4.1 million due primarily to a $0.03 per Mcf decrease in the net margin to $0.12 per Mcf and in part to a brokered volume decrease of 8% from 1996. Operating Expense. The total operating expenses increased $5.3 million, or 5%, to $77.9 million. The significant changes are explained as follows: o Direct operation expense increased $1.0 million, or 4%, due to office consolidation costs in the Western Region and the 8.5% increase in equivalent production. Direct operating costs per Mcfe declined, however, from $0.45 to $0.43 due in part to the sale of the higher cost Meadville properties and the addition of new lower cost production. o Exploration expense increased $1.3 million primarily due to a $0.9 million rise in geological and geophysical expenses and a $0.3 million increase in contract labor services related to the increased drilling and exploration program in 1997. o Depreciation, depletion, amortization and impairment expense decreased $1.9 million, or 4%. due to the benefit of the Meadville/Green River like-kind exchange transaction in the third quarter and due to the decline in the Western Region DD &A rate related to the addition of new lower cost production to existing fields. o Taxes other than income increased $2.0 million, or 16%, due to the increase in natural gas production revenues. o General and administrative expense increased $2.9 million, or 17%, due primarily to higher incentive and stock compensation expenses related to the Company's marked improvement in earnings performance. 26 28 Interest expense, excluding the 1996 selected item, declined $1.1 million, or 6%, due to a reduction in the Company's long-term debt level. Income tax expense, excluding the selected item, was up $5.2 million due to the comparable increase in earnings before income tax. The Company's effective tax rate declined slightly due to a 0.2% reduction in the effective state tax rate combined with a $0.2 million refund received on the prior year percentage depletion claim. 1996 AND 1995 COMPARED Net Income (Loss) and Revenues. The Company reported net income in 1996 of $12.5 million, or $0.55 per share, up $29.8 million, or $1.31 per share, compared with 1995, excluding the impact of the selected items. The $2.8 million special item, or $0.12 per share, in 1996 related to a $1.8 million tax refund for percentage depletion claimed for certain periods prior to 1990 and $1.7 million of interest income ($1.0 million after tax) earned on the refund amount. The $74.9 million from special items, or $3.29 per share, in 1995 consisted of a $113.8 million charge ($69.2 million after tax) related to the adoption of SFAS 121, $7.7 million ($4.7 million after tax) for the cost reduction program and other severance costs, $3.2 million ($2.0 million after tax) loss related to uncovered gas price hedges and a $2.6 million charge ($1.6 million after tax) to interest expense to close interest rate swap contracts, offset in part by other revenue of $4.3 million ($2.6 million after tax) in connection with the sale of a Columbia bankruptcy claim. Excluding the pre-tax effects of the selected items, operating income and net operating revenues increased $39 million and $43.1 million, respectively. Natural gas sales comprised 84%, or $137.5 million, of net operating revenue in 1996. The increase in net operating revenues was driven primarily by a 34% increase in the produced natural gas sales price. Net income (loss) and operating income (loss), excluding selected items, were similarly impacted by the increase in the produced natural gas sales price, as well as lower depreciation, depletion & amortization and interest expenses. Natural gas production volumes were down 0.7 Bcf, or 3%, to 26.8 Bcf in the Appalachian Region, a result from the low level of drilling activity in 1995 and the sale of non-strategic properties. Natural gas production volumes were up 1.8 Bcf, or 6%, to 32.0 Bcf in the Western Region due primarily to Rocky Mountains and Gulf Coast area wells drilled and put on line in the second and third quarters of 1996. The average Appalachian natural gas production sales price increased $0.50 per Mcf, or 23%, to $2.72, increasing net operating revenues by approximately $13.6 million on 26.8 Bcf of production. In the Western Region, the average natural gas production sales price increased $0.69 per Mcf, or 52%, to $2.02, increasing net operating revenues by approximately $22.3 million on 32.0 Bcf of production. The overall weighted average natural gas production sales price increased $0.59 per Mcf, or 34%, to $2.34. Crude oil and condensate sales decreased 98 Mbbl, or 16%, due primarily to the low drilling activity in 1995 and the sale of various non-strategic oil properties in 1995. Brokered natural gas margin was up $3.1 million to $5.6 million due primarily to a $0.08 per Mcf increase in the net margin to $0.15 per Mcf, a result of the higher prices environment in 1996. Brokered volume was comparable to 1995. Operating Expenses. Total operating expenses, excluding the selected items, were virtually unchanged, increasing $0.4 million. The significant changes are explained as follows: o Exploration expense increased $4.5 million due to the $4.1 million increase in dry hole expense and the $0.4 million increase in geological and geophysical expenses, a direct result of the increased capital expenditure program in 1996. o Depreciation, depletion, amortization and impairment expense decreased $6.9 million, or 13%, due to a $0.11 per Mcfe decline in the DD&A rate caused by the 1995 impairment of long-lived assets which reduced depreciable basis by $113.8 million. 27 29 o Taxes other than income increased $1.6 million, or 14%, due primarily to the increase in natural gas production revenues. o The cost reduction program in 1995 consisted primarily of a 23% staff reduction, achieved through early retirement and involuntary termination programs. The pre-tax charges, a selected item, related to this action totaled $6.8 million, comprised of $3.8 million in salary and other severance related expense and a $3.0 million non-cash charge for curtailments to the pension and postretirement benefits plans. Interest expense, excluding selected items, declined $3.1 million, or 14%, due primarily to the absence of the interest rate swaps which effectively increased interest expense in 1995. Income tax expense, excluding the selected item, was up $67.4 million due to the comparable increase in earnings before income tax. The Company's effective tax rate was virtually unchanged. 28 30 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Page - --------------------------------------------------------------------------- Report of Independent Accountants 31 Consolidated Statement of Operations 32 Consolidated Balance Sheet 33 Consolidated Statement of Cash Flows 34 Consolidated Statement of Stockholders' Equity 35 Notes to Consolidated Financial Statements 36 Supplemental Oil & Gas Information (Unaudited) 55 Quarterly Financial Information (Unaudited) 59 REPORT OF MANAGEMENT The management of Cabot Oil & Gas Corporation is responsible for the preparation and integrity of all information contained in the annual report. The consolidated financial statements and other financial information are prepared in conformity with generally accepted accounting principles and, accordingly, include certain informed judgments and estimates of management. Management maintains a system of internal accounting and managerial controls and engages internal audit representatives who monitor and test the operation of these controls. Although no system can ensure the elimination of all errors and irregularities, the system is designed to provide reasonable assurance that assets are safeguarded, transactions are executed in accordance with management's authorization and accounting records are reliable for financial statement preparation. An Audit Committee of the Board of Directors, consisting of directors who are not employees of the Company, meets periodically with management, the independent accountants and internal audit representatives to obtain assurances to the integrity of the Company's accounting and financial reporting and to affirm the adequacy of the system of accounting and managerial controls in place. The independent accountants and internal audit representatives have full and free access to the Audit Committee to discuss all appropriate matters. We believe that the Company's policies and system of accounting and managerial controls reasonably assure the integrity of the information in the consolidated financial statements and in the other sections of the annual report. Charles P. Siess, Jr. Ray Seegmiller Chairman of the Board and President and Chief Executive Officer Chief Operating Officer March 6, 1998 29 31 REPORT OF INDEPENDENT ACCOUNTANTS TO THE STOCKHOLDERS AND BOARD OF DIRECTORS OF CABOT OIL & GAS CORPORATION: We have audited the accompanying consolidated balance sheet of Cabot Oil & Gas Corporation as of December 31, 1997 and 1996, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 1997. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Cabot Oil & Gas Corporation as of December 31, 1997 and 1996, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles. As discussed in Notes 14 and 15 to the consolidated financial statements, in 1995 the Company changed its method of applying the unit-of-production method to calculate depreciation and depletion on producing oil and gas properties, and accounting for the impairment of long-lived assets. COOPERS & LYBRAND L.L.P. Houston, Texas March 6, 1998 30 32 CABOT OIL & GAS CORPORATION CONSOLIDATED STATEMENT OF OPERATIONS
Year Ended December 31, (In thousands, except per share amounts) 1997 1996 1995 - --------------------------------------------------------------------------------------- NET OPERATING REVENUES Natural Gas Production $ 161,737 $ 137,482 $ 101,260 Crude Oil and Condensate 11,443 10,992 11,089 Brokered Natural Gas Margin 4,113 5,619 2,509 Other 7,834 8,968 6,225 --------- --------- --------- 185,127 163,061 121,083 OPERATING EXPENSES Direct Operations 29,380 28,361 28,328 Exploration 13,884 12,559 8,031 Depreciation, Depletion and Amortization 40,598 42,689 47,206 Impairment of Long-Lived Assets (Note 15) -- -- 113,795 Impairment of Unproved Properties 2,856 2,701 5,047 General and Administrative 19,744 16,823 16,785 Cost Reduction Program (Note 12) -- -- 6,820 Taxes Other Than Income 14,874 12,826 11,215 --------- --------- --------- 121,336 115,959 237,227 Gain (Loss) on Sale of Assets 61 1,685 (614) --------- --------- --------- INCOME (LOSS) FROM OPERATIONS 63,852 48,787 (116,758) Interest Expense 17,961 17,409 24,885 --------- --------- --------- Income (Loss) Before Income Tax Expense 45,891 31,378 (141,643) Income Tax Expense (Benefit) 17,557 10,554 (55,025) --------- --------- --------- NET INCOME (LOSS) 28,334 20,824 (86,618) Dividend Requirement on Preferred Stock 5,103 5,566 5,553 --------- --------- --------- Net Income (Loss) Applicable to Common Stockholders $ 23,231 $ 15,258 $ (92,171) ========= ========= ========= Basic Earnings (Loss) Per Share Applicable to Common Stockholders (Note 20) $ 1.00 $ 0.67 $ (4.05) ========= ========= ========= Diluted Earnings (Loss) Per Share Applicable to Common Stockholders (Note 20) $ 0.97 $ 0.66$ (4.05) ========= ========= ========= Average Common Shares Outstanding 23,272 22,807 22,775 ========= ========= ========= - ----------------------------------------------------------------------------------------
The accompanying notes are an integral part of these consolidated financial statements. 31 33 CABOT OIL & GAS CORPORATION CONSOLIDATED BALANCE SHEET
December 31, (In thousands) 1997 1996 - --------------------------------------------------------------------------------------------------------------- ASSETS CURRENT ASSETS Cash and Cash Equivalents $ 1,784 $ 1,367 Accounts Receivable 59,672 67,810 Inventories 6,875 8,797 Other 2,202 1,663 --------- --------- Total Current Assets 70,533 79,637 PROPERTIES AND EQUIPMENT (Successful Efforts Method) 469,399 480,511 OTHER ASSETS 1,873 1,193 --------- --------- $ 541,805 $ 561,341 ========= ========= LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES Current Portion of Long-Term Debt $ 16,000 -- Accounts Payable 52,348 $ 56,338 Accrued Liabilities 17,524 16,279 --------- --------- Total Current Liabilities 85,872 72,617 LONG-TERM DEBT 183,000 248,000 DEFERRED INCOME TAXES 80,108 69,427 OTHER LIABILITIES 8,763 10,593 COMMITMENTS AND CONTINGENCIES (Note 8) STOCKHOLDERS' EQUITY Preferred Stock: Authorized -- 5,000,000 Shares of $0.10 Par Value Issued and Outstanding -- $3.125 Cumulative Convertible Preferred; $50 Stated Value; 0 Shares in 1997 and 692,439 Shares 1996 -- 6% Convertible Redeemable Preferred; $50 Stated Value; 1,134,000 Shares in 1997 and 1996 113 183 Common Stock: Authorized -- 40,000,000 Shares of $0.10 Par Value Issued and Outstanding -- 24,667,262 Shares and 22,847,345 Shares at December 31, 1997 and 1996, respectively 2,467 2,284 Class B Common Stock: Authorized -- 800,000 Shares of $0.10 Par Value No Shares Issued -- -- Additional Paid-in Capital 247,033 243,283 Accumulated Deficit (65,551) (85,046) --------- --------- Total Stockholders' Equity 184,062 160,704 --------- --------- $ 541,805 $ 561,341 ========= ========= - ---------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these consolidated financial statements. 32 34 CABOT OIL & GAS CORPORATION CONSOLIDATED STATEMENT OF CASH FLOWS
Year Ended December 31, (In thousands) 1997 1996 1995 - ---------------------------------------------------------------------------------------------- CASH FLOWS FROM OPERATING ACTIVITIES Net Income (Loss) $ 28,334 $20,824 $ (86,618) Adjustments to Reconcile Net Income (Loss) to Cash Provided by Operations: Depletion, Depreciation, and Amortization 40,598 42,689 47,206 Impairment of Long-Lived Assets -- -- 113,795 Impairment of Unproved Properties 2,856 2,701 5,047 Deferred Income Tax Expense (Benefit) 10,681 12,017 (55,055) Loss (Gain) on Sale of Assets (61) (1,685) 614 Exploration Expense 13,884 12,559 8,031 Other, Net 1,419 176 3,178 Changes in Assets and Liabilities: Accounts Receivable 8,137 (25,796) (3,848) Inventories 1,922 (3,201) 2,788 Other Current Assets (539) 46 (13) Other Assets (680) 243 (37) Accounts Payable and Accrued Liabilities (10,541) 11,199 5,838 Other Liabilities (970) 3,713 565 ---------- ------- ------- Net Cash Provided by Operations 95,040 75,485 41,491 ---------- ------- ------- CASH FLOWS FROM INVESTING ACTIVITIES Capital Expenditures (73,476) (60,719) (24,672) Cost of Major Acquisition -- -- 8,402 Proceeds from Sale of Assets 48,916 5,725 10,291 Exploration Expense (13,884) (12,559) (8,031) ---------- ------- ------- Net Cash Used by Investing (38,444) (67,553) (14,010) ---------- ------- ------- CASH FLOWS FROM FINANCING ACTIVITIES Increase in Debt 11,000 6,000 16,000 Decrease in Debt (60,000) (7,000) (35,363) Exercise of Stock Options 2,197 613 348 Preferred Dividends Paid (5,644) (5,566) (5,566) Common Dividends Paid and Other, Net (3,732) (3,641) (3,644) ---------- ------- ------- Net Cash Used by Financing (56,179) (9,594) (28,225) ---------- ------- ------- Net Increase (Decrease) in Cash and Cash Equivalents 417 (1,662) (744) Cash and Cash Equivalents, Beginning of Year 1,367 3,029 3,773 ---------- ------- ------- Cash and Cash Equivalents, End of Year $ 1,784 $ 1,367 $ 3,029 ========== ======= ======= - ----------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these consolidated financial statements. 33 35 CABOT OIL & GAS CORPORATION CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
Retained Common Preferred Paid-In Earnings (In thousands) Stock Stock Capital (Deficit) Total - -------------------------------------------------------------------------------------------- Balance at December 31, 1995 $ 2,275 $ 183 $241,471 $ (847) $ 243,082 ------- ----- -------- -------- --------- Net Loss (86,618) (86,618) Exercise of Stock Options 3 345 348 Preferred Stock Dividends (5,566) (5,566) Common Stock Dividends at $0.16 Per Share (3,631) (3,631) Stock Grant Vesting 242 242 Other (1) (1) ------- ----- -------- -------- --------- Balance at December 31, 1996 $ 2,278 $ 183 $242,058 $(96,663) $ 147,856 ======= ===== ======== ======== ========= Net Income 20,824 20,824 Exercise of Stock Options 6 607 613 Preferred Stock Dividends (5,566) (5,566) Common Stock Dividends at $0.16 Per Share (3,649) (3,649) Stock Grant Vesting 618 618 Other 8 8 ------- ----- -------- -------- --------- Balance at December 31, 1997 $ 2,284 $ 183 $243,283 $(85,046) $ 160,704 ======= ===== ======== ======== ========= Net Income 28,334 28,334 Exercise of Stock Options 14 2,183 2,197 Preferred Stock Dividends (5,103) (5,103) Common Stock Dividends (3,732) (3,732) at $0.16 Per Share Stock Grant Vesting 1,662 1,662 Conversion of $3.125 Preferred Stock to Common Stock 165 (70) (95) 0 Other 4 (4) 0 ------- ----- -------- -------- --------- BALANCE AT DECEMBER 31, 1997 $ 2,467 $ 113 $247,033 $(65,551) $ 184,062 ======= ===== ======== ======== ========= - ---------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these consolidated financial statements. 34 36 CABOT OIL & GAS CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION Cabot Oil & Gas Corporation and subsidiaries (the "Company") are engaged in the exploration, development, production and marketing of natural gas and, to a lesser extent, crude oil and natural gas liquids. The Company also transports, stores, gathers and purchases natural gas for resale. The consolidated financial statements contain the accounts of the Company after elimination of all significant intercompany balances and transactions. PIPELINE EXCHANGES Natural gas gathering and pipeline operations normally include exchange arrangements with customers and suppliers. The volumes of natural gas due to or from the Company under exchange agreements are recorded at average selling or purchase prices, as the case may be, and are adjusted monthly to reflect market changes. The net value of exchanged natural gas is included in inventories in the consolidated balance sheet. PROPERTIES AND EQUIPMENT The Company uses the successful efforts method of accounting for oil and gas producing activities. Under this method, acquisition costs for proved and unproved properties are capitalized when incurred. Exploration costs, including geological and geophysical costs, the costs of carrying and retaining unproved properties and exploratory dry hole drilling costs, are expensed. Development costs, including the costs to drill and equip development wells, and successful exploratory drilling costs that locate proved reserves, are capitalized Before the Company adopted Statement of Financial Accounting Standard ("SFAS") No. 121 on September 1, 1995, the Company limited the total amount of unamortized capitalized costs to the value of future net revenues, based on current prices and costs. Under SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of", the unamortized capital costs at a lease level are reduced to fair value if it is determined that the sum of expected future net cash flows is less than the net book value (See Note 15 Accounting For Long-Lived Assets). The Company makes a determination of an impairment event through either adverse changes or a periodic review of all fields each year. Capitalized costs of proved oil and gas properties, after considering estimated dismantlement, restoration and abandonment costs, net of estimated salvage values, are depreciated and depleted on a field basis by the unit-of-production method using proved developed reserves (See Note 14 Accounting Change). The costs of unproved oil and gas properties are generally aggregated and amortized over a period that is based on the average holding period for such properties and the Company's experience of successful drilling. Properties related to gathering and pipeline systems and equipment are depreciated using the straight-line method based on estimated useful lives ranging from 10 to 25 years. Certain other assets are also depreciated on a straight-line basis. Future estimated plug and abandonment cost is accrued over the productive life of the oil and gas properties. The accrued liability for plug and abandonment cost is included in accumulated depreciation, depletion and amortization. Costs of retired, sold or abandoned properties, constituting a part of an amortization base, are charged to accumulated depreciation, depletion, and amortization. Accordingly, gain or loss, if any, is recognized only when a group of proved properties (or field), constituting the amortization base, has been retired, abandoned or sold. 35 37 REVENUE RECOGNITION AND GAS IMBALANCES The Company applies the sales method of accounting for natural gas revenue. Under this method, revenues are recognized based on the actual volume of natural gas sold to purchasers. Natural gas production operations may include joint owners who take more or less than the production volumes entitled to them on certain properties. Volumetric production is monitored to minimize these natural gas imbalances. A natural gas imbalance liability is recorded in other liabilities in the consolidated balance sheet if the Company's excess takes of natural gas exceed its estimated remaining recoverable reserves for such properties. INCOME TAXES The Company follows the asset and liability method in accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to turn around. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. NATURAL GAS MEASUREMENT The Company records estimated amounts for natural gas revenues and natural gas purchase costs based on volumetric calculations under its natural gas sales and purchase contracts. Variances or imbalances resulting from such calculations are inherent in natural gas sales, production, operation, measurement, and administration. Management does not believe that differences between actual and estimated natural gas revenues or purchase costs attributable to the unresolved variances or imbalances are material. ACCOUNTS PAYABLE This account includes credit balances to the extent that checks issued have not been presented to the Company's bank for payment. These credit balances included in accounts payable were approximately $5.5 million and $10.4 million at December 31, 1997 and 1996, respectively. EARNINGS (LOSS) PER COMMON SHARE In February 1997, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 128, Earnings per Share ("SFAS 128"). The Company has adopted this statement effective December 31, 1997. SFAS 128 simplifies the computation of earnings per share for companies with complex capital structure by replacing primary and fully diluted presentations with the new basic and diluted disclosures. It has not impacted the Company's previously disclosed earnings per share since the Company had a simple capital structure and because earnings per share in prior years was calculated in the same manner that the new "Basic" earnings per share is presented. Basic earnings per share amounts are based on the weighted average of shares outstanding ( 23,272,432 in 1997 and 22,806,516 in 1996). See Note 20 Earnings (Loss) Per Common Share for further discussion. RISK MANAGEMENT ACTIVITIES From time to time, the Company enters into derivative contracts, such as natural gas price swaps, as a hedging strategy to manage commodity price risk associated with its inventories, production or other contractual commitments. Gains or losses on these hedging activities are generally recognized over the period that the inventory, production or other underlying commitment is hedged. The cash flows related to any recognized gains or losses associated with these hedges are reported as cash flows from operations. If the hedge is terminated prior to expected maturity, gains or losses are deferred and included in income in the same period that the underlying production or other contractual commitment is delivered. Unrealized gains or losses associated with any derivative contracts not considered to be a hedge are recognized currently in the results of operations. 36 38 The conditions to be met for a derivative instrument to qualify as a hedge are as follows: (1) the item to be hedged exposes the Company to price risk; (2) the derivative reduces the risk exposure and is designated as a hedge at the time the derivative contract is entered into; and (3) at the inception of the hedge and throughout the hedge period there is a high correlation of the changes in the market value of the derivative instrument and the fair value of the underlying item being hedged. When the designated item associated with a derivative instrument matures, is sold, extinguished or terminated, derivative gains or losses are recognized as part of the gain or loss on sale or settlement of the underlying item. When a derivative instrument is associated with an anticipated transaction that is no longer expected to occur or if correlation no longer exists, the gain or loss on the derivative is recognized currently in the results of operations to the extent the market value changes in the derivative have not been offset by the effects of the price changes on the hedged item since the inception of the hedge. See Note 13 Financial Instruments for further discussion. CASH EQUIVALENTS The Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. 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 and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company's most significant financial estimates are based on remaining proved oil and gas reserves (see Supplemental Oil and Gas Information). Actual results could differ from those estimates. RECLASSIFICATIONS Certain items within the Consolidated Statement of Operations for the year ended 1995 have been reclassified to conform with the 1996 and 1997 presentation. Under the new presentation, the Company presents gas revenues from its equity production net of related costs (principally transportation and storage costs) in a new revenue item called "Natural Gas Production". Similarly, the procurement costs related to the purchase and resale (brokered) activity are netted against the gas revenues and presented in a new item called "Brokered Natural Gas Margin" in the net operating revenues section. 2. PROPERTIES AND EQUIPMENT Properties and equipment are comprised of the following:
December 31, (In thousands) 1997 1996 - ------------------------------------------------------------ Unproved Oil and Gas Properties $ 24,618 $ 15,746 Proved Oil and Gas Properties 744,381 811,726 Gathering and Pipeline Systems 116,360 150,910 Land, Building and Improvements 3,896 5,221 Other 17,525 16,028 --------- --------- 906,780 999,631 Accumulated Depreciation, Depletion and Amortization (437,381) (519,120) --------- --------- $ 469,399 $ 480,511 ========= =========
As a component of accumulated depreciation, depletion and amortization, total accrued future plug and abandonment cost was $13.1 million and $14.8 million at December 31, 1997 and 1996, respectively. The Company believes that this accrual adequately provides for its estimated future plug and abandonment cost. 37 39 3. ADDITIONAL BALANCE SHEET INFORMATION Certain balance sheet amounts are comprised of the following:
December 31, (In thousands) 1997 1996 - ------------------------------------------------------------------------ Accounts Receivable Trade Accounts $ 49,315 $ 63,458 Insurance Recoveries 3,043 -- Current Income Tax Receivable 1,291 -- Other Accounts 6,562 5,021 -------- -------- 60,211 68,479 Allowance for Doubtful Accounts (539) (669) -------- -------- $ 59,672 $ 67,810 ======== ======== Accounts Payable Trade Accounts $ 6,209 $ 12,277 Natural Gas Purchases 13,991 20,726 Royalty and Other Owners 11,995 13,469 Capital Costs 12,936 5,409 Dividends Payable 851 1,391 Taxes Other Than Income 1,478 1,170 Drilling Advances 2,333 111 Other Accounts 2,555 1,785 -------- -------- $ 52,348 $ 56,338 ======== ======== Accrued Liabilities Employee Benefits $ 6,067 $ 4,432 Taxes Other Than Income 8,314 8,407 Interest Payable 2,147 2,188 Other Accrued 996 1,252 -------- -------- $ 17,524 $ 16,279 ======== ======== Other Liabilities Postretirement Benefits Other Than Pension $ 992 $ 1,853 Accrued Pension Cost 3,742 4,022 Taxes Other Than Income and Other 4,029 4,718 -------- -------- $ 8,763 $ 10,593 ======== ========
4. INVENTORIES Inventories are comprised of the following:
December 31, (In thousands) 1997 1996 - -------------------------------------------------------------------------------- Natural Gas in Storage $ 6,322 $ 7,312 Tubular Goods and Well Equipment 1,663 1,677 Pipeline Exchange Balances (1,110) (192) ---------- --------- $ 6,875 $ 8,797 ========== =========
5. DEBT AND CREDIT AGREEMENTS SHORT-TERM DEBT The Company has a $5.0 million unsecured short-term line of credit with a bank which it uses as part of its cash management program. The interest rate on the line of credit is at the bank's prime rate minus 1%. The debt agreement was established in February 1996, replacing the previous $5 million short-term line with another bank. Aside from a 38 40 more favorable rate, prime rate minus 1% versus prime rate, the terms of the new line of credit are comparable to the previous line of credit. At December 31, 1997 and 1996, no debt was outstanding under the respective lines. 10.18% NOTES In May 1990, the Company issued an aggregate principal amount of $80 million of its 12-year 10.18% Notes (the "10.18% Notes") to a group of nine institutional investors in a private placement offering. The 10.18% Notes require five annual $16 million principal payments starting in May 1998. The payment due in May 1998 is classified as "Current Portion of Long-Term Debt", a current liability on the Company's Consolidated Balance Sheet. The Company may prepay all or any portion of the indebtedness on any date with a prepayment premium. Due to the impact of the interest rate swap instruments obtained in 1993 (see "Interest Rate Swap Agreements" under Note 13 Financial Instruments), the Company's effective interest rate for the 10.18% Notes in the year ended December 31, 1995 was 12.6%. This effective rate excluded the $2.6 million charge in December 1995 to terminate the remaining interest rate swaps. Without the impact of the interest rate swaps, closed in 1995, the effective interest rate returned to 10.18% in 1996 and 1997. The 10.18% Notes contain restrictions on the merger of the Company or any subsidiary with a third party other than under certain limited conditions, as well as various other restrictive covenants customarily found in such debt instruments, including a restriction on the payment of dividends and a required asset coverage ratio (present value of proved reserves to debt and other liabilities) that must be at least 1.5 to 1.0. 7.19% NOTES In November 1997, the Company issued an aggregate principal amount of $100 million of its 12-year 7.19% Notes (the "7.19% Notes") to a group of six institutional investors in a private placement offering. The 7.19% Notes require five annual $20 million principal payments starting in November 2005. The Company may prepay all or any portion of the indebtedness on any date with a prepayment premium. The 7.19% Notes contain restrictions on the merger of the Company or any subsidiary with a third party other than under certain limited conditions, as well as various other restrictive covenants customarily found in such debt instruments, including a required asset coverage ratio (present value of proved reserves to debt and other liabilities) that must be at least 1.5 to 1.0; and a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0. REVOLVING CREDIT AGREEMENT The Company has a $135 million Revolving Credit Agreement (the "Credit Facility") with five banks. During 1997, the Company elected to reduce its availability under the Credit Facility to the existing $135 million level from $235 million in connection with the issuance of the 7.19% Notes. The available credit line is subject to adjustment from time-to-time on the basis of the projected present value (as determined by a petroleum engineer's report incorporating certain assumptions provided by the lender) of estimated future net cash flows from certain proved oil and gas reserves and other assets of the Company. In May 1997, the revolving term under the Credit Facility was extended one year to June 1999. Interest rates are principally based on a reference rate of either the rate for certificates of deposit ("CD rate") or LIBOR, plus a margin, or the prime rate. The margin above the reference rate is presently equal to 3/4 of 1% for the LIBOR based rate, or 7/8 of 1% for the CD based rate. The Credit Facility provides for a commitment fee on the unused available balance at an annual rate of 3/8 of 1% and a commitment fee on the unavailable balance of the credit line at an annual rate of 1/4 of 1%. The Company's effective interest rates for the Credit Facility in the years ended December 31, 1997, 1996 and 1995 were 6.6%, 6.6% and 6.8%, respectively. Although the revolving term of the Credit Facility expires in June 1999, it may be extended with the banks' approval. If such term is not extended, the indebtedness outstanding will be payable in 24 quarterly installments. Interest rates are subject to increase if the indebtedness under the Credit Facility is greater than 80% of the Company's debt limit of $315 million, as noted below. The Credit Facility contains various restrictive covenants customarily found in such facilities, including restrictions (i) prohibiting the merger of the Company or any subsidiary with a third party other than under certain limited conditions, (ii) prohibiting the sale of all or substantially all of the Company's or any subsidiary's assets to a third party, and (iii) requiring a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0. 39 41 6. EMPLOYEE BENEFIT PLANS PENSION PLAN The Company has a non-contributory, defined benefit pension plan covering all full-time employees. The benefits for this plan are based primarily on years of service and pay near retirement. Plan assets consist principally of fixed income investments and equity securities. The Company funds the plan in accordance with the Employee Retirement Income Security Act of 1974 and Internal Revenue Code limitations. The Company has a non-qualified equalization plan to ensure payments to certain executive officers of amounts to which they are already entitled under the provisions of the pension plan, but which are subject to limitations imposed by federal tax laws. This plan is unfunded. Net periodic pension cost of the Company for the years ended December 31, 1997, 1996 and 1995 are comprised of the following:
(In thousands) 1997 1996 1995 - -------------------------------------------------------------------------------------------- QUALIFIED: Current Year Service Cost $ 753 $ 737 $ 722 Interest Accrued on Pension Obligation 810 744 742 Actual Return on Plan Assets (1,129) (948) (1,327) Net Amortization 491 448 934 Curtailment Gain -- -- (376) Special Termination Benefit -- -- 766 ------- -------- --------- Net Periodic Pension Cost $ 925 $ 981 $ 1,461 ======= ======== ========= NON-QUALIFIED: Current Year Service Cost $ 28 $ 90 $ 63 Interest Accrued on Pension Obligation 6 6 23 Net Amortization 27 34 39 Curtailment Loss -- -- 37 Settlement Charge -- -- 174 ------- -------- --------- Net Periodic Pension Cost $ 61 $ 130 $ 336 ======= ======== =========
The following table sets forth the funded status of the Company's pension plans at December 31, 1997 and 1996, respectively:
1997 1996 (In thousands) QUALIFIED NON-QUALIFIED QUALIFIED NON-QUALIFIED - ------------------------------------------------------------------------------------------------------ Actuarial Present Value of: Vested Benefit Obligation $ 7,838 $ 246 $ 6,946 $ 31 Accumulated Benefit Obligation 8,669 363 7,621 81 Projected Benefit Obligation $ 12,772 $ 668 $ 10,960 $ 81 Plan Assets at Fair Value 8,890 -- 7,074 -- -------- -------- --------- --------- Projected Benefit Obligation in Excess of Plan Assets 3,882 668 3,886 81 Unrecognized Net Gain (Loss) 1,527 (436) 1,750 140 Adjustment to Recognize Minimum Liability 480 Unrecognized Prior Service Cost (862) (349) (950) (386) -------- -------- --------- -------- Accrued (Prepaid) Pension Cost $ 4,547 $ 363 $ 4,686 $ (165) ======== ======== ========= ========
40 42 Assumptions used to determine benefit obligations and pension costs are as follows:
1997 1996 1995 - -------------------------------------------------------------------------------- Discount Rate 7.50% 7.50% 7.50%(1) Rate of Increase in Compensation Levels 4.50% 4.50% 4.50%(1) Long-Term Rate of Return on Plan Assets 9.00% 9.00% 9.00% - --------------------------------------------------------------------------------
(1) Represents the rates used to determine the benefit obligation. An 8.5% discount rate and 5.5% rate of increase in compensation levels were used to compute pension costs. SAVINGS INVESTMENT PLAN The Company has a Savings Investment Plan (the "SIP") which is a defined contribution plan. The Company matches a portion of employees' contributions. Participation in the SIP is voluntary and all regular employees of the Company are eligible to participate. The Company charged to expense plan contributions of $0.6 million, $0.6 million and $0.8 million in 1997, 1996 and 1995, respectively. Effective February 1, 1994, the Company's common stock was added as an investment option within the SIP. POSTRETIREMENT BENEFITS OTHER THAN PENSIONS In addition to providing pension benefits, the Company provides certain health care and life insurance benefits ("postretirement benefits") for retired employees, including their spouses, eligible dependents and surviving spouses ("retirees"). Substantially all employees become eligible for these benefits if they meet certain age and service requirements at retirement. The Company was providing postretirement benefits to 259 retirees and 295 retirees at the end of 1997 and 1996, respectively. The Company adopted SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions", in 1992 and elected to amortize the accumulated postretirement benefit obligation at January 1, 1992 (the "Transition Obligation") over 20 years. The amortization benefit of the unrecognized Transition Obligation in 1997, 1996 and 1995, presented in the table below, is due to a cost-cutting amendment to the postretirement medical benefits in 1993. The amendment prospectively reduced the unrecognized Transition Obligation by $9.8 million and is amortized over a 5.75 year period beginning in 1993. Postretirement benefit costs recognized in the years ended December 31, 1997, 1996 and 1995 are comprised of the following:
(In thousands) 1997 1996 1995 - ----------------------------------------------------------------------------------------------- Service Cost of Benefits Earned During the Year $ 168 $ 99 $ 140 Interest Cost on the Accumulated Postretirement Benefit Obligation 519 522 517 Amortization Benefit of the Unrecognized Gain (181) (163) (249) Amortization Cost (Benefit) of the Unrecognized Transition Obligation (808) (807) (821) Curtailment Loss -- -- 2,074 Special Termination -- -- 503 ------- ------- ------- Total Postretirement Benefit Cost (Benefit) $ (302) $ (349) $ 2,164 ======= ======= =======
41 43 The health care cost trend rate used to measure the expected cost in 1997 for medical benefits to retirees over age 65 was 8.2%, graded down to a trend rate of 0% in 2001. The health care cost trend rate used to measure the expected cost in 1997 for retirees under age 65 was 8.5%, graded down to a trend rate of 0% in 2001. Provisions of the plan should prevent further increases in employer cost after 2001. The weighted average discount rate used in determining the actuarial present value of the benefit obligation at December 31, 1997 and 1996 was 7.5%. A one-percentage-point increase in health care cost trend rates for future periods would increase the accumulated net postretirement benefit obligation by approximately $167 thousand and, accordingly, the total postretirement benefit cost recognized in 1996 would have also increased by approximately $17 thousand. The funded status of the Company's postretirement benefit obligation at December 31, 1997 and 1996 is comprised of the following:
(In thousands) 1997 1996 - ------------------------------------------------------------------------------------------ Plan Assets at Fair Value $ -- $ -- Accumulated Postretirement Benefits Other Than Pensions Retirees 5,626 5,681 Active Participants 1,677 1,526 -------- ------- 7,303 7,207 Unrecognized Cumulative Net Gain 2,429 2,614 Unrecognized Transition Obligation (8,395) (7,587) -------- ------- Accrued Postretirement Benefit Liability $ 1,337 $ 2,234 ======== =======
7. INCOME TAXES Income tax expense (benefit) is summarized as follows:
Year Ended December 31, (In thousands) 1997 1996 1995 - ------------------------------------------------------------------------------------ CURRENT: Federal $ 5,210 $ (1,229) $ -- State 1,089 316 30 ---------- ---------- ----------- Total 6,299 (913) 30 ---------- ---------- ----------- DEFERRED: Federal 9,382 9,756 (46,430) State 1,876 1,711 (8,625) ---------- ---------- ---------- Total 11,258 11,467 (55,055) ---------- ---------- ---------- Total Income Tax Expense (Benefit) $ 17,557 $ 10,554 $ (55,025) ========== ========== ==========
Total income taxes were different than the amounts computed by applying the statutory federal income tax rate as follows:
Year Ended December 31, (In thousands) 1997 1996 1995 - ----------------------------------------------------------------------------------------- Statutory Federal Income Tax Rate 35% 35% 35% Computed "Expected" Federal Income Tax $ 16,062 $ 10,982 $(49,575) State Income Tax, Net of Federal Income Tax 1,927 1,317 (5,586) Other, Net (432) (1,745) 136 -------- -------- -------- Total Income Tax Expense (Benefit) $ 17,557 $ 10,554 $(55,025) ======== ======== ========
42 44 Income taxes for the year ended December 31, 1996 were decreased by $1.8 million due to a federal income tax refund in connection with percentage depletion claimed in certain periods prior to the Company's IPO in 1990. The Company also received $1.7 million of interest income in connection with the income tax refund. The tax effects of temporary differences that gave rise to significant portions of the deferred tax liabilities and deferred tax assets as of December 31, 1997 and 1996 were as follows:
(In thousands) 1997 1996 - ---------------------------------------------------------------------------- DEFERRED TAX LIABILITIES: Property, Plant and Equipment $115,808 $115,099 -------- -------- DEFERRED TAX ASSETS: Alternative Minimum Tax Credit Carryforwards 9,674 3,786 Net Operating Loss Carryforwards 6,749 17,708 Note Receivable on Section 29 Monetization(1) 13,933 18,347 Items Accrued for Financial Reporting Purposes 5,344 5,831 -------- -------- 35,700 45,672 -------- -------- Net Deferred Tax Liabilities $ 80,108 $ 69,427 ======== ======== - ----------------------------------------------------------------------------
(1) As a result of the monetization of Section 29 tax credits in 1997 and 1996, the Company recorded an asset sale for tax purposes in exchange for a long-term note receivable which will be repaid through 100% working and royalty interest in the production from the sold properties. At December 31, 1997, the Company has a net operating loss carryforward for regular income tax reporting purposes of $18.2 million which will begin expiring in 2009. In addition, the Company has an alternative minimum tax credit carryforward of $9.7 million which does not expire and is available to offset regular income taxes in future years to the extent that regular income taxes exceed the alternative minimum tax in any such year. In 1996, the Company recorded a $5.3 million adjustment reducing deferred tax liabilities for the reversal of temporary differences associated with the $8.4 million valuation adjustment received in 1995 on the 1994 WERCO acquisition (See Note 11 WERCO Acquisition). 8. COMMITMENTS AND CONTINGENCIES LEASE COMMITMENTS The Company leases certain transportation vehicles, warehouse facilities, office space and machinery and equipment under cancelable and non-cancelable leases, most of which expire within five years and may be renewed by the Company. Rent expense under such arrangements totaled $4.1 million, $4.8 million and $4.9 million for the years ended December 31, 1997, 1996 and 1995, respectively. Future minimum rental commitments under non-cancelable leases in effect at December 31, 1997 are as follows:
(In thousands) - ---------------------------------------------- 1998 $ 2,932 1999 2,146 2000 1,422 2001 1,039 2002 906 Thereafter 430 -------- $ 8,875 ========
Minimum rental commitments are not reduced by minimum sublease rental income of $1.4 million due in the future under non-cancelable subleases. 43 45 CONTINGENCIES The Company is a defendant in various lawsuits and is involved in other gas contract issues. In the opinion of the Company, final judgments or settlements, if any, which may be awarded in connection with any one or more of these suits and claims could be significant to the results of operations and cash flows of any period but would not have a material adverse effect on the Company's financial position. The Company sells approximately 20,000 Mmbtu of its natural gas per day in the Western Region to a cogeneration plant owned by Encogen Northwest, L.P. ("Encogen") under a contract containing a fixed price that escalates annually, a firm delivery arrangement and a term continuing through June 30, 2008. Encogen has requested that the Company consider restructuring this agreement. Thus far the Company has been unwilling to restructure the agreement without full compensation for the agreements value. See Item 3. Legal Proceedings for further discussion of this matter. 9. CASH FLOW INFORMATION Cash paid for interest and income taxes is as follows:
Year Ended December 31, (In thousands) 1997 1996 1995 - -------------------------------------------------------------------------------- Interest $18,001 $17,105 $24,744 Income Taxes $ 8,980 $ 873 $ 197
At December 31, 1997 and 1996, the majority of cash and cash equivalents is concentrated in one financial institution. Additionally, the Company has accounts receivable that are subject to credit risk. At December 31, 1997 and 1996, the Accounts Payable balance on the Consolidated Balance Sheet included payables for capital expenditures of $12.9 million and $5.4 million, respectively. 10. CAPITAL STOCK INCENTIVE PLANS On May 20, 1994, the 1994 Long-Term Incentive Plan and the 1994 Non-Employee Director Stock Option Plan were approved by the shareholders. The Company has two other stock option plans - the Incentive Stock Option Plan, adopted in 1990, and the 1990 Non-Employee Director Stock Option Plan. Under these four plans (the "Incentive Plans"), incentive and non-statutory stock options, stock appreciation rights ("SARs") and stock awards may be granted to key employees and officers of the Company, and non-statutory stock options may be granted to non-employee directors of the Company. A maximum of 2,660,000 shares of Common Stock, par value $0.10 per share, are subject to issuance under the Incentive Plans. All stock options have a maximum term of five or ten years from the date of grant and most vest over time. The options are issued at market value on the date of grant. The minimum exercise period for stock options is six months from the date of grant. No SARs have been granted under the Incentive Plans. Information regarding the Company's Incentive Plans is summarized below: 44 46
December 31, 1997 1996 1995 - -------------------------------------------------------------------------------------- Shares Under Option at Beginning of Period 1,532,353 1,310,318 953,775 Granted 82,500 311,750 565,750 Exercised 139,836 41,094 2,400 Surrendered or Expired 70,140 48,621 206,807 ---------- ---------- ---------- Shares Under Option at End of Period 1,404,877 1,532,353 1,310,318 ========== ========== ========== Option Price Range per Share $ 13.25 - $ 13.25 - $ 13.25 - 26.00 26.00 26.00 Options Exercisable at End of Period 1,071,923 1,021,362 852,692 ========== =========== ==========
Under the 1994 Long-Term Incentive plan, the Compensation Committee of the Board of Directors may grant awards of performance shares of stock to members of the executive management group. Each grant of performance shares has a three-year performance period, measured as the change from July 1 of the initial year of the performance period to June 30 of the third succeeding year. The number of shares of common stock received at the end of the performance period is based principally on the relative stock price growth between the two measurement dates of the Company's common stock as compared to that of a list of company peers. The performance shares which were granted on July 1, 1994, expired on June 1, 1997 without the issuance of any common stock of the Company. Performance shares granted in July of 1995 and 1996 may be converted to shares of common stock, depending upon the Company's relative performance to the peer group measured on June 1st of 1998 and 1999, respectively. Management has reviewed Statement of Financial Accounting Standards ("SFAS") No. 123, "Accounting for Stock-Based Compensation", which outlines a fair value based method of accounting for stock options or similar equity instruments and has opted to continue using the intrinsic value based method, as prescribed by Accounting Principles Board ("APB") Opinion No. 25, to measure compensation cost for its stock option plans. The pro forma results of operations, had the Company adopted SFAS 123, were net income of $22.9 million and $14.8 million, or $0.98 and $0.65 per share, in 1997 and 1996, respectively, and a net loss of $92.9 million, or $4.08 per share, in 1995. Under the fair value based method, the weighted average fair values of options granted during 1997, 1996 and 1995 were $4.26, $5.51 and $4.52, respectively. The fair value of stock options was calculated using a Black-Scholes stock option valuation model with the following weighted average assumptions for grants in 1997, 1996 and 1995: stock price volatility of 25.8 percent; risk free rate of return ranging from 6.20 percent to 6.46 percent; dividend rate of $0.16 per year; and an expected term of 5 years. The fair value of stock options included in the pro forma results for each of the three years is not necessarily indicative of future effects on net income and earnings per share. DIVIDEND RESTRICTIONS The determination of the amount of future cash dividends, if any, to be declared and paid on the Common Stock will be subject to the discretion of the Board of Directors of the Company and will depend upon, among other things, the Company's financial condition, funds from operations, the level of its capital and exploration expenditures, and its future business prospects. The Company's 10.18% note agreement restricts certain payments ("Restricted Payments," as defined in the note agreement) associated with (i) purchasing, redeeming, retiring or otherwise acquiring any capital stock of the Company or any option, warrant or other right to acquire such capital stock or (ii) declaring any dividend, if immediately prior to or after giving effect to such payments, the dividend exceeds consolidated net cash flows, as defined, and the ratio of proved reserves to debt is less than 1.7 to 1, or an event of default has occurred under the note agreement. As of December 31, 1997, such restrictions had no adverse impact on the Company's ability to pay regular dividends. The agreement related to 7.19% Notes issued in 1997 contains no restricted payment provision. PURCHASE RIGHTS On January 21, 1991, the Board of Directors adopted the Preferred Stock Purchase Rights Plan and declared a dividend distribution of one right for each outstanding share of Common Stock. Each right becomes exercisable, at a price of $55, when any person or group has acquired, obtained the right to acquire or made a tender or exchange offer for beneficial ownership of 15 percent or more of the Company's outstanding Common Stock, except pursuant to a 45 47 tender or exchange offer for all outstanding shares of Common Stock deemed to be fair and in the best interests of the Company and its stockholders by a majority of the independent Continuing Directors (as defined in the plan). Each right entitles the holder, other than the acquiring person or group, to purchase one one-hundredth of a share of Series A Junior Participating Preferred Stock ("Junior Preferred Stock"), or to receive, after certain triggering events, Common Stock or other property having a market value (as defined in the plan) of twice the exercise price of each right. After the rights become exercisable, if the Company is acquired in a merger or other business combination in which it is not the survivor or 50 percent or more of the Company's assets or earning power are sold or transferred, each right entitles the holder to purchase common stock of the acquiring company with a market value (as defined in the plan) equal to twice the exercise price of each right. At December 31, 1997, there were no shares of Junior Preferred Stock issued. The rights, which expire on January 21, 2001, and the exercise price are subject to adjustment and may be redeemed by the Company for $0.01 per right at any time before they become exercisable. Under certain circumstances, the Continuing Directors may opt to exchange one share of Common Stock for each exercisable right. PREFERRED STOCK At December 31, 1996, 692,439 shares of the Company's $3.125 cumulative convertible preferred stock ("$3.125 preferred stock") were issued and outstanding. Each share had a stated value of $50 and was convertible any time by the holder into Common Stock at a conversion price of $21 per share. These shares were also redeemable under certain provisions and fixed redemption prices. The Company had the option to convert the $3.125 preferred stock into shares of Common Stock valued at the conversion price if the closing price of the Common Stock was at least equal to the conversion price for 20 consecutive trading days. In October 1997, the Company exercised this right and converted all of the 692,439 shares of $3.125 preferred stock into 1,648,664 shares of Common Stock. At December 31, 1996 and 1995, 1,134,000 shares of 6% convertible redeemable preferred stock ("6% preferred stock") were issued and outstanding (See Note 11 WERCO Acquisition). Each share has voting rights equal to approximately 1.7 shares of Common Stock, a stated value of $50 and is convertible by the holder, at any time at least five days prior to the date fixed for redemption by the Company's Board of Directors, into Common Stock at a conversion price of $28.75 per share, subject to adjustment. Starting on May 2, 1998, the 6% preferred stock is redeemable, in whole or in part, at the Company's option price of $50 per share. Commencing May 2, 1998 and continuing until May 2, 1999, the Company may redeem the 6% preferred stock at $50 per share, payable in Common Stock, using the market price of the Common Stock on the date redeemed, plus a cash payment for the accrued dividends due on the shares redeemed. On or after May 2, 1999, the $50 per share redemption price is payable in cash, plus a cash payment for accrued dividends due on the shares redeemed. 11. WERCO ACQUISITION On May 2, 1994, the Company completed the merger between a Company subsidiary and Washington Energy Resources Company ("WERCO"), a wholly-owned subsidiary of Washington Energy Company. The Company acquired the stock of WERCO in a tax-free exchange. Total capitalized costs related to the acquisition were $202.5 million, comprised of cash and stock consideration of $167.6 million (net of an $8.4 million post-closing adjustment in 1995) and a $34.9 million non-cash component (net of a $5.3 million reduction in 1996 related to the 1995 post-closing adjustment) in connection with the deferred income taxes attributable to the differences between the tax and book bases of the acquired properties, as required by SFAS 109, "Accounting for Income Taxes". The acquisition was recorded using the purchase method. The oil and gas properties are located in the Green River Basin of Wyoming and in the Gulf Coast. The Company issued 2,133,000 shares of Common Stock and 1,134,000 shares of 6% convertible redeemable preferred stock ($50 per share stated value) to Washington Energy Company in exchange for the capital stock of WERCO. 46 48 The $8.4 million post-closing adjustment was a net cash payment received in 1995 related to a valuation adjustment and was recorded as a reduction to the net book value of certain of the oil and gas properties acquired. In 1996, the net book value of certain oil and gas properties was further reduced by a $5.3 million non-cash adjustment. This adjustment was to record the reversal of the differences between the tax and book basis related to the 1995 post-closing adjustment. 12. COST REDUCTION PROGRAM In January 1995, the Company announced a cost reduction program which included a voluntary early retirement program, a 15% targeted reduction in work force and a consolidation of management in the Rocky Mountain, Anadarko and onshore Gulf Coast areas into a single Western Region. Accordingly, the Company recognized a liability and charged to expense $6.8 million in termination benefits for 115 employees, or 23% of the total work force, including 24 employees who elected early retirement. The employee terminations were made in virtually all departments both at the Company's corporate headquarters and each of the operating region/area offices. The termination benefits included $3.8 million for severance and related costs, which were paid out by year end and a $3.0 million non-cash charge for curtailments to the Company's pension ($0.4 million) and postretirement ($2.6 million) benefits plans. 13. FINANCIAL INSTRUMENTS The following disclosures on the estimated fair value of financial instruments are presented in accordance with SFAS 107, "Disclosures about Fair Value of Financial Instruments". Fair value, as defined in SFAS 107, is the amount at which the instrument could be exchanged currently between willing parties. The Company uses available marketing data and valuation methodologies to estimate fair value of debt.
DECEMBER 31, 1997 DECEMBER 31, 1996 CARRYING ESTIMATED CARRYING ESTIMATED (IN THOUSANDS) AMOUNT FAIR VALUE AMOUNT FAIR VALUE - ----------------------------------------------------------------------------------------------- DEBT: 10.18% Notes $ 80,000 $ 86,555 $ 80,000 $ 86,433 7.19% Notes 100,000 102,693 -- -- Credit Facility 19,000 19,000 168,000 168,000 ---------- ---------- --------- ---------- $ 199,000 $ 208,248 $ 248,000 $ 254,433 ========== ========== ========= ========== OTHER FINANCIAL INSTRUMENTS: Gas Price Swaps -- $ (350) -- $ 763
LONG-TERM DEBT The fair value of long-term debt is the estimated cost to acquire the debt, including a premium or discount for the differential between the issue rate and the year-end market rate. The fair value of the 10.18% Notes and the 7.19% Notes is based upon interest rates available to the Company. The Credit Facility and the short-term line approximate fair value because these instruments bear interest at rates based on current market rates. 47 49 INTEREST RATE SWAP AGREEMENTS In November 1993, the Company executed reverse interest rate swap agreements with four banks that effectively converted the Company's $80 million fixed rate notes into variable rate notes. Under the swap agreements, the Company paid a variable rate of interest that was based on the six-month LIBOR. The banks paid the Company fixed rates of interest that average 5.00%. The four agreements had notional principal of $20 million each with terms of two, three, four and five years. The fair value was determined by obtaining termination values from third parties. In January 1995, the Company entered into four additional swap agreements which effectively fixed interest payments on the original interest rate swaps until May 1997. In 1995, the Company recorded $4.5 million of interest expense related to these swap agreements. GAS PRICE SWAPS The Company has entered into several price swap agreements with counterparties. In a majority of the natural gas price swap agreements in 1996, the Company received a fixed price ("fixed price swap contracts") for a notional quantity of natural gas in exchange for its paying a variable price based on a market based index, such as the NYMEX gas futures. The fixed price swap contracts are used to hedge price risk associated with the Company's production. During 1996, the fixed prices received on closed contracts ranged from $1.02 to $2.54 per Mmbtu on total notional quantities of 17,600,000 Mmbtu. There were no fixed price swap contracts open at December 31, 1996. During 1997, the Company entered into no fixed price swap contracts to hedge prices on its production. Typically, the Company enters into contracts to sell its natural gas at a variable price based on the market index price. However, in some circumstances, some of the Company's customers request that a fixed price be stated in the contract. After entering into these certain fixed price sales contracts to meet the needs of its customers, the Company typically opens gas swap agreements to convert these fixed price contracts to market-sensitive price contracts. These agreements had total notional quantities of 2,683,000 Mmbtu and 1,002,000 Mmbtu in closed contracts in 1997 and 1996, respectively. In 1997 and 1996, this represented approximately 7% and 3%, respectively, of the Company's total volume of brokered gas sold. Additional agreements which remained open at year end had notional quantities of 248,000 Mmbtu and 744,000 Mmbtu in 1997 and 1996, respectively. The estimated fair value of price swaps in the table above are for hedged transactions in which gains or losses are recognized in results of operations over the periods that production or purchased gas is hedged (see "Risk Management Activities" under Note 1). Certain of the fixed price swap contracts, open at December 31, 1995, became 'uncovered' due to an unprecedented decoupling of the NYMEX gas prices from realizable sales prices in the physical markets. These 'uncovered' hedge contracts had notional quantities totaling 5,480,000 Mmbtu and covered the contract months of January to April 1996. Accordingly, the Company recorded a $3.2 million unrealized loss at December 31, 1995. The Company is exposed to market risk on these open contracts to the extent of changes in market prices for natural gas. However, the market risk exposure on these hedged contracts is generally offset by the gain or loss recognized upon the ultimate sale of the natural gas that is hedged. CREDIT RISK Although notional contract amounts are used to express the volume of gas price and interest rate swap agreements, the amounts potentially subject to credit risk in the event of non-performance by third parties are substantially smaller. The Company does not anticipate any material impact to its financial results due to non-performance by the third parties. 14. ACCOUNTING CHANGE Effective January 1, 1995, the Company changed from the property-by-property basis to the field basis of applying the unit-of-production method to calculate depreciation and depletion on producing oil and gas properties. 48 50 The field basis provides for the aggregation of wells that have a common geological reservoir or field. The field basis provides a better matching of expenses with revenues over the productive life of the properties, and, therefore, the Company believes the new method is preferable to the property-by-property basis. Because the cumulative effect of the change in method from prior periods was insignificant, a pre-tax charge of $303 thousand, such amount ("pre-1995 amount") was included with depreciation, depletion and amortization ("DD&A") expense in 1995. The net effect of the change in method resulted in a $3,967 thousand decrease in DD&A expense and a $2,428 thousand increase in net earnings in 1995, including the impact of the pre-1995 amount. The pro forma impact on the results of operations in 1994, had the change in method been implemented at the beginning of 1994, would have been a decrease in DD&A expense of approximately $2,378 thousand and a $1,446 thousand increase in net earnings. The reduction in DD&A expense for 1995 due to the change in method was offset by higher levels of DD&A expense primarily due to reserve revisions. 15. ACCOUNTING FOR LONG-LIVED ASSETS Effective September 30, 1995, the Company adopted SFAS No. 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of". SFAS 121 requires that an impairment loss be recognized when the carrying amount of an asset exceeds the sum of the undiscounted estimated future cash flow of the asset. Under SFAS 121, the Company reviewed the impairment of oil and gas properties and related assets on an economic unit basis. For each economic unit determined to be impaired, an impairment loss equal to the difference between the carrying value and the fair value of the economic unit was recognized. Fair value, on an economic unit basis, was estimated to be the present value of expected future net cash flows over the economic lives of the reserves. As a result of the adoption of SFAS 121, the Company recognized a non-cash charge during the third quarter of 1995 of $113.8 million ($69.2 million after tax). 16. OIL AND GAS PROPERTY TRANSACTIONS The Company sold various non-core oil and gas properties in the Appalachian Region, receiving proceeds of $4.6 million, in 1996 and in the Western Region, obtaining proceeds of $7.6 million, in 1995. In the fourth quarter of 1997, the Company closed two notable asset transactions. Properties in northwest Pennsylvania (the "Meadville properties"), including 912 wells and 15 Mmcfed of production, were sold to Lomak Petroleum Incorporated for $92.9 million. In a like-kind exchange transaction, the Company matched a portion of the Meadville properties sold with approximately $45 million in oil and gas producing properties acquired from Equitable Resources Energy Company, including 63 wells and 10 Mmcfed of production. 17. OTHER REVENUE The Company recorded $4.6 million ($4.3 million net of severance taxes) in 1995 in other revenue in connection with the sale of certain Columbia Gas Transmission Corporation ("Columbia") bankruptcy claims. The claims related to the remaining value of gas sales in contracts terminated by Columbia as part of its bankruptcy filing in 1991. 18. MONETIZATION OF SECTION 29 TAX CREDITS The Company completed two transactions in September and November 1995 and a third transaction in August 1996 to monetize the value of Section 29 tax credits from most of its qualifying Appalachian and Rocky Mountain properties. The transactions provided up-front cash of $2.8 million in 1995 and $0.6 million in 1996 which was recorded as a reduction to the net book value of natural gas properties, and will generate additional revenues through 2002 estimated at $23 million ($3.6 million in 1997 and $3.4 million in 1996) related to the value of future Section 29 tax credits attributable to these properties. Employing a volumetric production payment structure, the production, revenues, expenses and proved reserves related to these properties will continue to be reported by the Company as Other Revenue until the production payment is satisfied. 49 51 19. SUPPLEMENTAL FULL COST ACCOUNTING INFORMATION U.S. oil and gas producing entities may utilize one of two methods of financial accounting: successful efforts or full cost. Given the current composition of the Company's properties, management considers the successful efforts method to be more appropriate than the full cost method primarily because the successful efforts method results in moderately better matching of costs and revenues. It has come to management's attention that certain users of the Company's financial statements believe that information about the Company prepared under the full cost method would be useful. As a result, management has presented the following supplemental full cost information. Successful efforts methodology is explained in Note 1. Summary of Significant Accounting Policies. Under the full cost method of accounting, all costs incurred in the acquisition, exploration and development of oil and gas properties are capitalized. Such capitalized costs and estimated future development and dismantlement costs are amortized on a unit-of-production method based on proved reserves. Net capitalized costs of oil and gas properties are limited to the lower of unamortized cost or the cost center ceiling, defined as: (1) the present value (10% discount rate) of estimated unescalated future net revenues from proved reserves, plus (2) the cost of properties not being amortized, plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, minus (4) the deferred tax liabilities for the temporary differences between the book and tax basis of oil and gas properties. Proceeds from the sale of oil and gas properties are applied to reduce the costs in the cost center unless the sale involves a significant quantity of reserves in relation to the cost center, in which case a gain or loss is recognized. Unevaluated properties and associated costs not currently being amortized and included in oil and gas properties totaled $24.6 million, $15.7 million, and $12.5 million at December 31, 1997, 1996, and 1995, respectively. Because of the capital cost limitations, described above, full cost entities are not subject to the impairment test prescribed by SFAS 121 (see Note 15. Accounting for Long-Lived Assets).
1997 1996 1995 -------------------- ------------------- -------------------------- SUCCESSFUL FULL SUCCESSFUL FULL SUCCESSFUL FULL (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) EFFORTS COST EFFORTS COST EFFORTS COST - ---------------------------------------------------------------------------------------------------------------------------- BALANCE SHEET: Properties and Equipment, Net $ 469,399 $ 651,739 $ 480,511 $ 657,957 $ 474,371 $ 646,322 Stockholders' Equity 184,062 296,201 160,704 269,833 147,856 253,606 INCOME STATEMENT: Depreciation, Depletion, Amortization and Unproved Property Impairment $ 43,454 $ 52,383 $ 45,390 $ 50,769 $ 52,253 $ 51,922 Impairment of Long-Lived Assets -- -- -- -- 113,795 -- Impairment - Full Cost Ceiling -- -- -- -- -- -- Net Income (Loss) Applicable to Common Stockholders 23,231 26,240 15,258 18,637 (92,171) (17,481) Basic Earnings (Loss) Per Share $ 1.00 $ 1.13 $ 0.67 $ 0.82 $ (4.05 $ (0.77)
20. EARNINGS (LOSS) PER COMMON SHARE The adoption of SFAS 128 effective December 31, 1997, requires the restatement of Earnings (Loss) Per Share of each year presented in the Consolidated Statement of Operations. Since the Company has a simple capital structure, previously disclosed Earnings (Loss) Per Share represents Basic Earnings (Loss) Per Share. Diluted Earnings (Loss) Per Share reflects the assumed conversion of outstanding stock options and stock grants. Both the $3.125 cumulative convertible preferred stock and the 6% convertible redeemable preferred stock ("preferred stock"), issued May 1994 and May 1995, respectively, had an antidilutive effect on earnings per common share. The preferred stock was determined not to be a common stock equivalent at the time of issuance. During 1997, 1,648,664 common shares were issued upon conversion of all of the 692,439 shares of $3.125 Cumulative Convertible Preferred stock. The preferred stock became convertible at the Company's option when the 50 52 Company's common shares closed at or above the $21.00 conversion price of the $3.125 cumulative convertible preferred stock for twenty consecutive days. Earnings per share, basic and diluted, are calculated as follows:
(in thousands, except per share data) 1997 1996 1995 - ----------------------------------------------------------------------------------------------- BASIC EARNINGS (LOSS) PER COMMON SHARE: Income before cumulative effect of changes $ 23,231 $ 15,258 $(22,984) in accounting principles Cumulative effect of changes in accounting principles -- -- (69,187) -------- -------- -------- Net Income - Basic EPS $ 23,231 $ 15,258 $(92,171) Weighted average common shares outstanding 23,272 22,807 22,775 Basic earnings (loss) per common share $ 1.00 $ 0.67 $ (4.05) ================================================================================================= DILUTED EARNINGS (LOSS) PER COMMON SHARE: Income before cumulative effect of changes $ 23,231 $ 15,258 $(22,984) in accounting principles Cumulative effect of changes in accounting principles -- -- (69,187) -------- -------- -------- Net Income - Diluted EPS $ 23,231 $ 15,258 $(92,171) Diluted earnings (loss) per common share $ 0.97 $ 0.66 $ (4.05) Weighted average common shares outstanding 23,272 22,807 22,775 Dilutive effect of: Stock Options(1) 275 70 -- Stock Grants(1) 375 116 -- Weighted average shares outstanding - Diluted 23,922 22,993 22,775 =====================================================================================================
(1) In 1995, the stock options and stock grants are anti-dilutive and, therefore, excluded from the calculation of Diluted Earnings (Loss) Per Share. 51 53 CABOT OIL & GAS CORPORATION SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) OIL AND GAS RESERVES Users of this information should be aware that the process of estimating quantities of "proved" and "proved developed" natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures. Proved reserves represent estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods being utilized at the time the estimates were made. Estimates of proved and proved developed reserves at December 31, 1997, 1996 and 1995 were based on studies performed by the Company's petroleum engineering staff. The estimates prepared by the Company's engineering staff were reviewed by Miller and Lents, Ltd., who indicated in their recent letter dated February 9,1998 that, based on their investigation and subject to the limitations described in such letter, it was their judgment that the results of those estimates and projections for 1997 were reasonable in the aggregate. No major discovery or other favorable or adverse event subsequent to December 31, 1997 is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date. The following table sets forth the Company's net proved reserves, including changes therein, and proved developed reserves for the periods indicated, as estimated by the Company's engineering staff. All reserves are located in the United States.
Natural Gas --------------------------------------------- December 31, (Millions of cubic feet) 1997 1996 1995 - ------------------------------------------------------------------------------------------------ PROVED RESERVES Beginning of Year 915,617 889,850 953,083 Revisions of Prior Estimates 6,744 2,774 14,032 Extensions, Discoveries and Other Additions 109,191 69,708 34,408 Production (63,889) (58,762) (57,721) Purchases of Reserves in Place 73,836 37,397 1,416 Sales of Reserves in Place (138,070) (25,350) (55,368) -------- ------- ------- End of Year 903,429 915,617 889,850 ======= ======= ======= PROVED DEVELOPED RESERVES 738,764 768,097 747,235 ======= ======= =======
52 54
Liquids ---------------------------------- December 31, (Thousands of barrels) 1997 1996 1995 - --------------------------------------------------------------------------------------- PROVED RESERVES Beginning of Year 5,166 5,310 8,036 Revisions of Prior Estimates 99 (132) (648) Extensions, Discoveries and Other Additions 794 386 174 Production (629) (597) (740) Purchases of Reserves in Place 594 215 15 Sales of Reserves in Place (155) (16) (1,527) ----- ----- ----- End of Year 5,869 5,166 5,310 ===== ===== ===== PROVED DEVELOPED RESERVES 4,859 4,685 4,970 ===== ===== =====
CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES The following table sets forth the aggregate amount of capitalized costs relating to natural gas and crude oil producing activities and the aggregate amount of related accumulated depreciation, depletion and amortization.
Year Ended December 31, (In thousands) 1997 1996 1995 - ------------------------------------------------------------------------------- Aggregate Capitalized Costs Relating to Oil and Gas Producing Activities $ 904,669 $ 997,531 $ 977,885 Aggregate Accumulated Depreciation, Depletion and Amortization $ 435,502 $ 517,249 $ 503,757
COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES Costs incurred in property acquisition, exploration and development activities were as follows:
Year Ended December 31, (In thousands) 1997 1996 1995 - -------------------------------------------------------------------------------- Property Acquisition Costs - Proved $ 45,573 $ 6,637 $ 33 Property Acquisition Costs - Unproved 4,302 4,355 2,006 Exploration and Extension Well Costs 28,633 14,192 8,670 Development Costs 53,441 41,036 18,610 -------- -------- -------- Total Costs $131,949 $ 66,220 $ 29,319 ======== ======== ========
53 55 HISTORICAL RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES The results of operations for the Company's oil and gas producing activities were as follows:
Year Ended December 31, (In thousands) 1997 1996 1995 - ---------------------------------------------------------------------------------- Operating Revenues $ 173,865 $ 150,096 $ 110,418 Costs and Expenses Production 39,068 35,161 34,062 Other Operating 18,017 15,155 22,783 Exploration 13,884 12,559 8,031 Depreciation, Depletion and Amortization 39,485 40,810 161,886 --------- --------- --------- Total Cost and Expenses 110,454 103,685 226,762 --------- --------- --------- Income (Loss) Before Income Taxes 63,411 46,411 (116,344) Provision for Income Taxes Expense (Benefit) 22,194 16,244 (40,720) --------- --------- --------- Results of Operations $ 41,217 $ 30,167 $ (75,624) ========= ========= =========
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES The following information has been developed utilizing procedures prescribed by SFAS 69 and based on natural gas and crude oil reserve and production volumes estimated by the Company's engineering staff. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company. The Company believes that the following factors should be taken into account in reviewing the following information: (i) future costs and selling prices will probably differ from those required to be used in these calculations; (ii) due to future market conditions and governmental regulations, actual rates of production achieved in future years may vary significantly from the rate of production assumed in the calculations; (iii) selection of a 10% discount rate is arbitrary and may not be reasonable as a measure of the relative risk inherent in realizing future net oil and gas revenues; and (iv) future net revenues may be subject to different rates of income taxation. Under the Standardized Measure, future cash inflows were estimated by applying year-end oil and gas prices adjusted for fixed and determinable escalations, to the estimated future production of year-end proved reserves. The average prices related to proved reserves at December 31, 1997, 1996 and 1995 were for oil ($/Bbl) $19.02, $22.86 and $17.06, respectively, and for natural gas ($/Mcf) $2.44, $3.55 and $2.06, respectively. Future cash inflows were reduced by estimated future development and production costs based on year-end costs in order to arrive at net cash flow before tax. Future income tax expense has been computed by applying year-end statutory tax rates to future pretax net cash flows, reduced by the tax basis of the properties involved. Use of a 10% discount rate is required by SFAS 69. Management does not rely solely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated. 54 56 Standardized Measure is as follows:
Year Ended December 31, (In thousands) 1997(1) 1996(1) 1995 - ---------------------------------------------------------------------------------------------- Future Cash Inflows $2,539,287 $ 3,528,558 $ 2,194,751 Future Production and Development Costs (686,689) (773,631) (644,586) ---------- ----------- ----------- Future Net Cash Flows Before Income Taxes 1,852,598 2,754,927 1,550,165 10% Annual Discount for Estimated Timing of Cash Flows (1,013,837) (1,589,290) (884,861) ---------- ----------- ----------- Standardized Measure of Discounted Future Net Cash Flows Before Income Taxes 838,761 1,165,637 665,304 Future Income Tax Expenses, Net of 10% Annual Discount(2) (227,796) (331,331) (152,356) ---------- ----------- ----------- Standardized Measure of Discounted Future Net Cash Flows (3) $ 610,965 $ 834,306 $ 512,948 ========== =========== ===========
(1) Includes the future cash inflows, production costs and development costs, as well as the tax basis, relating to the properties included in the transactions to monetize the value of Section 29 tax credits. See Note 18 of the Notes to the Consolidated Financial Statements. (2) Future income taxes before discount were $582,639, $887,583 and $462,058 for the years ended December 31, 1997, 1996 and 1995, respectively. (3) The change in discounted future cash flows from 1996 to 1997 is primarily a result of the $1.11 per Mcf decrease in average natural gas price. CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES The following is an analysis of the changes in the Standardized Measure:
Year Ended December 31, (In thousands) 1997 1996 1995 - ------------------------------------------------------------------------------------------------- Beginning of Year $ 834,306 $ 512,948 $ 490,495 Discoveries and Extensions, Net of Related Future Costs 113,032 99,983 21,881 Net Changes in Prices and Production Costs (367,112) 416,042 57,057 Accretion of Discount 116,564 66,530 61,566 Revisions of Previous Quantity Estimates, Timing and Other (10,798) (7,874) 1,707 Development Costs Incurred 17,435 10,294 5,665 Sales and Transfers, Net of Production Costs (138,274) (114,935) (76,356) Net Purchases (Sales) of Reserves in Place (57,723) 30,293 (21,878) Net Change in Income Taxes 103,535 (178,975) (27,189) ---------- ----------- ----------- End of Year $ 610,965 $ 834,306 $ 512,948 ========== ========== ==========
55 57 CABOT OIL & GAS CORPORATION SELECTED DATA (UNAUDITED) QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
(In thousands except per share amounts) First Second Third Fourth Total - ------------------------------------------------------------------------------------------------------- 1997 NET OPERATING REVENUES $ 52,792 $ 39,407 $ 40,773 $ 52,155 $185,127 OPERATING INCOME 22,715 10,013 10,830 20,294 63,852 NET INCOME 9,692 1,955 2,289 9,295 23,231 BASIC EARNINGS PER SHARE $ 0.42 $ 0.09 $ 0.10 $ 0.39 $ 1.00 1996 Net Operating Revenues $ 41,198 $ 37,346 $ 35,497 $ 49,020 $163,061 Operating Income 15,929 8,615 7,577 16,666 48,787 Net Income 5,258 853 2,974 6,173 15,258 Basic Earnings Per Share $ 0.23 $ 0.04 $ 0.13 $ 0.27 $ 0.67 - -------------------------------------------------------------------------------------------------------
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information to be set forth under the caption "Election of Directors" in the Company's definitive proxy statement ("Proxy Statement") in connection with the 1998 annual stockholders meeting is incorporated herein by reference. ITEM 11. EXECUTIVE COMPENSATION The information appearing under the caption "Executive Compensation" in the Proxy Statement is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information appearing under the captions "Beneficial Ownership of Over Five Percent of Common Stock" and "Beneficial Ownership of Directors and Executive Officers" in the Proxy Statement is incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS None. 56 58 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, SCHEDULES AND REPORTS ON FORM 8-K A. INDEX 1. CONSOLIDATED FINANCIAL STATEMENTS See Index on page 30. 2. FINANCIAL STATEMENT SCHEDULES None 3. EXHIBITS The following instruments are included as exhibits to this report. Those exhibits below incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. If no parenthetical appears after an exhibit, copies of the instrument have been included herewith. Exhibit Number Description - -------- ----------- 3.1 Certificate of Incorporation of the Company (Registration Statement No. 33-32553). 3.2 Amended and Restated Bylaws of the Company adopted August 5, 1994. 4.1 Form of Certificate of Common Stock of the Company (Registration Statement No. 33-32553). 4.2 Certificate of Designation for Series A Junior Participating Preferred Stock (Form 10-K for 1994). 4.3 Rights Agreement dated as of March 28, 1991 between the Company and The First National Bank of Boston, as Rights Agent, which includes as Exhibit A the form of Certificate of Designation of Series A Junior Participating Preferred Stock (Form 8-A, File No. 1-10477). (a) Amendment No. 1 to the Rights Agreement dated February 24, 1994 (Form 10-K for 1994). 4.4 Certificate of Designation for 6% Convertible Redeemable Preferred Stock (Form 10-K for 1994). 4.5 Amended and Restated Credit Agreement dated as of May 30, 1995 among the Company, Morgan Guaranty Trust Company, as agent and the banks named therein. (a) Amendment No. 1 to Credit Agreement dated September 15, 1995 (Form 10-K for 1995). (b) Amendment No. 2 to Credit Agreement dated December 24, 1996 (Form 10-K for 1996). 4.6 Note Purchase Agreement dated May 11, 1990 among the Company and certain insurance companies parties thereto (Form 10-Q for the quarter ended June 30, 1990). (a) First Amendment dated June 28, 1991 (Form 10-K for 1994). (b) Second Amendment dated July 6, 1994 (Form 10-K for 1994). 4.7 Note Purchase Agreement dated November 14, 1997 among the Company and the purchasers named therein. 10.1 Supplemental Executive Retirement Agreement between the Company and Charles P. Siess, Jr. (Form 10-K for 1995). 10.2 Form of Change in Control Agreement between the Company and Certain Officers (Form 10-K for 1995). 10.3 Letter Agreement dated January 11, 1990 between Morgan Guaranty Trust Company of New York and the Company (Registration Statement No. 33-32553). 10.4 Form of Annual Target Cash Incentive Plan of the Company (Registration Statement No. 33-32553). 10.5 Form of Incentive Stock Option Plan of the Company (Registration Statement No. 33-32553). (a) First Amendment to the Incentive Stock Option Plan (Post-Effective Amendment No. 1 to S-8 dated April 26, 1993). 10.6 Form of Stock Subscription Agreement between the Company and certain executive officers and directors of the Company (Registration Statement No. 33-32553). 57 59 10.7 Transaction Agreement between Cabot Corporation and the Company dated February 1, 1991 (Registration Statement No. 33-37455). 10.8 Tax Sharing Agreement between Cabot Corporation and the Company dated February 1, 1991 (Registration Statement No. 33-37455). 10.9 Amendment Agreement (amending the Transaction Agreement and the Tax Sharing Agreement) dated March 25, 1991. (incorp. by ref. from Cabot Corporation's Schedule 13E-4, Am. No. 6, File No. 5-30636). 10.10 Savings Investment Plan & Trust Agreement of the Company (Form 10-K for 1991). (a) First Amendment to the Savings Investment Plan dated May 21, 1993 (Form S-8 dated November 1, 1993). (b) Second Amendment to the Savings Investment Plan dated May 21, 1993 (Form S-8 dated November 1, 1993). (c) First through Fifth Amendments to the Trust Agreement (Form 10-K for 1995). (d) Third through Fifth Amendments to the Savings Investment Plan (Form 10-K for 1996). 10.11 Supplemental Executive Retirement Agreements of the Company (Form 10-K for 1991). 10.12 Settlement Agreement and Mutual Release (Tax Issues) between Cabot Corporation and the Company dated July 7, 1992 (Form 10-Q for the quarter ended June 30, 1992). 10.13 Agreement of Merger dated February 25, 1994 among Washington Energy Company, Washington Energy Resources Company, the Company and COG Acquisition Company (Form 10-K for 1993). 10.14 1990 Nonemployee Director Stock Option Plan of the Company (Form S-8 dated June 23, 1990) (a) First Amendment to 1990 Nonemployee Director Stock Option Plan (Post-Effective Amendment No. 2 to Form S-8 dated March 7, 1994). (b) Second Amendment to 1990 Nonemployee Director Stock Option Plan (Form 10-K for 1995). 10.15 1994 Long-Term Incentive Plan of the Company (Form S-8 dated May 20, 1994 - Registration Statement No. 33-53723). 10.16 1994 Nonemployee Director Stock Option Plan (Form S-8 dated May 20, 1994 - Registration Statement No. 33-53723). 10.17 Employment Agreement between the Company and Ray R. Seegmiller dated September 25, 1995 (Form 10-K for 1995). 10.18 Form of Indemnity Agreement between the Company and Certain Officers. 21.1 Subsidiaries of Cabot Oil & Gas Corporation. 23.1 Consent of Coopers & Lybrand L.L.P. 23.2 Consent of Miller and Lents, Ltd. 27 Financial Data Schedule. 28.1 Miller and Lents, Ltd. Review Letter dated February 9, 1998. B. REPORTS ON FORM 8-K None 58 60 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on the 10th of March 1998. CABOT OIL & GAS CORPORATION By: /s/ Charles P. Siess, Jr. --------------------------------- Charles P. Siess, Jr. Chairman of the Board and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated.
Signature Title Date --------- ----- ---- /s/ Charles P. Siess, Jr. Chairman of the Board and March 10, 1998 - -------------------------------- Chief Executive Officer Charles P. Siess, Jr (Principal Executive Officer) /s/ Ray R. Seegmiller President, Chief Operating March 10, 1998 - -------------------------------- Officer and Director Ray R. Seegmiller (Principal Financial Officer) /s/ Paul F. Boling Controller March 10, 1998 - -------------------------------- (Principal Accounting Officer) Paul F. Boling /s/ Robert F. Bailey Director March 10, 1998 - -------------------------------- Robert F. Bailey /s/ Samuel W. Bodman Director March 10, 1998 - -------------------------------- Samuel W. Bodman /s/ Henry O. Boswell Director March 10, 1998 - -------------------------------- Henry O. Boswell /s/ John G. L. Cabot Director March 10, 1998 - -------------------------------- John G. L. Cabot /s/ William R. Esler Director March 10, 1998 - -------------------------------- William R. Esler /s/ William H. Knoell Director March 10, 1998 - -------------------------------- William H. Knoell /s/ C. Wayne Nance Director March 10, 1998 - -------------------------------- C. Wayne Nance /s/ William P. Vititoe Director March 10, 1998 - -------------------------------- William P. Vititoe
59 61 EXHIBIT INDEX
Exhibit Number Description - -------- ----------- 3.1 Certificate of Incorporation of the Company (Registration Statement No. 33-32553). 3.2 Amended and Restated Bylaws of the Company adopted August 5, 1994. 4.1 Form of Certificate of Common Stock of the Company (Registration Statement No. 33-32553). 4.2 Certificate of Designation for Series A Junior Participating Preferred Stock (Form 10-K for 1994). 4.3 Rights Agreement dated as of March 28, 1991 between the Company and The First National Bank of Boston, as Rights Agent, which includes as Exhibit A the form of Certificate of Designation of Series A Junior Participating Preferred Stock (Form 8-A, File No. 1-10477). (a) Amendment No. 1 to the Rights Agreement dated February 24, 1994 (Form 10-K for 1994). 4.4 Certificate of Designation for 6% Convertible Redeemable Preferred Stock (Form 10-K for 1994). 4.5 Amended and Restated Credit Agreement dated as of May 30, 1995 among the Company, Morgan Guaranty Trust Company, as agent and the banks named therein. (a) Amendment No. 1 to Credit Agreement dated September 15, 1995 (Form 10-K for 1995). (b) Amendment No. 2 to Credit Agreement dated December 24, 1996 (Form 10-K for 1996). 4.6 Note Purchase Agreement dated May 11, 1990 among the Company and certain insurance companies parties thereto (Form 10-Q for the quarter ended June 30, 1990). (a) First Amendment dated June 28, 1991 (Form 10-K for 1994). (b) Second Amendment dated July 6, 1994 (Form 10-K for 1994). 4.7 Note Purchase Agreement dated November 14, 1997 amoung the Company and the purchasers named therein. 10.1 Supplemental Executive Retirement Agreement between the Company and Charles P. Siess, Jr. (Form 10-K for 1995). 10.2 Form of Change in Control Agreement between the Company and Certain Officers (Form 10-K for 1995). 10.3 Letter Agreement dated January 11, 1990 between Morgan Guaranty Trust Company of New York and the Company (Registration Statement No. 33-32553). 10.4 Form of Annual Target Cash Incentive Plan of the Company (Registration Statement No. 33-32553). 10.5 Form of Incentive Stock Option Plan of the Company (Registration Statement No. 33-32553). (a) First Amendment to the Incentive Stock Option Plan (Post-Effective Amendment No. 1 to S-8 dated April 26, 1993). 10.6 Form of Stock Subscription Agreement between the Company and certain executive officers and directors of the Company (Registration Statement No. 33-32553).
62 10.7 Transaction Agreement between Cabot Corporation and the Company dated February 1, 1991 (Registration Statement No. 33-37455). 10.8 Tax Sharing Agreement between Cabot Corporation and the Company dated February 1, 1991 (Registration Statement No. 33-37455). 10.9 Amendment Agreement (amending the Transaction Agreement and the Tax Sharing Agreement) dated March 25, 1991. (incorp. by ref. from Cabot Corporation's Schedule 13E-4, Am. No. 6, File No. 5-30636). 10.10 Savings Investment Plan & Trust Agreement of the Company (Form 10-K for 1991). (a) First Amendment to the Savings Investment Plan dated May 21, 1993 (Form S-8 dated November 1, 1993). (b) Second Amendment to the Savings Investment Plan dated May 21, 1993 (Form S-8 dated November 1, 1993). (c) First through Fifth Amendments to the Trust Agreement (Form 10-K for 1995). (d) Third through Fifth Amendments to the Savings Investment Plan (Form 10-K for 1996). 10.11 Supplemental Executive Retirement Agreements of the Company (Form 10-K for 1991). 10.12 Settlement Agreement and Mutual Release (Tax Issues) between Cabot Corporation and the Company dated July 7, 1992 (Form 10-Q for the quarter ended June 30, 1992). 10.13 Agreement of Merger dated February 25, 1994 among Washington Energy Company, Washington Energy Resources Company, the Company and COG Acquisition Company (Form 10-K for 1993). 10.14 1990 Nonemployee Director Stock Option Plan of the Company (Form S-8 dated June 23, 1990) (a) First Amendment to 1990 Nonemployee Director Stock Option Plan (Post-Effective Amendment No. 2 to Form S-8 dated March 7, 1994). (b) Second Amendment to 1990 Nonemployee Director Stock Option Plan (Form 10-K for 1995). 10.15 1994 Long-Term Incentive Plan of the Company (Form S-8 dated May 20, 1994 - Registration Statement No. 33-53723). 10.16 1994 Nonemployee Director Stock Option Plan (Form S-8 dated May 20, 1994 - Registration Statement No. 33-53723). 10.17 Employment Agreement between the Company and Ray R. Seegmiller dated September 25, 1995 (Form 10-K for 1995). 10.18 Form of Indemnity Agreement between the Company and Certain Officers. 21.1 Subsidiaries of Cabot Oil & Gas Corporation. 23.1 Consent of Coopers & Lybrand L.L.P. 23.2 Consent of Miller and Lents, Ltd. 27 Financial Data Schedule. 28.1 Miller and Lents, Ltd. Review Letter dated February 9, 1998.
EX-4.7 2 NOTE PURCHASE AGREEMENT, DATED 11/14/97 1 Exhibit 4.7 NOTE PURCHASE AGREEMENT dated as of November 14, 1997 among CABOT OIL & GAS CORPORATION and THE PURCHASERS LISTED HEREIN ------------------- $100,000,000 7.19% Notes due 2009 2 TABLE OF CONTENTS* ARTICLE I DEFINITIONS 1 SECTION 1.01. Definitions 1 SECTION 1.02. Accounting Terms and Definitions 8 ARTICLE II THE NOTES 8 SECTION 2.01. Sale and Purchase of Notes 8 SECTION 2.02. Closing 9 SECTION 2.03. Prepayments 9 SECTION 2.04. Maximum Interest Rate 11 ARTICLE III CONDITIONS TO PURCHASE OF NOTES 12 SECTION 3.01. Conditions to Purchase 12 ARTICLE IV REPRESENTATIONS AND WARRANTIES 13 SECTION 4.01. Corporate Existence and Power 13 SECTION 4.02. Corporate and Governmental Authorization; No Contravention 13 SECTION 4.03. Binding Effect 14 SECTION 4.04. Financial Information 14 SECTION 4.05. Full Disclosure 14 SECTION 4.06. Litigation 15 SECTION 4.07. Compliance with ERISA 15 SECTION 4.08. Environmental Matters 15 SECTION 4.09. Taxes 16 SECTION 4.10. Titles, etc 16 SECTION 4.11. Casualties; Taking of Properties 16 SECTION 4.12. Gas Imbalances 16 SECTION 4.13. Use of Proceeds 17 SECTION 4.14. Offering of the Notes 17 SECTION 4.15. Ownership of Subsidiaries 17 ARTICLE V COVENANTS 17 SECTION 5.01. Information 17 SECTION 5.02. Payment of Obligations 19 SECTION 5.03. Maintenance of Property 19 SECTION 5.04. Conduct of Business and Maintenance of Existence 19 SECTION 5.05. Compliance with Laws 20 SECTION 5.06. Inspection of Property, Books and Records 20 SECTION 5.07. Insurance 20 SECTION 5.08. Engineering Reports 20
- ---------------------- * The Table of Contents is not a part of this Agreement. 3 SECTION 5.09. Asset Coverage Ratio 20 SECTION 5.10. Liens 21 SECTION 5.11. Transactions with Affiliates 21 SECTION 5.12. Annual Coverage Ratio 22 SECTION 5.13. Consolidations, Mergers and Sales of Assets 22 SECTION 5.14. Subsidiary Debt 23 SECTION 5.15. Sale and Leasebacks 23 ARTICLE VI DEFAULTS 23 SECTION 6.01. Events of Default 23 SECTION 6.02. Rescission of Acceleration 26 ARTICLE VII PURCHASE FOR INVESTMENT; SOURCE OF FUNDS 26 SECTION 7.01. Purchase for Investment 26 SECTION 7.02. Source of Funds 26 SECTION 7.03. Securities Act; Legend 28 ARTICLE VIII MISCELLANEOUS SECTION 8.01. Notices 28 SECTION 8.02. No Waiver 28 SECTION 8.03. Expenses; Documentary Taxes; Indemnification for Litigation 29 SECTION 8.04. Amendments and Waivers 29 SECTION 8.05. New York Law 30 SECTION 8.06. Successors and Assigns 30 SECTION 8.07. Form, Registration, Transfer and Exchange of the Notes; Transferees 30 SECTION 8.08. Persons Deemed Owners 31 SECTION 8.09. Home Office Payment 31 SECTION 8.10. Substitution 31 SECTION 8.11. Credit Decision 32 SECTION 8.12. Counterparts; Integration; Effectiveness; Severability 32 SECTION 8.13. Submission to Jurisdiction 32 SECTION 8.14. Confidentiality 32
Schedule A -- Information Relating To Purchasers Schedule 4.05 -- Certain Disclosure Schedule 4.06 -- Litigation Schedule 4.15 -- Subsidiaries Schedule 5.10 -- Liens Exhibit A -- Form of Note Exhibit B -- Form of Opinion of Counsel for the Issuer Exhibit C -- Form of Opinion of Managing Counsel for the Issuer Exhibit D -- Form of Opinion of Special Counsel for the Purchasers 4 NOTE PURCHASE AGREEMENT AGREEMENT dated as of November 14, 1997 among CABOT OIL & GAS CORPORATION, a Delaware corporation (the "Issuer"), and the PURCHASERS listed on the signature pages hereof (the "Purchasers"). The parties hereto agree as follows: ARTICLE I DEFINITIONS SECTION 1.01. Definitions. The following terms, as used herein, have the following meanings: "Adjusted Cash" means, as of any date, the lesser of (i) the amount by which cash and short-term investments of the Issuer and its Subsidiaries exceed $5,000,000 and (ii) the amount, if any, by which (a) current assets of the Issuer and its Subsidiaries exceed (b) current liabilities of such Persons (excluding the aggregate outstanding principal amount of Debt included in such current liabilities), in each case determined on a consolidated basis as of such date. If such current liabilities exceed such current assets, Adjusted Cash shall be zero. "Affiliate" means each Person who controls, is controlled by or is under common control with the Issuer. For purposes of this definition, the term "control" means possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of a Person, whether through the ownership of voting securities, by contract or otherwise. "Asset Disposition" means any sale, lease, transfer or other disposition of shares of capital stock of a Subsidiary, property or other assets by the Issuer or a Subsidiary, other than any such sales, leases, transfers or other dispositions of assets made in the ordinary course of business. "Attributable Debt" means, as to any particular lease and at any date, the total net amount of rent required to be paid by such Person under such lease during the remaining primary term thereof (or any renewal terms for which the lease may be extended at the option of the lessor), discounted from the respective due dates thereof to such date at a rate of 7.19% per annum. The net amount of rent required to be paid under any such lease for any such period shall be the aggregate amount of rent payable by the lessee with respect to such period after excluding amounts required to be paid on account of insurance, taxes, assessments, utility, operating and labor costs and similar charges. In the case of any lease which is terminable by the lessee upon the payment of a penalty, such net amount shall also include the amount of such penalty, but no rent shall be considered as required to be paid under such lease subsequent to the first date upon which it may be so terminated. "Business Day" means any day except a Saturday, Sunday or other day on which commercial banks in Houston, Texas are authorized by law to close. "Change of Control" shall have occurred if (i) any Person or related Persons constituting a "group" for purposes of Section 13(d) of the Exchange Act shall have acquired "beneficial ownership" of a majority of the voting stock of the Issuer, or (ii) during any period of 24 consecutive months, individuals who were directors of the Issuer at the beginning of the period and Qualifying Directors, in the aggregate, shall cease to constitute a majority of the Board of Directors of the Issuer. 5 "Closing Date" means November 18, 1997. "Credit Agreement" means the Amended and Restated Credit Agreement dated May 30, 1995 among the Issuer, the banks party thereto, and Morgan Guaranty Trust Company of New York, as Agent, as amended from time to time. "Debt" of any Person means at any date, without duplication, (i) all obligations of such Person for borrowed money; (ii) all obligations of such Person evidenced by bonds, debentures, notes or other similar instruments; (iii) all long-term obligations of such Person to pay the deferred purchase price of property or services, except trade accounts payable arising in the ordinary course of business; (iv) all obligations of such Person as lessee under capital leases; (v) all Debt of others secured by a Lien on any asset of such Person, whether or not such Debt is assumed by such Person, provided that to the extent such Debt is not assumed by such Person the amount of such Debt for purposes of the provisions of this Agreement shall be equal to the lesser of (a) the amount of Debt secured by such Lien or (b) the value of the asset which secures such Debt and to the extent such Debt is assumed by such Person the amount of such Debt for purposes of the provisions of this Agreement shall equal the amount of such Debt assumed; and (vi) all Debt of others described in (i) through (v) above directly or indirectly guaranteed by such Person or in respect of which such Person is otherwise liable, contingently or otherwise; provided, that the amount of such Debt for the purposes of this Agreement shall be equal to the amount of Debt guaranteed by such Person or in respect of which such Person is otherwise liable, contingently or otherwise. "Debt and Other Liabilities" means, at any date, the sum of, without duplication, (i) Debt of the Issuer and its Subsidiaries at such date plus (ii) the amount, if any, by which Negative Adjusted Working Capital at such date exceeds 6% of the Present Value of Proved Reserves minus (iii) Non-Recourse Debt of the Issuer and its Subsidiaries at such date. "Default" means the occurrence of any of the events specified in Section 6.01, whether or not any requirement for notice or lapse of time or other condition precedent has been satisfied. "Environmental Laws" means any and all federal, state, local and foreign statutes, laws, regulations, ordinances, rules, judgments, orders, decrees, permits, concessions, grants, franchises, licenses, agreements or other governmental restrictions relating to the environment or to emissions, discharges or releases of pollutants contaminants, petroleum or petroleum products, chemicals or industrial, toxic or hazardous substances or wastes into the environment including, without limitation, ambient air, surface water, ground water, or land, or otherwise relating to the manufacture, processing, distribution, use, treatment, storage, disposal, transport or handling of pollutants, contaminants, petroleum or petroleum products (including natural gas), chemicals or industrial, toxic or hazardous substances or wastes or the clean-up or other remediation thereof. "ERISA" means the Employee Retirement Income Security Act of 1974, as amended, or any successor statute. "ERISA Group" means the Issuer and all members of a controlled group of corporations and all trades or businesses (whether or not incorporated) under common control which, together with the Issuer, are treated as a single employer under Section 414 of the Internal Revenue Code. "Event of Default" means any of the events specified in Section 6.01. 6 "Excepted Liens" means: (i) Liens for taxes, assessments or other governmental charges or levies not yet due or which are being contested in good faith by appropriate action; (ii) Liens in connection with workers' compensation, unemployment insurance or other social security, old age pension or public liability obligations but not resulting from the failure of the Issuer to meet or comply with such obligations; (iii) attachment or judgment Liens arising in connection with legal proceedings, provided that (A) the execution or enforcement of such Lien is effectively stayed and the claims secured thereby are being actively contested in good faith by appropriate proceedings and (B) such reserve or other appropriate provision, if any, as shall be required by generally accepted accounting principles shall have been made therefor on the books of the Issuer and its Subsidiaries; (iv) vendors', carriers', warehousemen's, repairmen's, mechanics', workmen's, materialmen's, construction or other like Liens (including, without limitation, Liens arising in favor of sellers of hydrocarbons) arising by operation of law in the ordinary course of business incident to obligations which are not yet due or which are being contested in good faith by appropriate proceedings by or on behalf of the Issuer or a Subsidiary and for which appropriate provisions, if any, as required by generally accepted accounting principles shall have been made on the books of the Issuer and its Subsidiaries; (v) Liens arising in the ordinary course of business under farm-out agreements, gas sales contracts, operating agreements, unitization and pooling agreements, and such other documents as are customarily found in connection with comparable drilling and producing operations; (vi) letters of credit, pledges or deposits, including bonds, required in the ordinary course of business to secure public or statutory obligations or to secure performance in connection with bids or contracts related to the exploration or development of Petroleum Properties, to the extent that payment of the underlying obligations is not yet due or is being contested in good faith by appropriate proceedings by or on behalf of the Issuer or a Subsidiary and with respect to which appropriate reserves have been established; and (vii) minor irregularities in title which do not materially interfere with the occupation, use and enjoyment by the Issuer and its Subsidiaries of their respective Properties in the normal course of business as presently conducted or materially impair the value thereof for such business. "Exchange Act" means the Securities Exchange Act of 1934, as amended, or any successor statute. For purposes of the definitions of "Change of Control" and "Qualifying Director", unless otherwise defined in such Sections, the terms enclosed in quotation marks as used therein have the meanings ascribed to such terms under the Exchange Act and the rules and regulations promulgated by the Securities and Exchange Commission thereunder. "Executive Officer" means, with respect to any Person, the chairman and chief executive officer, the president, any vice president, the treasurer, the chief financial officer, the chief accounting officer, the controller or the general counsel or any other person performing similar functions. "Holder" means a registered holder from time to time of any Note. "Institutional Investor" means (a) any original purchaser of a Note, (b) any holder of a Note holding more than 5% of the aggregate principal amount of the Notes then outstanding, and (c) any bank, trust company, savings and loan association or other financial institution, any pension plan, any investment company, any insurance company, any broker or dealer, or any other similar financial institution or entity, regardless of legal form. "Internal Revenue Code" means the Internal Revenue Code of 1986, as amended, or any successor statute. 7 "Investment" means with respect to any Person (the "Investor"), any investment by the Investor in any other Person, whether by means of share purchase, capital contribution, loan, purchase of Debt, guarantee of Debt, time deposit or otherwise. "Issuer" means Cabot Oil & Gas Corporation, a Delaware corporation, and its successors. "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, gas imbalances or similar arrangement with respect to minerals in place) or any other arrangement the economic effect of which is to give a creditor preferential access to such asset to satisfy its claim, whether or not filed, recorded or otherwise perfected under applicable law. For the purposes of this Agreement, the Issuer or any Subsidiary shall be deemed to own subject to a Lien (i) any asset that it has acquired or holds subject to the interest of a vendor or lessor under any conditional sale agreement, capital lease or other title retention agreement relating to such asset or any capitalized lease obligation or (ii) any account receivable transferred by it with credit recourse (including any such transfer subject to a holdback or similar arrangement which effectively imposes the risk of collectibility upon the transferor). "Majority Lenders" means Holders of a majority in principal amount of the Outstanding Notes. "Make Whole Amount" has the meaning set forth in Section 2.03 and, as used in Section 6.01 with respect to the acceleration of any Note, means an amount equal to the Make Whole Amount that would be payable with respect to such Note if the Issuer had elected to prepay the Notes in full pursuant to Section 2.03(b) on the date of the applicable acceleration.. "Material Debt" means Debt (other than Non-Recourse Debt) of the Issuer or one or more of its Subsidiaries, arising in one or more related or unrelated transactions, in an aggregate principal amount exceeding $15,000,000. "Material Plan" means at any time a Plan or Plans having aggregate Unfunded Liabilities in excess of $5,000,000. "Multiemployer Plan" means at any time an employee pension benefit plan within the meaning of Section 4001(a)(3) of ERISA to which any member of the ERISA Group is then making or accruing an obligation to make contributions or has within the preceding five plan years made contributions, including for these purposes any Person which ceased to be a member of the ERISA Group during such five year period. "Negative Adjusted Working Capital" means, at any date, the amount, if any, by which current liabilities other than Debt of the Issuer and its Subsidiaries exceeds current assets of such Persons, determined on a consolidated basis as of such date. "Non-Recourse Debt" of any Person means Debt of such Person in respect of which (i) the recourse of the holder of such Debt, whether direct or indirect and whether contingent or otherwise, is effectively limited to the assets directly securing such Debt; (ii) such holder may not collect by levy of execution against assets of such Person generally (other than the assets directly securing such Debt) if such Person fails to pay such Debt when due and the holder obtains a judgment with respect thereto; and (iii) such holder has waived, to the extent such holder may effectively do so, such holder's right to elect recourse treatment under 11 U.S.C. S 1111(b). 8 "Notes" means the promissory notes of the Issuer, substantially in the form of Exhibit A hereto, in an original aggregate principal amount equal to $100,000,000, evidencing the obligations of the Issuer hereunder and "Note" means any one of such promissory notes issued hereunder. "Offering Memorandum" means the Private Placement Memorandum dated October 1997 provided by the Issuer to the Purchasers in connection with this Agreement, together with all amendments, supplements, exhibits and schedules thereto delivered to the Purchasers prior to the execution of this Agreement. "Outstanding" means, with respect to the Notes, all Notes issued pursuant to this Agreement except (i) Notes delivered to the Issuer in substitution or exchange for which new Notes have been issued, (ii) Notes delivered to the Issuer for payment upon maturity, prepayment or repurchase and (iii) Notes held by the Issuer or any of its Affiliates. "PBGC" means the Pension Benefit Guaranty Corporation or any entity succeeding to any or all of its functions under ERISA. "Person" means an individual, a corporation, a partnership, an association, a trust or any other entity or organization, including a government or political subdivision or an agency or instrumentality thereof. "Petroleum Property" means any interest of the Issuer or any Subsidiary in oil and gas reserves and assets consisting primarily of gas gathering, processing and storage facilities and transmission pipelines. "Plan" means at any time an employee pension benefit plan (other than a Multiemployer Plan) which is covered by Title IV of ERISA or subject to the minimum funding standards under Section 412 of the Internal Revenue Code and either (i) is maintained, or contributed to, by any member of the ERISA Group for employees of any member of the ERISA Group or (ii) has at any time within the preceding five years been maintained, or contributed to, by any Person which was at such time a member of the ERISA Group for employees of any Person which was at such time a member of the ERISA Group. "Present Value of Proved Reserves" means at any time the standardized measure of discounted after-tax future net cash flows, calculated in accordance with the methods prescribed at such time by Item 302(b) of Regulation S-K or any successor provision promulgated by the Securities and Exchange Commission (or if no such methods shall then be prescribed, then on a basis consistent with those most recently so prescribed), of the Issuer's and its Subsidiaries' Proved Reserves, excluding reserves subject to any Non-Recourse Debt. In calculating the Present Value of Proved Reserves, Proved Undeveloped Reserves shall not be taken into account to the extent that more than 30% of the Present Value of Proved Reserves is attributable to Proved Undeveloped Reserves. "Prime Rate" means the rate of interest publicly announced by Morgan Guaranty Trust Company of New York from time to time as its Prime Rate. "Production Payment" means an interest in a Petroleum Property that (i) is not subject to the costs of production and (ii) terminates at such time as the interest holder has realized a specified sum from the sale of oil or gas attributable to such interest. 9 "Property" means any interest in any kind of property or asset, whether real, personal or mixed, or tangible or intangible. "Proved Developed Producing Reserves" has the meaning assigned to that term by the Society of Petroleum Engineers, as it may be amended from time to time, but generally shall mean the subcategory of "Proved Developed Reserves" (as defined by the Society of Petroleum Engineers) which are recoverable by natural reservoir energies (including pumping) from the completion intervals currently open and producing to market. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery will be included as "Proved Developed Producing Reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response through existing completions producing to market that increased recovery will be achieved. Proved Developed Producing Reserves shall not include any Proved Developed Non-Producing Reserves. "Proved Developed Non-Producing Reserves" has the meaning assigned to that term by the Society of Petroleum Engineers, as it may be amended from time to time, but generally shall mean the subcategory of "Proved Developed Reserves" (as defined by the Society of Petroleum Engineers) which will become "Proved Developed Producing Reserves" upon minor capital expenditures being made with respect to existing wells which will cause formerly non-producing completions or intervals to become open and producing to market. "Proved Reserves" means and includes Proved Developed Producing Reserves, Proved Developed Non-Producing Reserves and Proved Undeveloped Reserves. "Proved Undeveloped Reserves" has the meaning assigned to that term by the Society of Petroleum Engineers, as it may be amended from time to time, but generally shall mean those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Proved Undeveloped Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved Undeveloped Reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for Proved Undeveloped Reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir. "QPAM Exemption" means Prohibited Transaction Class Exemption 84-14 issued by the United States Department of Labor. "Qualifying Director" means any director who (a) is elected by a majority of the members of the board of directors of the Issuer who were directors immediately prior to the event that caused the change in directorships and (b) is not a "person" or member of a "group" of persons, or an "affiliate" or "associate" of any "person" or "group" member, or an "associate" of an "affiliate" of any such "person" or "group" member, which "person" or "group" of persons, together with all of their respective "affiliates" and "associates" and all "associates" of their respective "affiliates" (other than a "person" or "group" of persons or an "affiliate" or "associate" of such "person" or "group" of persons or an "associate" of such "affiliate" in each case which is affiliated with the Issuer or any Subsidiary) comprise a majority of the board of directors of the Issuer. 10 "Required Lenders" means Holders of at least 66 2/3% in principal amount of the Outstanding Notes. "Reserve Report" means the Reserve Summary contained in the Offering Memorandum and, subsequently, a report delivered by the Issuer pursuant to Section 5.08(a). "Subsidiary" means any corporation or other entity of which securities or other ownership interests having ordinary voting power to elect a majority of the board of directors or other persons performing similar functions are at the time directly or indirectly owned by the Issuer. "Unfunded Liabilities" means, with respect to any Plan at any time, the amount (if any) by which (i) the present value of all benefits under such Plan exceeds (ii) the fair market value of all Plan assets allocable to such benefits (excluding any accrued but unpaid contributions), all determined as of the then most recent valuation date for such Plan, but only to the extent that such excess represents a potential liability of the Issuer or any Subsidiary (whether direct or joint and several with one or more affiliates) to the PBGC or any other Person under Title IV of ERISA. "Wholly-Owned Subsidiary" means any Subsidiary all of the shares of capital stock or other ownership interests of which (except directors' qualifying shares) are at the time directly or indirectly owned by the Issuer. SECTION 1.02. Accounting Terms and Definitions. Unless otherwise specified herein, all accounting terms used in this Agreement shall be interpreted, all accounting determinations hereunder shall be made and all financial statements required to be delivered hereunder shall be prepared in accordance with generally accepted accounting principles as in effect from time to time, applied on a basis consistent (except for changes concurred by the Issuer's independent public accountants) with the most recent audited consolidated financial statements of the Issuer delivered to the Holders. ARTICLE II THE NOTES SECTION 2.01. Sale and Purchase of Notes. The Issuer agrees to issue and sell to each Purchaser, and subject to the terms and conditions of this Agreement, each Purchaser, severally and not jointly, agrees to purchase from the Issuer, at the Closing provided for in Section 2.02, Notes in the principal amounts specified opposite such Purchaser's name on Schedule A attached hereto. The purchase price of the Notes to be purchased by each Purchaser shall be 100% of the principal amount thereof. The Notes to be purchased by each Purchaser will be dated the date of issue thereof, will mature on the date set forth therein and will bear interest on the unpaid balance thereof from the date of issue until the principal thereof shall become due and payable, at the rate of 7.19% per annum. Interest on the Notes shall be computed on the basis of a year of 360 days, consisting of 12 30-day months, and accrued and unpaid interest on the unpaid balance thereof shall be payable semi-annually on May 15 and November 15 of each year, commencing May 15, 1998, and at maturity. Any overdue principal of, prepayment charge on, and, to the extent permitted by law, overdue interest on any Note shall bear interest, payable on demand, for each day from and including the date payment thereof is due to but excluding the date of actual payment, at a rate per annum equal to the higher of (i) 9.19% and (ii) the Prime Rate for such day plus 2%. Whenever any payment of principal of, or interest on, a Note shall be due on a day which is not a Business Day, the date for payment thereof shall be extended to the next succeeding Business Day. If the date for any payment of principal is extended by operation of law or otherwise, interest thereon will be payable for such extended time. The Notes will be in registered form substantially in the form of Exhibit A attached hereto. 11 SECTION 2.02. CLOSING. The sale and purchase of the Notes shall take place- at the offices of Milbank, Tweed, Hadley & McCloy, 1 Chase Manhattan Plaza, New York, New York 10005, at 10:00 a.m., New York City time, on November 18, 1997 or at such other time on such day as may be agreed upon by the Issuer and the Purchasers (the "Closing"). At the Closing, the Issuer will deliver to each Purchaser the Note or Notes to be purchased by such Purchaser, dated the date of the Closing and registered in such Purchaser's name (or in the name of such Purchaser's nominee), against delivery by such Purchaser to the Issuer or its order of immediately available funds in the amount of the purchase price thereof. If at the Closing the Issuer shall fail to tender such Note or Notes to such Purchaser as provided above, or any of the conditions specified in Article III shall not have been satisfied or waived, such Purchaser shall, at its election, be relieved of all further obligations under this Agreement, without thereby waiving any other rights such Purchaser may have by reason of such failure or such nonfulfillment. SECTION 2.03. Prepayments. (a) Subject to the provisions of Section 2.03(e), the Issuer shall pay $20,000,000 of the outstanding principal amount of the Notes on November 15 of each of the years 2005 through 2008, inclusive, and shall pay the remaining outstanding principal amount of the Notes together with all accrued but unpaid interest thereon, and the Notes shall finally mature, on November 15, 2009. (b) On any date (but in any event not more than four times in any fiscal year), the Issuer may prepay all or any portion of the Notes, provided that, simultaneously with any such prepayment, the Issuer shall pay accrued but unpaid interest and a prepayment charge with respect to Notes being prepaid equal to the amount (the "Make Whole Amount") not less than zero that is the excess of: (1) the sum of the Present Values of (i) the aggregate principal amount of the Notes being prepaid (assuming the principal balance of such Notes payable upon maturity and the required prepayments pursuant to Section 2.03(a) are paid when due, without regard to the prepayment in respect of which the Make Whole Amount is being calculated) and (ii) the amount of interest which would have been payable on the principal amount of such Notes (assuming the principal balance of such Notes payable upon maturity, the required prepayments pursuant to Section 2.03(a) and interest payments pursuant to the terms of such Notes are paid when due); over (2) the aggregate principal amount of the Notes being prepaid. For purposes of the definition of Make Whole Amount, "Present Value" shall be computed in accordance with generally accepted accounting principles on a semiannual basis at a discount rate equal to the sum of the Treasury Yield plus 0.50%; and the "Treasury Yield" shall be the yield to maturity implied by (i) the yields reported, as of 10:00 A.M. (New York City time) on the second Business Day prior to the date fixed for prepayment, on the display designated as Bloomberg Financial Markets "Page USD" (or such other display as may replace Bloomberg Financial Markets "Page USD") for actively traded United States Treasury securities adjusted to a constant maturity equal to the then remaining weighted average life of the Notes being prepaid (the "Remaining Life"), or (ii) if such yields are not reported as of such time or the yields reported as of such time are not ascertainable, the Treasury Constant Maturity Series Yields reported, for the latest day for which such yields have been so reported as of the second Business Day prior to the date fixed for prepayment in Federal Reserve Statistical Release H.15 (519) (or any comparable successor publication) for actively traded United States Treasury securities adjusted to a constant maturity equal to the Remaining Life; provided that if the Remaining Life of the Notes is not equal to the constant maturity of a United States Treasury 12 security for which a weekly average yield is given, the Treasury Yield shall be obtained by linear interpolation (calculated to the nearest one-twelfth of a year) from the most recent weekly average yield of United States Treasury securities for which such yields are given having a maturity as close as possible to the Remaining Life. Prepayments of Notes in accordance with this subsection (b) shall be made in minimum amounts of $5,000,000 principal amount of Notes and increments of $1,000,000. (c) The Issuer shall give each Holder at least 20 Business Days'(but not more than 60 days') notice of any anticipated prepayment of Notes pursuant to paragraph (b) of this Section 2.03, which notice shall set forth the date of the prepayment and the anticipated amount of the prepayment applicable to such Holder's Notes. Any such notice given by the Issuer hereunder shall be irrevocable. The Issuer shall, at least one Business Day prior to the date of the prepayment, give immediate notice to each Holder of the Make Whole Amount applicable to such prepayment, showing the components of the calculation thereof. (d) In the event of a Change of Control, the Issuer shall prepay the aggregate principal amount of the Notes of any Holder electing prepayment, together with accrued and unpaid interest thereon and the Make Whole Amount with respect thereto. The Issuer shall give notice (the "Change of Control Notice") to each Holder of a Change of Control within 5 Business Days of knowledge of such event. The Change of Control Notice shall include a statement of the date of occurrence of such Change of Control and a description of the facts known to the Issuer underlying such Change of Control and shall state that the Issuer is obligated, pursuant to this Section 2.03(d), to purchase Notes in respect of which a Holder shall elect prepayment. Each Holder electing prepayment shall notify the Issuer in writing of its election of prepayment (the "Election Notice") within 30-days of the date of the Change of Control Notice. The Issuer shall promptly upon receipt of an Election Notice from any Holder forward a copy of such Election Notice to all other Holders. In the event that a Change of Control occurs but no Change of Control Notice is given by the Issuer, a Holder may deliver a notice to the Issuer (a "Purchase Notice") stating that it is electing to exercise its right to require the Issuer to purchase its Notes. The Issuer shall forthwith upon receipt of any Purchase Notice give notice of the receipt of such Purchase Notice (and enclose a copy of such Purchase Notice) to all other Holders, stating that other Holders may give a similar notice to the Issuer within 30 days of the date of transmission of the copy of such Purchase Notice by the Issuer. Prepayments required to be made by this paragraph (d) shall be made on a date specified by the Issuer by at least 5 Business Days notice to the Holders electing prepayment, which date shall be no later than 15 days after the earlier of (i) the last day for submission of the Election Notice or Purchase Notice by any Holder and (ii) the date of receipt by the Issuer of an Election Notice or Purchase Notice from a Holder such that all Holders of Outstanding Notes have delivered such Notice to the Issuer. (e) The Issuer will not make any payment of any Note under this Section 2.03 unless a simultaneous payment is made to all Holders (or in the case of prepayment under subsection (d) to all Holders electing prepayment) so as to reduce ratably the obligation of the Issuer under each of the Outstanding Notes (or, in the case of prepayment under subsection (d), under each of the Outstanding Notes as to which the Holder has elected prepayment). The amount of each payment required by subsection (a) shall be reduced ratably by the aggregate principal amount of Notes prepaid in accordance with subsection (b) or (d). (f) The Issuer will not, and will not permit any of its Affiliates to, acquire directly or indirectly by purchase or prepayment or otherwise any of the Outstanding Notes except by way of payment or prepayment in accordance with the provisions of the Notes and of this 13 Agreement. Notes paid or prepaid in full in accordance with this Section 2.03 shall not be deemed Outstanding for any purpose under this Agreement. SECTION 2.04. Maximum Interest Rate. The Issuer, the Purchasers and all other Holders of the Notes specifically intend and agree to limit contractually the amount of interest, and all amounts which shall be deemed to constitute interest under applicable law, payable under this Agreement, the Notes and all other instruments and agreements related hereto and thereto to the maximum amount of interest lawfully permitted to be charged under applicable law. Therefore, none of the terms of this Agreement, the Notes or any instrument pertaining to or relating to this Agreement or the Notes shall ever be construed to create a contract to pay interest at a rate in excess of the maximum rate permitted to be charged under applicable law, and neither the Issuer nor any other party liable or to become liable hereunder, under the Notes or under any other instruments and agreements related hereto and thereto shall ever be liable for interest in excess of the amount determined at such maximum rate, and the provisions of this Section 2.04 shall control over all other provisions of this Agreement, the Notes, or any other instrument pertaining to or relating to the transactions herein contemplated. If any amount of interest taken or received by any Holder of a Note shall be in excess of said maximum amount of interest which, under applicable law, could lawfully have been collected by such Holder incident to such transactions, then such excess shall be deemed to have been the result of a mathematical error by all parties hereto and the amount of interest which would otherwise be payable hereunder or under the Notes shall be automatically reduced to the amount allowed under applicable law, and such excess shall be credited ratably against and to the extent of the unpaid principal amount of the Note or Notes held by such Holder, with the excess, if any, being refunded to the Issuer. All amounts paid or agreed to be paid in connection with such transactions which would under applicable law be deemed "interest" shall, to the extent permitted by such applicable law, be amortized, prorated, allocated and spread throughout the full stated term of this Agreement. "Maximum rate" as used in this paragraph means, with respect to each of the Notes, the maximum lawful, nonusurious rates of interest which under applicable law may be charged to the Issuer from time to time with respect to such Notes. ARTICLE III CONDITIONS TO PURCHASE OF NOTES SECTION 3.01. Conditions to Purchase. The obligation of each Purchaser to purchase a Note or Notes at the Closing is subject to the satisfaction of such of the following conditions as shall not have been expressly waived by such Purchaser: (a) the fact that, immediately before and after such purchase, no Default shall have occurred and be continuing; (b) the fact that the representations and warranties of the Issuer contained in this Agreement shall be true and correct on and as of the date of such purchase and before and after giving effect to the issuance and purchase of the Notes; (c) receipt by such Purchaser of a Note duly executed on behalf of the Issuer and dated the date of such purchase, substantially in the form of Exhibit A hereto; (d) receipt by such Purchaser of an opinion of Baker & Botts, counsel for the Issuer, substantially in the form of Exhibit B hereto; 14 (e) receipt by such Purchaser of an opinion of Lisa A. Machesney, Managing Counsel for the Issuer, substantially in the form Of Exhibit C hereto; (f) receipt by such Purchaser of an opinion of Milbank, Tweed, Hadley & McCloy, special counsel for the Purchasers, substantially in the form of Exhibit D hereto; (g) receipt by such Purchaser of a certificate signed by the chief financial officer or the treasurer of the Issuer, to the effect set forth in clauses (a) and (b) of Section 3.01; (h) on the Closing Date, the purchase of Notes by such Purchaser shall (i) be permitted by the laws and regulations of each jurisdiction to which such Purchaser is subject, without recourse to provisions (such as Section 1405(a)(8) of the New York Insurance Law) permitting limited investments by insurance companies without restriction as to the character of the particular investment, (ii) not violate any applicable law or regulation (including, without limitation, Regulation G, T or X of the Board of Governors of the Federal Reserve System) and (iii) not subject such Purchaser to any tax, penalty or liability under or pursuant to any applicable law or regulation, which law or regulation was not in effect on the date hereof; and, if requested by any Purchaser, such Purchaser shall have received a certificate of the chief financial officer, principal accounting officer, treasurer or comptroller of the Issuer or of any other officer of the Issuer whose responsibilities extend to the subject matter of such certificate, certifying as to such matters of fact (but in no event as to a legal conclusion with respect thereto) as such Purchaser may reasonably specify in a form to be provided by such Purchaser, to enable such Purchaser to determine whether such purchase is so permitted; (i) without limiting the provisions of Section 8.03, the Issuer shall have paid on or before the Closing Date the fees, charges and disbursements of special counsel for the Purchasers referred to in paragraph (f) above to the extent reflected in a statement of such counsel rendered to the Issuer at least one Business Day prior to the Closing Date; (j) evidence satisfactory to such Purchaser of the receipt of a Private Placement Number for the Notes from the CUSIP Bureau of Standard & Poor's; (k) the fact that the Issuer shall have issued and sold $100,000,000 in aggregate principal amount of Notes hereunder (taking into account the Notes to be purchased by such Purchaser); and (l) receipt by such Purchaser of all documents it or its special counsel may reasonably request relating to the existence of the Issuer, the corporate authority for and the validity of the Notes and this Agreement, and any other matters relevant hereto, all in form and substance satisfactory to special counsel for the Purchasers. The documents and opinions referred to in this Article III shall be delivered to each Purchaser no later than the Closing Date. The certificate and opinions referred to above shall be dated the Closing Date. 15 ARTICLE IV REPRESENTATIONS AND WARRANTIES The Issuer represents and warrants to each Purchaser that: SECTION 4.01. Corporate Existence and Power. The Issuer and each Subsidiary is a corporation duly incorporated, validly existing and in good standing under the laws of its jurisdiction of incorporation, and has all corporate powers and all governmental licenses, authorizations, consents and approvals required to own its assets and to carry on its business as now conducted and is duly qualified as a foreign corporation in good standing in each jurisdiction where the nature of its business or the ownership or leasing of its Properties requires such qualification, except where the failure to qualify would not materially and adversely affect the conduct of its business or the enforceability of contractual obligations of the Issuer. Neither the Issuer nor any Affiliate is subject to regulation under the Public Utility Holding Company Act of 1935, the Investment Company Act of 1940, the Transportation Act (49 U.S.C.), as amended, the Federal Power Act, as amended, or any other law or regulation the application of which limits the incurrence by the Issuer of Debt hereunder, including, but not limited to, laws relating to common or contract carriers or the sale of electricity, gas, steam, water or other public utility services. SECTION 4.02. Corporate and Governmental Authorization; No Contravention. The execution, delivery and performance by the Issuer of this Agreement and the Notes are within the Issuer's corporate powers, have been duly authorized by all necessary corporate action, require no action by or in respect of, or filing with, any governmental body, agency or official and do not contravene, or constitute a default under, any provision of applicable law or regulation or of the certificate of incorporation or bylaws of the Issuer or of any agreement or instrument evidencing or governing Debt of the Issuer or any Affiliate or any other agreement, instrument, judgment, injunction, order or decree binding upon the Issuer or any Subsidiary or result in the creation or imposition of any Lien on any asset of the Issuer pursuant to any such agreement, instrument, judgment, injunction, order or decree. SECTION 4.03. Binding Effect. The Notes and this Agreement constitute legal, valid and binding obligations of the Issuer enforceable in accordance with their terms, except as the enforceability thereof may be limited by (i) bankruptcy, insolvency or similar laws affecting creditors' rights generally and (ii) equitable principles of general applicability. SECTION 4.04. Financial Information (a) Audited Financial Statements. The consolidated balance sheets of the Issuer and its Subsidiaries as of the fiscal years ended December 31, 1994 to 1996 and the related consolidated statements of operations, cash flows and stockholders' equity for the fiscal years then ended, reported on by Coopers & Lybrand and set forth in the Offering Memorandum, a copy of which has been delivered to each of the Purchasers, fairly present, in conformity with generally accepted accounting principles, the consolidated financial position of the Issuer and its Subsidiaries as of such dates and their consolidated results of operations and cash flows for such fiscal years. (b) Reserve Data. There are no statements or conclusions in the reserve report included in the Offering Memorandum provided to Purchasers regarding reserves which are based upon or include misleading information or fail to take into account material information known to the Issuer regarding the matters reported therein, it being understood that such statements and conclusions are necessarily based upon professional opinions, estimates and forecasts, and the Issuer 16 does not warrant that such opinions, estimates and forecasts will ultimately prove to have been accurate. Such reserve data has, in the judgment of the Issuer, been properly compiled from engineering tests conducted in accordance with prevailing industry standards. (c) The financial projections and estimates and the pro forma financial statements included in the Offering Memorandum or otherwise furnished by the Issuer in connection with the Notes and this Agreement have been prepared by the Issuer in good faith on the basis of information and assumptions that the Issuer believed to be reasonable as of the date of such information, and no material assumptions have been omitted as basis for such financial projections and estimates and pro forma financial statements. (d) Since December 31, 1996, there has been no material adverse change in the business, Properties, financial position, results of operations or prospects of the Issuer or the Issuer and its Subsidiaries, considered as a whole. SECTION 4.05. Full Disclosure. None of the financial statements and other financial or factual information included in the Offering Memorandum (excluding estimates, financial projections and pro forma financial statements) contains any untrue statement of material fact or omits to state a material fact necessary in order to make the statements contained therein not misleading. All other financial and reserve information, financial statements and other documents (excluding estimates, projections and pro forma financial information) furnished by the Issuer to the Purchasers in connection with the Notes and this Agreement and set forth on Schedule 4.05 do not and will not contain any untrue statement of material fact or omit to state a material fact necessary in order to make the statements contained therein not misleading. The Issuer has disclosed to the Purchasers in writing any and all facts known to the Issuer which materially, and adversely affect the business, properties, operations or condition, financial or otherwise, of the Issuer or the Issuer and its Subsidiaries, considered as a whole or the Issuer's ability to perform its obligations under the Notes and this Agreement. SECTION 4.06. Litigation. Except as disclosed on Schedule 4.06 there is no action, suit or proceeding pending against, or to the knowledge of the Issuer threatened against or affecting, the Issuer or any of its Affiliates before any court or arbitrator or any governmental body, agency or official in which there is a reasonable possibility of an adverse decision which could individually or in the aggregate materially adversely affect the financial position of the Issuer or the Issuer and its Subsidiaries, considered as a whole or which in any manner draws into question the validity of the Notes and this Agreement. SECTION 4.07. Compliance with ERISA. (a) Each member of the ERISA Group has fulfilled its obligations under the minimum funding standards of ERISA and the Internal Revenue Code with respect to each Plan and is in compliance in all material respects with the presently applicable provisions of ERISA and the Internal Revenue Code with respect to each Plan. No member of the ERISA Group has (i) sought a waiver of the minimum funding standard under Section 412 of the Internal Revenue Code in respect of any Plan, (ii) failed to make any contribution or payment to any Plan or Multiemployer Plan, or made any amendment to any Plan, which, in either case, has resulted or could result in the imposition of a Lien on Property of the Issuer or any Subsidiary or the posting of a bond or other security by the Issuer or any Subsidiary under ERISA or the Internal Revenue Code or (iii) incurred any liability under Title IV of ERISA (other than a liability to the PBGC for premiums under Section 4007 of ERISA) which could cause the Issuer or any Subsidiary (whether directly or jointly and severally with one or more affiliates) to incur any liability. 17 (b) The execution and delivery of this Agreement and the issuance and sale of the Notes hereunder will not involve any transaction that is subject to the prohibitions of section 406(a) of ERISA or in connection with which a tax could be imposed pursuant to section 4975(c)(1)(A)-(D) of the Internal Revenue Code. The representation by the Issuer in the immediately preceding sentence is made in reliance upon and subject to the accuracy of the representation of each Purchaser in Section 7.02 as to the sources of the funds used to pay the purchase price of the Notes to be purchased by such Purchaser. SECTION 4.08. Environmental Matters. In the ordinary course of its business, the Issuer considers effects of all existing and applicable Environmental Laws on the business, operations and properties of the Issuer and its Subsidiaries, in the course of which it identifies and evaluates associated liabilities and costs (including, without limitation, any capital or operating expenditures required for cleanup or closure of properties currently or previously owned, any capital or operating expenditures required to achieve or maintain compliance with environmental protection standards imposed by law or as a condition of any license, permit or contract, any related constraints on operating activities, including any periodic or permanent shutdown of any facility or reduction in the level of or change in the nature of operations conducted thereat and any actual or potential liabilities to third parties, including employees, and any related costs and expenses). The Issuer has reasonably concluded that existing and applicable Environmental Laws are unlikely to have a material adverse effect on the business, Properties, financial condition, results of operations or prospects of the Issuer or the Issuer and its Subsidiaries, considered as a whole. The Issuer and its Subsidiaries have conducted and are conducting their respective businesses in compliance with all applicable Environmental Laws, except where the failure to so comply would not have a material adverse effect on the Issuer or the Issuer and its Subsidiaries, considered as a whole. SECTION 4.09. Taxes. The Issuer and its Subsidiaries have filed all United States Federal income tax returns and all other material tax returns which are required to be filed by them and have paid all taxes due pursuant to such returns or pursuant to any assessment received by the Issuer or any Subsidiary. The charges, accruals and reserves on the books of the Issuer and its Subsidiaries in respect of taxes or other governmental charges are adequate. SECTION 4.10. Titles, ect. The Issuer and each Subsidiary has valid and defensible title to its material (individually or in the aggregate) Petroleum Properties and good, valid, defensible and marketable title to its other real and personal property, in each case free and clear of all Liens except Liens expressly permitted by Section 5.10. Each lease under which the Issuer or any of its Subsidiaries is the lessee which is material to the business or operations of the Issuer or the Issuer and its Subsidiaries considered as a whole is valid and subsisting and is in full force and effect. SECTION 4.11. Casualities; Taking of Properties. Since the date of the reserve data included in the Offering Memorandum, neither the business nor the Petroleum Properties of the Issuer or any of its Subsidiaries have been affected as a result of any fire, explosion, earthquake, flood, drought, windstorm, accident, strike or other labor disturbance, embargo, requisition or taking of Property or cancellation of contract, permits or concessions by any domestic or foreign government or any agency thereof, riot, activities of armed forces or acts of God or of any public enemy, or any other event the occurrence of which, would have a material adverse effect on the business, Properties, financial condition, results of operations or prospects of the Issuer or the Issuer and its Subsidiaries, considered as a whole. SECTION 4.12. Gas Imbalances. There exists no gas imbalances, take or pay or other prepayments with respect to any Petroleum Properties which would require the Issuer or any Subsidiary to deliver hydrocarbons produced from any Petroleum Properties at some future time 18 without then or thereafter receiving full payment therefor which would be reasonably likely to have a material adverse effect on the business, Properties, financial condition, results of operations or prospects of the Issuer or the Issuer and its Subsidiaries, considered as a whole. SECTION 4.13. Use of Proceeds. The proceeds from the sale of the Notes pursuant to this Agreement will be used by the Issuer to repay indebtedness under the Credit Agreement and for general corporate purposes. No part of the proceeds from the sale of the Notes hereunder will be used, directly or indirectly, for the purpose of buying or carrying any margin stock within the meaning of Regulation G of the Board of Governors of the Federal Reserve System (12 CFR 207), or for the purpose of buying or carrying or trading in any securities under such circumstances as to involve the Issuer in a violation of Regulation X of said Board (12 CFR 224) or to involve any broker or dealer in a violation of Regulation T of said Board (12 CFR 220). Margin stock does not constitute more than 5% of the value of the consolidated assets of the Issuer and its Subsidiaries and the Issuer does not have any present intention that margin stock will constitute more than 5% of the value of such assets. As used in this Section, the terms "margin stock" and "purpose of buying or carrying" shall have the meanings assigned to them in said Regulation G. SECTION 4.14. Offering of the Notes. Neither the Issuer nor any Person acting on behalf of the Issuer has, directly or indirectly, offered any of the Notes or any similar security of the Issuer for sale to, or solicited any offers to buy any thereof from, or otherwise approached or negotiated with respect thereto with, anyone other than the Purchasers and not more than 75 other institutional investors, each of whom were offered a portion of the Notes for purposes of investment and not for distribution. Neither the Issuer nor any Person acting on behalf of the Issuer has taken or will take any action which would cause the offer, issuance or sale of any Note to any Purchaser to violate the provisions of the Securities Act of 1933, as amended, or any other securities or blue sky laws of any applicable jurisdiction or subject the issuance or sale of the Notes to the registration requirements of Section 5 of said Securities Act. SECTION 4.15. Ownership of Subsidiaries. Schedule 4.15 sets forth a list of each Subsidiary of the Issuer and its jurisdiction of incorporation. All of the issued shares of capital stock of such Subsidiary have been duly and validly authorized and issued, are fully paid and nonassessable, and are owned directly or indirectly by the Issuer, free and clear of all Liens and restrictions on transferability or voting. ARTICLE V COVENANTS The Issuer agrees that, so long as any amount payable under any Note or this Agreement remains unpaid, it will, and will cause each of its Subsidiaries to, perform and comply with each of the following covenants, unless such performance and compliance shall have been specifically waived in writing by the Required Lenders: 19 SECTION 5.01. Information. The Issuer will deliver to each of the Holders: (a) as soon as available and in any event within 100 days after the end of each fiscal year of the Issuer, a consolidated balance sheet of the Issuer and its Subsidiaries as of the end of such fiscal year and the related consolidated statements of operations, cash flows and stockholders' equity for such fiscal year, setting forth in each case in comparative form the figures for the previous fiscal year, all reported on in a manner acceptable to the Securities and Exchange Commission by Coopers & Lybrand or other independent public accountants of nationally recognized standing; (b) as soon as available and in any event within 60 days after the end of each of the first three quarters of each fiscal year of the Issuer, a consolidated balance sheet of the Issuer and its Subsidiaries as of the end of such quarter and the related consolidated statements of operations and cash flows for such quarter and for the portion of the Issuer's fiscal year ended at the end of such quarter, setting forth in each case in comparative form the figures for the corresponding quarter and the corresponding portion of the Issuer's previous fiscal year, all certified (subject to normal year-end adjustments) as to fairness of presentation, generally accepted accounting principles and consistency by the chief financial officer or the chief accounting officer or treasurer of the Issuer; (c) simultaneously with the delivery of each set of financial statements referred to in clauses (a) and (b) above, a certificate of the chief financial officer or the chief accounting officer or treasurer of the Issuer (i) setting forth in reasonable detail the calculations required to establish whether the Issuer was in compliance with the financial covenants contained herein on the date of such financial statements, and (ii) stating whether any Default then exists, setting forth the details thereof and the action which the Issuer is taking or proposes to take with respect thereto; (d) within five days after any Executive Officer of the Issuer obtains knowledge of any Default, if such Default is then continuing, a certificate of the chief financial officer or the chief accounting officer or treasurer of the Issuer setting forth the details thereof and the action which the Issuer is taking or proposes to take with respect thereto; (e) promptly upon the mailing thereof to the shareholders of the Issuer generally, copies of all financial statements, reports and proxy statements so mailed; (f) promptly upon the filing thereof, copies of all registration statements (other than the exhibits thereto and any registration statements on Form S-8, or its equivalent) and reports on Forms 10K, 10Q and 8K (or their equivalents) which the Issuer shall have filed with the Securities and Exchange Commission; (g) if and when any member of the ERISA Group (i) gives or is required to give notice to the PBGC of any "reportable event" (as defined in Section 4043 of ERISA and the regulations thereunder) with respect to any Plan which might constitute grounds for a termination of such Plan under Title IV of ERISA, or any Executive Officer of the Issuer or any Subsidiary knows that the plan administrator of any Plan has given or is required to give notice of any such reportable event, a copy of the notice of such reportable event given or required to be given to the PBGC; (ii) receives notice of complete or partial withdrawal liability under Title IV of ERISA or notice that any Multiemployer Plan is in reorganization, is insolvent or has been terminated, a copy of such notice; (iii) receives notice from the PBGC under Title IV of ERISA of an intent to terminate, impose liability (other than for premiums 20 under Section 4007 of ERISA) in respect of, or appoint a trustee to administer any Plan, a copy of such notice; (iv) applies for a waiver of the minimum funding standard under Section 412 of the Internal Revenue Code, a copy of such application; (v) gives notice of intent to terminate any Plan under Section 4041(c) of ERISA, a copy of such notice and other information filed with the PBGC; (vi) gives notice of withdrawal from any Plan pursuant to Section 4063 of ERISA, a copy of such notice; or (vii) fails to make any required payment or contribution to any Plan or Multiemployer Plan, or makes any amendment to any Plan which has resulted or could result in the imposition of a Lien on Property of the Issuer or any Subsidiary or the posting of a bond or other security by the Issuer or any Subsidiary, a certificate of the chief financial officer or the chief accounting officer or treasurer of the Issuer setting forth details as to such occurrence and action, if any, which the Issuer or applicable member of the ERISA Group is required or proposes to take; and (h) from time to time such additional information regarding the financial position, reserves or business of the Issuer and its Subsidiaries as any Holder may reasonably request. SECTION 5.02. Payment of Obligations. The Issuer will pay and discharge, and will cause each Subsidiary to pay and discharge, at or before maturity, all their respective material obligations and liabilities, including, without limitation, tax liabilities, except where, the same may be contested in good faith by appropriate proceedings, and will maintain, and will cause each Subsidiary to maintain, in accordance with generally accepted accounting principles, appropriate reserves for the accrual of any of the same. SECTION 5.03. Maintenance of Property. The Issuer will keep, and will cause each Subsidiary to keep, all property useful and necessary in its business in good working order and condition, ordinary wear and tear excepted. The Issuer will operate, or will use its best efforts to cause a third party operator to operate, all Petroleum Properties in a prudent manner, and will market or will cause to be marketed the production therefrom at the best price reasonably obtainable at the time the applicable sales contract is executed. SECTION 5.04. Conduct of Business and Maintenance of Existence. The Issuer (a) will, and will cause each Subsidiary to continue to, engage in business of the same general type as now conducted by the Issuer and its Subsidiaries, and (b) will preserve, renew and keep in full force and effect, and will cause each Subsidiary to preserve, renew and keep in full force and effect, their respective corporate existence and their respective rights, privileges and franchises necessary or desirable in the normal conduct of business; provided that nothing in this Section 5.04 shall prohibit (i) the merger of a Wholly-Owned Subsidiary into the Issuer or the merger or consolidation of a Wholly-Owned Subsidiary with or into another Person if the corporation surviving such consolidation or merger is a Wholly-Owned Subsidiary and if, in each case, after giving effect thereto, no Default shall have occurred and be continuing or (ii) the termination of the corporate existence of any Subsidiary if the Issuer in good faith determines that such termination is in the best interest of the Issuer and is not materially disadvantageous to the Holders. SECTION 5.05. Compliance with Laws. The Issuer will comply, and will cause each Subsidiary to comply, in all material respects with all applicable laws, ordinances, rules, regulations, and requirements of governmental authorities (including, without limitation, Environmental Laws and ERISA and the rules and regulations thereunder) except for laws the violation of which could not have a material adverse effect on the Issuer or any Subsidiary and where the necessity of compliance therewith is contested in good faith by appropriate proceedings. 21 SECTION 5.06. Inspection of Property, Books and Records. The Issuer will keep, and will cause each Subsidiary to keep, proper books of record and account in which full, true and correct entries shall be made of all dealings and transactions in relation to its business and activities; and will permit, and will cause each Subsidiary to permit, representatives of any Holder at such Holder's expense (except during the continuance of any Default, in which case at the expense of the Issuer) to visit and inspect any of their respective Properties, to examine and make copies of any of their respective books and records and to discuss their respective affairs, finances and accounts with their respective officers, employees and independent public accountants, all at such reasonable times and as often as may reasonably be desired. SECTION 5.07. Insurance. The Issuer and each Subsidiary now maintains and will cause to be maintained with insurers which the Issuer believes to be financially sound and reputable, insurance with respect to its Properties and business against such liabilities, casualties, risks and contingencies and in such types and amounts as is customary in the case of Persons engaged in the same or similar businesses and similarly situated. SECTION 5.08. Engineering Reports (a) On or before April 10, 1998, and thereafter by April 10th of each subsequent year, the Issuer shall furnish to each of the Holders a report in form and substance reasonably satisfactory to the Required Lenders prepared by or under the supervision of a petroleum engineer who may be an employee of the Issuer, which shall evaluate all net Proved Reserves owned by the Issuer and its Subsidiaries as of the preceding December 31 and which shall set forth the information necessary to determine the Present Value of Proved Reserves as of such date. (b) Together with the Reserve Report furnished pursuant to subsection (a), the Issuer shall furnish to each of the Holders a review report thereon in form and substance reasonably satisfactory to the Required Lenders by Miller & Lents, Ltd. or other independent petroleum engineers of nationally recognized standing. SECTION 5.09. Asset Coverage Ratio. (a) The ratio of (i) Present Value of Proved Reserves plus Adjusted Cash to (ii) Debt and Other Liabilities shall at all times be not less than 1.5:1; (b) The Present Value of Proved Reserves will be determined and adjusted periodically as follows: (i) The calculation of Present Value of Proved Reserves will be determined from the most recent Reserve Report. (ii) Upon any sale by the Issuer or any Subsidiary of any Petroleum Property including but not limited to a sale of a lesser interest such as a royalty or a net profit interest to the extent the sale of such lesser interest is not considered to create a Lien (other than the sale of hydrocarbons after severance occurring in the ordinary course of the Issuer's business), the calculation of Present Value of Proved Reserves shall be reduced, effective on the date of consummation of such sale, by an amount equal to the Present Value of Proved Reserves attributable to Proved Reserves included in such sale. (iii) Immediately upon acquisition or development by the Issuer or any Subsidiary of any Petroleum Property owned directly by the Issuer or any Subsidiary and not reflected in the most recent Reserve Report, the calculation of Present Value 22 of Proved Reserves shall be increased in an amount equal to the Present Value of Proved Reserves attributable to such Petroleum Property. SECTION 5.10. Liens. The Issuer will not, and will not permit any Subsidiary to, create, incur, assume or suffer to exist any Lien on any of its Properties (now owned or hereafter acquired), except: (a) Excepted Liens; (b) Liens existing on the Closing Date and listed on Schedule 5.10, but not any renewals and extensions thereof; (c) a Lien existing on any asset prior to the acquisition thereof by the Issuer or any of its Subsidiaries but not created in contemplation of such acquisition; (d) a Lien on any asset not previously owned by the Issuer or any Subsidiary securing Debt incurred or assumed for the purpose of financing any part of the cost of acquiring such asset, provided that such Lien attaches to such asset concurrently with or within 90 days after the acquisition thereof; (e) Liens in respect of gas imbalances in the ordinary course of business not exceeding 2% of the Present Value of Proved Reserves in the aggregate at any time; and (f) Liens securing other Debt of the Issuer or any Subsidiary the aggregate principal amount of which, when taken together with the amount of Attributable Debt in respect of sale and leaseback transactions otherwise restricted by Section 5.15, does not exceed $5,000,000 at any time. SECTION 5.11. Transactions with Affiliates. The Issuer will not, and will not permit any Subsidiary to, directly or indirectly, pay any funds to or for the account of, make any Investment in, lease, sell, transfer or otherwise dispose of any assets, tangible or intangible, to, or participate in, or effect any transaction in connection with any joint enterprise or other joint arrangement with, any Affiliate; provided, however, that the foregoing provisions of this Section shall not prohibit (a) the Issuer or any Subsidiary from making sales to or purchases from any Affiliates and, in connection therewith, extending credit or making payments, or from making payments for services rendered by any Affiliates, if such sales or purchases are made or such services are rendered in the ordinary course of business and on terms and conditions at least as favorable to it as the terms and conditions which would apply in a similar transaction with a Person not an Affiliate, (b) the Issuer from making payments of principal, interest and premium on any Debt of the Issuer held by an Affiliate if the terms of such Debt are substantially as favorable to the Issuer as the terms which could have been obtained at the time of the creation of such Debt from a lender which was not an Affiliate and are otherwise in accordance with this Agreement, (c) the Issuer or any Subsidiary from participating in, or effecting any transaction in connection with, any joint enterprise or other joint arrangement with any Affiliate if it participates or effects any such transaction in the ordinary course of its business and on a basis no less advantageous than the basis on which such Affiliate participates or (d) the Issuer or any Wholly-Owned Subsidiary from engaging in any of the above listed activities with any other Wholly-Owned Subsidiary or any Wholly-Owned Subsidiary with the Issuer. 23 SECTION 5.12. Annual Coverage Ratio. (a) The Company will not permit as of the last day of any fiscal quarter the Annual Coverage Ratio to be less than 2.8:1. For this purpose: (i) "Annual Coverage Ratio" means at any date the ratio of Consolidated Cash Flow to Consolidated Interest Expense for the period of four consecutive fiscal quarters ending on such date. (ii) "Consolidated Cash Flow" means, for any period, the net cash from operating activities of the Issuer and its Consolidated Subsidiaries for such period, as the same is, or would in accordance with generally accepted accounting principles be set forth in a statement of cash flows for such period, plus to the extent deducted in determining such net cash from operating activities, the sum of (x) Consolidated Interest Expense for such period and (y) income tax expense. (iii) "Consolidated Interest Expense" means, for any period, the interest expense of the Issuer and its Consolidated Subsidiaries determined on a consolidated basis for such period in accordance with generally accepted accounting principles. (iv) "Consolidated Subsidiaries" means at any date any Subsidiary or other entity the accounts of which would in accordance with generally accepted accounting principles be consolidated with those of the Issuer in its consolidated financial statements if such statements were prepared as of such date. SECTION 5.13. Consolidations, Mergers and Sales of Asset. (a) Without limiting the applicability of Section 2.03(d), the Issuer will not consolidate or merge with or into any other Person or sell, lease or otherwise transfer, directly or indirectly, all or substantially all of its assets to any other Person unless (i) immediately after giving effect to such consolidation, merger, sale, lease or other transfer, no Default shall exist and the Issuer would be in compliance with the provisions of Section 5.12 (assuming that the date of any determination hereunder were the end of a fiscal quarter of the Issuer), (ii) such Person shall be a corporation organized and existing under the laws of the United States of America or any state therein or the District of Columbia and (iii) all of the obligations of the Issuer under the Notes and this Agreement shall have been expressly assumed in writing by the Person formed by such consolidation, or into which the Issuer shall have been merged, or which shall have acquired such assets. (b) The Issuer will not, and will not permit any Subsidiary to, make any Asset Disposition to any Person unless such Asset Disposition is upon fair and reasonable terms no less favorable to the Issuer or such Subsidiary than would obtain in a comparable arm's-length transaction with a Person which is not an Affiliate; provided that, this Section 5.13(b) shall not limit the transactions permitted with Affiliates provided under Section 5.11 hereof. SECTION 5.14. Subsidiary Debt. The Issuer will not permit any Subsidiary to incur, create, assume, guarantee or in any other manner become liable with respect to, or extend the maturity of or become responsible for the payment of any Debt other than (i) Debt owing to the Issuer or a Wholly-Owned Subsidiary, (ii) Non-Recourse Debt in an aggregate principal amount (together with any such Non-Recourse Debt incurred by the Issuer) not to exceed $150,000,000 at any time incurred to finance the acquisition of assets, and (iii) other Debt in an aggregate principal amount not to exceed 5% of the Present Value of Proved Reserves as reflected in the most recent Reserve Report. 24 SECTION 5.15. Sale and Leasebacks. The Issuer shall not, and shall not permit any of its Subsidiaries to, enter into any arrangement with any lender or investor (other than the Issuer or any Subsidiary of the Issuer) or to which such lender or investor is a party providing for the leasing by the Issuer or any of its Subsidiaries for a period of more than three years (including all renewals and extensions) of real or personal property that has been or is to be sold or transferred by the Issuer or any of its Subsidiaries to such lender or investor or to any Person to whom funds have been or are to be advanced by such lender or investor on the security of such property or rental obligations of the Issuer or any of its Subsidiaries, unless the Issuer or such Subsidiary would be entitled, pursuant to Section 5.10(f), to incur Debt in a principal amount equal to or exceeding the Attributable Debt in respect of such arrangement, secured by a Lien on the property to be leased, without any violation of Section 5.09 or 5.14. ARTICLE VI DEFAULTS SECTION 6.01. Events of Default. If one or more of the following events shall have occurred and be continuing: (a) the Issuer shall fail to pay when due any principal on the Notes or shall fail to pay within five Business Days of the due date thereof any interest or other amount payable under any of the Notes or this Agreement; (b) the Issuer shall fail to observe or perform any covenant or agreement contained in Section 5.14 for 10 days after it shall have become aware of such failure; (c) the Issuer shall fail to observe or perform any covenant or agreement contained in Sections 5.04(a), 5.09, 5.10, 5.11, 5.12, 5.13 and 5.15; (d) the Issuer shall fail to observe or perform any of its covenants or agreements contained in any of the Notes or this Agreement (other than those covered by clause (a), (b) or (c) above) for 30 days after it shall have become aware of such failure; (e) any representation, warranty, certification or statement made by the Issuer in any of the Notes or this Agreement or in any certificate, financial statement or other document delivered pursuant to any of the Notes or this Agreement shall prove to have been incorrect in any material respect when made; (f) the Issuer or any Subsidiary shall fail to make any payment in respect of any Material Debt (other than the Notes) when due or within any applicable grace period and such default has not been effectively waived by the holders of such Debt; (g) any event or condition shall occur which, after the expiration of any applicable grace period with respect thereto, results in the acceleration of the maturity of any Material Debt (other than the Notes) or enables the holder of such Debt or any Person acting on such holder's behalf to accelerate the maturity thereof and such default has not been effectively waived by the holders of such Debt (provided, that prior to the expiration of such grace period, the occurrence of such event or condition shall constitute a Default hereunder); 25 (h) the Issuer or any Subsidiary shall commence a voluntary case or other proceeding seeking liquidation, reorganization or other relief with respect to itself or its debts under any bankruptcy, insolvency or other similar law now or hereafter in effect or seeking the appointment of a trustee, receiver, liquidator, custodian or other similar official of it or any substantial part of its property, or shall consent to any such relief or to the appointment of or taking possession by any such official in an involuntary case or other proceeding commenced against it, or shall make a general assignment for the benefit of creditors, or shall fail generally to pay its debts as they become due, or shall take any corporate action to authorize any of the foregoing; (i) an involuntary case or other proceeding shall be commenced against the Issuer or any Subsidiary seeking liquidation, reorganization or other relief with respect to it or its debts under any bankruptcy, insolvency or other similar law now or hereafter in effect or seeking the appointment of a trustee, receiver, liquidator, custodian or other similar official of it or any substantial part of its property, and such involuntary case or other proceeding shall remain undismissed and unstayed for a period of 60 days; or an order for relief shall be entered against the Issuer or any Subsidiary under the federal bankruptcy laws as now or hereafter in effect; (j) any member of the ERISA Group shall fail to pay when due an amount or amounts aggregating in excess of $1,000,000 which it shall have become liable to pay under Title IV of ERISA which failure to pay could cause the Issuer or any Subsidiary (whether directly or jointly and severally with one or more affiliates) to incur a liability in respect of such amount or amounts, except for any such failure which is being contested in good faith through appropriate proceedings, so long as such proceedings are diligently prosecuted and no Lien has been imposed on any Property of the Issuer or any Subsidiary as a consequence of such failure; or notice of intent to terminate a Material Plan shall be filed under Title IV of ERISA by any member of the ERISA Group, any plan administrator or any combination of the foregoing; or the PBGC shall institute proceedings under Title IV of ERISA to terminate, to impose liability (other than for premiums under Section 4007 of ERISA) in respect of, or to cause a trustee to be appointed to administer any Material Plan; or a condition shall exist by reason of which the PBGC would be entitled to obtain a decree adjudicating that any Material Plan must be terminated; or there shall occur a complete or partial withdrawal from, or a default, within the meaning of Section 4219(c)(5) of ERISA, with respect to, one or more Multi-employer Plans which could cause the Issuer or any Subsidiary (whether directly or indirectly or jointly and severally with one or more affiliates) of the ERISA Group to incur a current payment obligation in excess of $1,000,000; or (k) a judgment or order for the payment of money in excess of $5,000,000 shall be rendered against the Issuer or any Subsidiary and such judgment or order shall continue unsatisfied and unstayed pending appeal for a period of 30 days; then (i) in the event of any Event of Default specified in subsection (a) of this Section 6.01, each Holder may, by notice to the Issuer declare the principal amount of all Notes held by such Holder (together with accrued interest thereon) and, to the extent permitted under applicable law, the Make Whole Amount with respect thereto and all other amounts payable by the Issuer hereunder to such Holder to be, and such Notes and amounts shall thereupon become, immediately due and payable without presentment, demand, protest or other notice of any kind, all of which are hereby waived by the Issuer; 26 (ii) in the event of any Event of Default specified in subsections (h)or (i) of this Section 6.01, without any notice to the Issuer or any other act by any Holder or the Majority Lenders, the Notes (together with accrued interest thereon and all other amounts payable by the Issuer hereunder) and, to the extent permitted under applicable law, the Make Whole Amount with respect thereto shall become immediately due and payable without presentment, demand, protest, notice of intent to accelerate, notice of acceleration, or other notice of any kind, all of which are hereby waived by the Issuer; and (iii) in the event of any Event of Default specified in any other subsection of this Section 6.01, the Majority Lenders may, by notice to the Issuer, declare the Notes (together with accrued interest thereon) and, to the extent permitted under applicable law, the Make Whole Amount with respect thereto and all other amounts payable by the Issuer hereunder to be, and such Notes and amounts shall thereupon become, immediately due and payable without presentment, demand, protest or other notice of any kind, all of which are hereby waived by the Issuer. SECTION 6.02. Rescission of Acceleration. At any time after the principal of, and interest accrued on and the Make Whole Amount on, any or all of the Notes are declared due and payable, the Required Lenders, by written notice to the Issuer, may rescind and annul any such declaration and its consequences if (a) the Issuer has paid all overdue interest on the Notes, the principal of and Make Whole Amount, if any, on any Notes which have become due otherwise than by reason of such declaration, and interest on such overdue principal and Make Whole Amount, (to the extent permitted by applicable law) any overdue interest in respect of the Notes, (b) all Events of Default, other than non-payment of amounts which have become due solely by reason of such declaration, and all conditions and events which constitute a Default have been cured or waived pursuant to Section 8.04, and (c) no judgment or decree has been entered for the payment of any monies due pursuant to the Notes or this Agreement; but no such rescission and annulment shall extend to or affect any subsequent Default or Event of Default or impair any right consequent thereon. ARTICLE VII PURCHASE FOR INVESTMENT; SOURCE OF FUNDS SECTION 7.01. Purchase for Investment. Each Purchaser represents that it is purchasing Notes for its own account or for one or more separate accounts maintained by it or for the account of one or more pension or trust funds, in each case for investment and not with a view to the distribution thereof or with any present intention of distributing or selling any of the Notes, but subject to any requirement of law, the disposition of its or their property shall at all times be within its or their control. SECTION 7.02. Source of Funds. Each Purchaser represents that at least one of the following statements is an accurate representation as to each source of funds (a "Source") to be used by it to pay the purchase price of the Notes purchased by it hereunder: (a) the Source is an "insurance company general account" (as the term is defined in Prohibited Transaction Exemption ("PTE") 95-60 (issued July 12, 1995)) in respect of which the reserves and liabilities (as defined by the annual statement for life insurance companies approved by the National Association of Insurance Commissioners (the "NAIC Annual Statement")) for the general account contract(s) held by or on behalf of any employee benefit plan together with the amount of the reserves and liabilities for the general account contract(s) held by or on behalf of any other employee benefit plans maintained by the same employer 27 (or affiliate thereof as defined in PTE 95-60) or by the same employee organization in the general account do not exceed 10% of the total reserves and liabilities of the general account (exclusive of separate account liabilities) plus surplus as set forth in the NAIC Annual Statement filed with such Purchaser's state of domicile; or (b) the Source is a separate account that is maintained solely in connection with such Purchaser's fixed contractual obligations under which the amounts payable, or credited, to any employee benefit plan (or its related trust) that has any interest in such separate account (or to any participant or beneficiary of such plan (including any annuitant)) are not affected in any manner by the investment performance of the separate account; or (c) the Source is either (i) an insurance company pooled separate account, within the meaning of PTE 90-1 (issued January 29, 1990), or (ii) a bank collective investment fund, within the meaning of the PTE 91-38 (issued July 12, 1991) and, except as disclosed by such Purchaser to the Issuer in writing pursuant to this paragraph (c), no employee benefit plan or group of plans maintained by the same employer or employee organization beneficially owns more than 10% of all assets allocated to such pooled separate account or collective investment fund; or (d) the Source constitutes assets of an "investment fund" (within the meaning of Part V of the QPAM Exemption) managed by a "qualified professional asset manager" or "QPAM" (within the meaning of Part V of the QPAM Exemption), no employee benefit plan's assets that are included in such investment fund, when combined with the assets of all other employee benefit plans established or maintained by the same employer or by an affiliate (within the meaning of Section V(c) of the QPAM Exemption) of such employer or by the same employee organization and managed by such QPAM, exceed 20% of the total client assets managed by such QPAM, the conditions of Part I(c) and (g) of the QPAM Exemption are satisfied, neither the QPAM nor a person controlling or controlled by the QPAM (applying the definition of "control" in Section V(e) of the QPAM Exemption) owns a 5% or more interest in the Issuer and (i) the identity of such QPAM and (ii) the names of all employee benefit plans whose assets are included in such investment fund have been disclosed to the Issuer in writing pursuant to this paragraph (d); or (e) the Source is a governmental plan; or (f) the Source is one or more employee benefit plans, or a separate account or trust fund comprised of one or more employee benefit plans, each of which has been identified to the Issuer in writing pursuant to this paragraph (f); or (g) the Source does not include assets of any employee benefit plan, other than a plan exempt from the coverage of ERISA. As used in this Section 7.02, the terms "employee benefit plan", "governmental plan", "party in interest" and "separate account" shall have the respective meanings assigned to such terms in Section 3 of ERISA. 28 SECTION 7.03. Securities Act; Legend. Each Purchaser represents that it is an accredited investor (as defined in Regulation D of the Rules and Regulations of the Securities and Exchange Commission under the Securities Act of 1933, as amended) and that it understands the Notes have not been registered under the Securities Act of 1933. Each Purchaser acknowledges that upon issuance of the Notes, and until such time, if any, as the same is no longer required under applicable securities laws, the Notes shall bear the following legend: THIS NOTE HAS NOT BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933, AS AMENDED, AND MAY NOT BE TRANSFERRED, SOLD OR OTHERWISE DISPOSED OF EXCEPT WHILE REGISTRATION UNDER SAID ACT IS IN EFFECT OR PURSUANT TO AN EXEMPTION FROM REGISTRATION UNDER SAID ACT OR IF SAID ACT DOES NOT APPLY. Any Holder of a Note may upon surrender of its Note to the Issuer together with an opinion of counsel to the effect that the foregoing legend is no longer required under applicable securities laws obtain a like Note in exchange for its Note without such legend. ARTICLE VIII MISCELLANEOUS SECTION 8.01. Notices. Unless otherwise specified herein, all notices, requests and other communications to any party hereunder shall be in writing (including bank wire, facsimile copy or similar writing) and shall be given (i) if to the Issuer, at its address or facsimile number set forth on its signature page hereto and to the attention of the Person therein specified, (ii) if to any Purchaser, at the address or facsimile number specified for such communication in Schedule A and to the Person therein specified, if any, or (iii) if to any other Holder, at such address or facsimile number and to such Person as such other Holder shall have specified to the Issuer in writing, or, in any case, to such other address or facsimile number or to the attention of such other Person as such party may hereafter specify for the purpose by notice in the case of the Issuer to each Holder and in the case of any Holder to the Issuer; provided, however, that no Holder shall be required to give notice to any other Holder of any matter under this Agreement. Each such notice, request or other communication shall be addressed to the attention of the Person specified pursuant to this Section and shall be effective (i) if given by mail, ten days after such communication is deposited in the mails with prepaid certified mail, return receipt requested, addressed as aforesaid or (ii) if given by courier, facsimile or any other means, when delivered to the Person specified, if any, at the address or sent to the facsimile number specified pursuant to this Section 8.01 with confirmation from the addressee of receipt. SECTION 8.02. No Waiver. No failure or delay by any Holder in exercising any right, power or privilege under any Note or this Agreement shall operate as a waiver thereof nor shall any single or partial exercise thereof preclude any other or further exercise thereof or the exercise of any other right, power or privilege. The rights and remedies provided in the Notes or this Agreement shall be cumulative and not exclusive of any rights or remedies provided by law. SECTION 8.03. Expenses; Documentary Taxes; Indemnification for Litigation. (a) The Issuer shall pay on demand (i) all reasonable fees and out-of-pocket expenses of the Purchasers and the Holders (including, without limitation, reasonable fees and disbursements of the law firm acting as special counsel for the Purchasers or the Holders and such local counsel as may be retained on behalf of the Purchasers or the Holders) in connection with the preparation, closing and administration of the Notes and this Agreement, any waiver, consent or amendment of any provision thereof (whether 29 or not any such waiver, consent or amendment becomes effective), or any Default or alleged Default thereunder, and (ii) if any Event of Default occurs, all reasonable out-of-pocket expenses incurred by any Holder, including reasonable fees and disbursements of counsel and funding losses, in connection with such Event of Default and collection and other enforcement proceedings resulting therefrom. The Issuer agrees to indemnify each Holder from and hold it harmless against any transfer taxes, documentary taxes, or other similar assessments or charges made by any governmental authority by reason of the execution and delivery of the Notes and this Agreement. The Issuer shall bear the costs of obtaining a Private Placement Number for the Notes. (b) The Issuer shall indemnify each Holder and hold each Holder harmless from and against any and all liabilities, losses, damages, costs and expenses of any kind (including, without limitation, the reasonable fees and disbursements of counsel for any Holder in connection with any investigative, administrative or judicial proceeding, whether or not such Holder shall be designated a party thereto) which may be incurred by any Holder, relating to or arising out of the Notes and this Agreement or any actual or proposed use of the proceeds of the sale of the Notes hereunder, provided that no Holder shall have the right to be indemnified hereunder for its own gross negligence or willful misconduct as determined by a court of competent jurisdiction. SECTION 8.04. Amendments and Waivers. (a) Any provision of this Agreement or the Notes may be amended or waived if, and only if, such amendment or waiver is in writing and is signed by the Issuer and the Required Lenders; provided that no such amendment or waiver shall, unless signed by all Holders of Outstanding Notes, (i) change the principal of or rate of interest on any Note, the Make Whole Amount or any other amount payable hereunder, (ii) waive or change the date fixed for any payment of principal of or interest on any Note or the Make Whole Amount hereunder, or (iii) change the percentage of Holders that shall be required for the Holders to take any action under this Section or any other provision of this Agreement; and provided further that no such amendment will change the principal amount of Notes to be purchased by any Purchaser hereunder without the consent of such Purchaser. (b) The Issuer will provide each Holder (irrespective of the amount of Notes then owned by it) with sufficient information, sufficiently far in advance of the date a decision is required, to enable such Holder to make an informed and considered decision with respect to any proposed amendment, waiver or consent in respect of any of the provisions hereof or of the Notes. The Issuer will deliver executed or true and correct copies of each amendment, waiver or consent effected pursuant to the provisions of this Section 8.04 to each Holder promptly following the date on which it is executed and delivered by, or receives the consent or approval of, the requisite Holders. (c) The Issuer will not directly or indirectly pay or cause to be paid any remuneration, whether by way of supplemental or additional interest, fee or otherwise, or grant any security, to any Holder as consideration for or as an inducement to the entering into by any Holder or any waiver or amendment of any of the terms and provisions hereof unless such remuneration is concurrently paid, or security is concurrently granted, on the same terms, ratably to each Holder even if such Holder did not consent to such waiver or amendment. SECTION 8.05. New York Law. This Agreement and each Note shall be construed in accordance with and governed by the law of the State of New York. SECTION 8.06. Successors and Assigns. This Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns, except that the Issuer may not assign or transfer any of its rights or obligations under this Agreement. 30 SECTION 8.07. Form, Registration, Transfer and Exchange of the Notes; Transferees. (a) The Notes issuable under this Agreement shall be registered notes substantially in the form of Exhibit A hereto and shall be issued in denominations of $1,000,000 and any larger multiple of $50,000 (except as may otherwise be required as a result of prepayments of portions of Notes pursuant to Section 2.03). The Issuer shall keep at its principal office a register in which the Issuer shall provide for the registration of the transfers of Notes. The Issuer's principal office for such purposes shall be maintained in the continental United States and, until further notice, will be maintained at the address specified pursuant to Section 8.01. Upon surrender of any Note at such office for registration of transfer, the Issuer shall execute and deliver, at its expense, one or more new Notes of a like aggregate unpaid principal amount. Each such new Note shall be registered in the name of the designated transferee or transferees (or its nominee or nominees). At the option of the Holder of any Note such Note may be exchanged for other Notes of any authorized denominations, of a like aggregate unpaid principal amount upon surrender of the Note to be exchanged at the principal office of the Issuer. Whenever any Notes are so surrendered for exchange, the Issuer shall execute and deliver, at its expense, the Notes which the Holder thereof making the exchange is entitled to receive. Every Note presented or surrendered for registration of transfer shall be duly endorsed, or be accompanied by a written instrument of transfer duly executed by the registered Holder or his attorney duly authorized in writing. Any Note or Notes issued in exchange for any Note or upon transfer thereof shall carry the rights to unpaid interest and interest to accrue which were carried by the Note so exchanged or transferred, and neither gain nor loss of interest shall result from any such transfer or exchange. Upon the written request of any Holder, the Issuer shall promptly forward to such Holder the names and addresses of all other Holders and the principal amount of Notes held by such Holders. Upon receipt by the Issuer of evidence reasonably satisfactory to it of the ownership of and loss, theft, destruction or mutilation of any Note and (i) in case of loss, theft, or destruction, of indemnity reasonably satisfactory to it (provided that, with respect to Institutional Investors and their nominees, such Person's agreement of indemnity shall be deemed to be satisfactory) or (ii) in the case of mutilation, upon surrender and cancellation thereof, the Issuer, at its expense, will execute and deliver, in lieu thereof, a new Note of like tenor and dated and bearing interest from the date to which interest has been paid on such lost, stolen, destroyed or mutilated Note. SECTION 8.08. Persons Deemed Owners. Prior to due presentment for registration of transfer, the Issuer may treat the Person in whose name any Note is registered as the owner and holder of such Note for the purpose of receiving payment of principal of and interest and premium on such Note and for all other purposes whatsoever, whether or not such Note is or shall be overdue, and the Issuer shall not be affected by notice to the contrary. SECTION 8.09. Home Office Payment. The Issuer agrees that, so long as a Purchaser listed on the signature pages hereof or its nominee shall hold any of the Notes, it will make payments of principal of and interest and Make Whole Amounts (if any) on such Notes not later than 12:00 noon, New York City time, on the date such payment is due, in immediately available funds, at the address specified for such purpose on Schedule A or such other account or address (in the United States of America) as such Purchaser may designate in writing, notwithstanding any contrary provisions contained herein or in the Notes and without any requirement of surrendering the Notes (except that, upon the written request of the Issuer, any Note that has been paid or prepaid in full shall be surrendered for cancellation to the Issuer at its principal office maintained by the Issuer pursuant to Section 8.07). Each Purchaser agrees that, before selling or otherwise transferring any Note, it will make a notation thereon of all principal payments previously made thereon and of the date to which interest thereon has been paid. As to any subsequent Holder, the Issuer will make payments of principal of and interest on the Notes held by such Holder not later than 12:00 noon, local time, to a place within the United States on the date such payment is due, in immediately 31 available funds, by credit to the account designated by such Holder or at the option of such Holder by a check mailed or delivered to the address designated by such Holder. SECTION 8.10. Substitution. Each Purchaser may by notice to the Issuer substitute any of its wholly-owned subsidiaries as a Purchaser hereunder. Such notice shall be signed by such Purchaser and such wholly-owned subsidiary, shall contain such wholly-owned subsidiary's agreement to be bound by this Agreement and shall contain confirmation by such wholly-owned subsidiary of the accuracy with respect to it of the representations set forth in Article VII (subject to any exception necessary to reflect the intention, if any, of such wholly-owned subsidiary to transfer to such Purchaser at a subsequent date all or any of the Notes to be acquired by such wholly-owned subsidiary). The Issuer agrees that, upon receipt of such notice, all references to "Purchaser" hereunder (other than this Section 8.10) shall include a reference to such wholly-owned subsidiary and that such wholly-owned subsidiary shall have the right to transfer the Notes acquired by it hereunder to a Purchaser subsequent to such purchase. In the event that a wholly-owned subsidiary is substituted for a Purchaser in accordance with this Section 8.10 and thereafter transfers its Notes or any portion thereof to such Purchaser, the term "Purchaser" shall be deemed to refer to such wholly-owned subsidiary only if it retains any portion of the Notes, and shall refer to such Purchaser to the extent such Purchaser owns all or any portion of the Notes, and such Purchaser and such wholly-owned subsidiary (if it retains any Notes) shall each have all the rights which an original purchaser of Notes has under this Agreement. SECTION 8.11. Credit Decision. Each Purchaser acknowledges that it has, independently and without reliance upon any other Purchaser, and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement. Each Purchaser also acknowledges that it will, independently and without reliance upon any other Purchaser, and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking any action under the Notes and this Agreement. SECTION 8.12. Counterparts; Integration; Effectiveness; Severability. (a) This Agreement may be signed in any number to counterparts, each of which shall be an original, and all of which taken together shall constitute a single agreement, with the same effect as if the signatures thereto and hereto were upon the same instrument. This Agreement constitutes the entire agreement and understanding among the parties hereto and supersedes any and all prior agreements and understandings, oral or written, relating to the subject matter hereof. This Agreement shall become effective when the Issuer shall have received counterparts hereof signed by all of the parties hereto (or, in the case of any Purchaser as to which an original executed counterpart shall not have been received, the Issuer shall have received from such Purchaser an executed counterpart hereof by facsimile by such Purchaser). (b) In case any provision in this Agreement or any Note shall be invalid, illegal or unenforceable, the validity, legality and enforceability of the remaining provisions shall not in any way be affected or impaired thereby and such provision shall be ineffective only to the extent of such invalidity, illegality or unenforceability. SECTION 8.13. SUBMISSION TO JURISDICTION. THE ISSUER HEREBY SUBMITS TO THE NON-EXCLUSIVE JURISDICTION OF THE UNITED STATES DISTRICT COURT FOR THE SOUTHERN DISTRICT OF NEW YORK AND OF ANY NEW YORK STATE COURT SITTING IN THE CITY OF NEW YORK FOR PURPOSES OF ALL LEGAL PROCEEDINGS WHICH MAY ARISE HEREUNDER OR UNDER THE NOTES. THE ISSUER IRREVOCABLY WAIVES TO THE FULLEST EXTENT PERMITTED BY LAW, 32 ANY OBJECTION WHICH IT MAY HAVE OR HEREAFTER HAVE TO THE LAYING OF THE VENUE OF ANY SUCH PROCEEDINGS BROUGHT IN SUCH A COURT AND ANY CLAIM THAT ANY SUCH PROCEEDING BROUGHT IN SUCH A COURT HAS BEEN BROUGHT IN AN INCONVENIENT FORUM. THE ISSUER HEREBY CONSENTS TO PROCESS BEING SERVED IN ANY SUCH PROCEEDING BY THE MAILING OF A COPY THEREOF BY REGISTERED OR CERTIFIED MAIL, POSTAGE PREPAID, TO ITS ADDRESS SPECIFIED PURSUANT TO SECTION 8.01 OR IN ANY OTHER MANNER PERMITTED BY LAW. SECTION 8.14. Confidentiality. For the purposes of this Section 8.14, "Confidential Information" means information delivered to a Holder by or on behalf of the Issuer or any Subsidiary in connection with the transactions contemplated by or otherwise pursuant to this Agreement that is proprietary in nature and that was clearly marked or labeled or otherwise adequately identified when received by such Holder as being confidential information of the Issuer or such Subsidiary, provided that such term does not include information that (a) was publicly known or otherwise known to such Holder prior to the time of such disclosure, (b) subsequently becomes publicly known through no act or omission by such Holder or any person acting on its behalf, (c) otherwise becomes known to such Holder other than through disclosure by the Issuer or any Subsidiary or (d) constitutes financial statements delivered to such Holder under Section 5.01 that are otherwise publicly available. Each Holder will maintain the confidentiality of such Confidential Information in accordance with procedures adopted by such Holder in good faith to protect confidential information of third parties delivered to it, provided that such Holder may deliver or disclose Confidential Information to (i) its directors, trustees, officers, employees, agents, attorneys and affiliates (to the extent such disclosure reasonably relates to the administration of the investment represented by Notes held by it), (ii) its financial advisors and other professional advisors who agree to hold confidential the Confidential Information substantially in accordance with the terms of this Section 8.14, (iii) any other holder of any Note, (iv) any Institutional Investor to which such Holder sells or offers to sell such Note or any part thereof or any participation therein (if such Person has agreed in writing prior to its receipt of such Confidential Information to be bound by the provisions of this Section 8.14), (v) any federal or state regulatory authority having jurisdiction over such Holder, (vi) the National Association of Insurance Commissioners or any similar organization, or any nationally recognized rating agency that requires access to information about such Holder's investment portfolio, or (vii) any other Person to which such delivery or disclosure may be necessary or appropriate (w) to effect compliance with any law, rule, regulation or order applicable to such Holder, (x) in response to any subpoena or other legal process, (y) in connection with any litigation to which such Holder is a party or (z) if an Event of Default has occurred and is continuing, to the extent such Holder may reasonably determine such delivery and disclosure to be necessary or appropriate in the enforcement or for the protection of the rights and remedies under its Notes and this Agreement. Each holder of a Note, by its acceptance of a Note, will be deemed to have agreed to be bound by and to be entitled to the benefits of this Section 8.14 as though it were a party to this Agreement. On reasonable request by the Issuer in connection with the delivery to any holder of a Note of information required to be delivered to such holder under this Agreement or requested by such holder (other than a holder that is a party to this Agreement or its nominee), such holder will enter into an agreement with the Issuer embodying the provisions of this Section 8.14. 33 IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed by their respective authorized officers as of the date first above written. CABOT OIL & GAS CORPORATION By /s/ Edgar J. Milan ------------------------------ Title: Chief Financial Officer 15375 Memorial Drive Houston, Texas 77079 Attention: Treasurer Telecopier: (281) 589-4653 34 PURCHASERS: THE NORTHWESTERN MUTUAL LIFE INSURANCE COMPANY By: /s/Richard A. Strait -------------------------------- Title: Vice President THE GUARDIAN LIFE INSURANCE COMPANY OF AMERICA By: /s/Thomas M. Donohue -------------------------------- Title: Vice President-Fixed Income GREAT-WEST LIFE & ANNUITY INSURANCE COMPANY By: /s/ James G. Lowery -------------------------------- Title: Assistant Vice President- Investments By: /s/ Julie Bock -------------------------------- Title: Assistant Vice President PACIFIC LIFE INSURANCE COMPANY By: /s/ Diane W. Oales -------------------------------- Title: Assistant Vice President By: /s/ Peter S. Fiek -------------------------------- Title: Assistant Secretary KEYPORT LIFE INSURANCE COMPANY by Stein Roe & Farnham Incorporated, as agent By: /s/ Richard A. Hedgwood -------------------------------- Title: Senior Vice President TRANSAMERICA LIFE INSURANCE AND ANNUITY COMPANY By: /s/ John M. Casparian --------------------- Title: Investment Officer 35 EXHIBIT A [FORM OF NOTE] [Add Legend as Appropriate] CABOT OIL & GAS CORPORATION 7.19% NOTE DUE 2009 No. [_____] [Date] $[________] PPN 127097 A@ 2 FOR VALUE RECEIVED, the undersigned, CABOT OIL & GAS CORPORATION (herein called the "Issuer"), a corporation organized and existing under the laws of the State of Delaware, hereby promises to pay to [___________________________], or registered assigns, the principal sum of [___________________________] DOLLARS on November 15, 2009, with interest (computed on the basis of a 360-day year of twelve 30-day months) (a) on the unpaid balance thereof at the rate of 7.19% per annum from the date hereof, payable semiannually, on the 15th day of May and November in each year, commencing May 15, 1998, until the principal hereof shall have become due and payable, and (b) to the extent permitted by law on any overdue payment (including any overdue prepayment) of principal, any overdue payment of interest and any overdue payment of any Make Whole Amount (as defined in the Note Purchase Agreement referred to below), payable semiannually as aforesaid (or, at the option of the registered holder hereof, on demand), at a rate per annum from time to time equal to the higher of (i) 9.19% or (ii) the Prime Rate (as defined in said Note Purchase Agreement) for such day plus 2%. Payments of principal of, interest on and any Make Whole Amount with respect to this Note are to be made in lawful money of the United States of America as provided in Section 8.09 of the Note Purchase Agreement referred to below. This Note is one of a series of Notes (herein called the "Notes") issued pursuant to the Note Purchase Agreement, dated as of November 14, 1997 (as from time to time amended, the "Note Purchase Agreement"), between the Issuer and the Purchasers named therein and is entitled to the benefits thereof. Each holder of this Note will be deemed, by its acceptance hereof, (i) to have agreed to the confidentiality provisions set forth in Section 8.14 of the Note Purchase Agreement and (ii) to have made the representation set forth in Article VII of the Note Purchase Agreement. This Note is a registered Note and, as provided in the Note Purchase Agreement, upon surrender of this Note for registration of transfer, duly endorsed, or accompanied by a written instrument of transfer duly executed, by the registered holder hereof or such holder's attorney duly authorized in writing, a new Note for a like principal amount will be issued to, and registered in the name of, the transferee. Prior to due presentment for registration of transfer, the Issuer may treat the person in whose name this Note is registered as the owner hereof for the purpose of receiving payment and for all other purposes, and the Issuer will not be affected by any notice to the contrary. The Issuer will make required prepayments of principal on the dates and in the amounts specified in the Note Purchase Agreement. This Note is also subject to optional prepayment, in whole or from time to time in part, at the times and on the terms specified in the Note Purchase Agreement, but not otherwise. 36 If an Event of Default, as defined in the Note Purchase Agreement, occurs and is continuing, the principal of this Note may be declared or otherwise become due and payable in the manner, at the price (including any applicable Make Whole Amount) and with the effect provided in the Note Purchase Agreement. This Note shall be construed in accordance with and governed by the law of the State of New York. CABOT OIL & GAS CORPORATION By ------------------------------ Title: EX-10.18 3 FORM OF INDEMNITY AGREEMENT 1 Exhibit 10.18 CABOT OIL & GAS CORPORATION AGREEMENT This Agreement, made and entered into this 23rd day of August, 1994, ("Agreement"), by and between CABOT OIL & GAS CORPORATION, a Delaware corporation ("Company"), and ("Indemnitee"): WHEREAS, highly competent persons are becoming more reluctant to continue to serve publicly-held corporations as directors or in other capacities unless they are provided with adequate protection through insurance or adequate indemnification against inordinate risks of claims and actions against them arising out of their service to and activities on behalf of the corporation; WHEREAS, it is reasonable, prudent and necessary for the Company contractually to obligate itself to indemnify such persons to the fullest extent permitted by applicable law so that they will serve or continue to serve the Company free from undue concern that they will not be so indemnified; and WHEREAS, Indemnitee is willing to serve, continue to serve and to take on additional service for or on behalf of the Company on the condition that he be so indemnified; NOW THEREFORE, in consideration of the premises and the covenants contained herein, the Company and Indemnitee do hereby covenant and agree as follows: Section 1. Services by Indemnitee. Indemnitee agrees to serve at the request of the Company as a director, officer or employee. Indemnitee may at any time and for any reason resign from such position (subject to any other contractual obligation or any obligation imposed by operation of law), in which event the Company shall have no obligation under this Agreement to continue Indemnitee in any such position. Section 2. Indemnification - General. The Company shall indemnify, and advance Expenses (as hereinafter defined), to Indemnitee as provided in this Agreement and to the fullest extent permitted by applicable law in effect on the date hereof and to such greater extent as applicable law may thereafter from time to time permit. The rights of Indemnitee provided under the preceding sentence shall include, but shall not be limited to, the rights set forth in the other Sections of this Agreement. -1- 2 Section 3. Proceedings Other Than Proceedings by or in the Right of the Company. Indemnitee shall be entitled to the rights of indemnification provided in this Section 3 if, by reason of his Corporate Status (as hereinafter defined), he is, or is threatened to be made, a party to any threatened, pending, or completed Proceeding (as hereinafter defined), other than a Proceeding by or in the right of the Company. Pursuant to this Section 3, Indemnitee shall be indemnified against Expenses, judgments, penalties, fines and amounts paid in settlement actually and reasonably incurred by him or on his behalf in connection with such Proceeding or any claim, issue or matter therein, if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the Company, and, with respect to any criminal Proceeding, had no reasonable cause to believe his conduct was unlawful. Section 4. Proceedings by or in the Right of the Company. Indemnitee shall be entitled to the rights of indemnification provided in this Section 4 if, by reason of his Corporate Status, he is, or is threatened to be made, a party to any threatened, pending or completed Proceeding brought by or in the right of the Company to procure a judgment in its favor. Pursuant to this Section, Indemnitee shall be indemnified against Expenses actually and reasonably incurred by him or on his behalf in connection with such Proceeding if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the Company. Notwithstanding the foregoing, no indemnification against such Expenses shall be made in respect of any claim, issue or matter in such Proceeding as to which Indemnitee shall have been adjudged to be liable to the Company if applicable law prohibits such indemnification; provided, however, that if applicable law so permits, indemnification against Expenses shall nevertheless be made by the Company in such event if and only to the extent that the Court of Chancery of the State of Delaware, or the court in which such Proceeding shall have been brought or is pending, shall determine. Section 5. Indemnification for Expenses of a Party Who is Wholly or Partly Successful. Notwithstanding any other provision of this Agreement, to the extent that Indemnitee is, by reason of his Corporate Status, a party to and is successful, on the merits or otherwise, in any Proceeding, he shall be indemnified against all Expenses actually and reasonably incurred by him or on his behalf in connection therewith. If otherwise, as to one or more but less than all claims, issues or matters in such Proceeding, the Company shall indemnify Indemnitee against all Expenses actually and reasonably incurred by him or on his behalf in connection with each successfully resolved claim, issue or matter. For purposes of this Section and without limitation, the termination of any claim, issue or matter in such a Proceeding by dismissal, with or without prejudice, shall be deemed to be a successful result as to such claim, issue or matter. Section 6. Indemnification for Expenses of a Witness. Notwithstanding any other provision of this Agreement, to the extent that Indemnitee is, by reason of his Corporate Status, a witness in any Proceeding, he shall be indemnified against all Expenses actually and reasonably incurred by him or on his behalf in connection therewith. -2- 3 Section 7. Advancement of Expenses. The Company shall advance all reasonable Expenses incurred by or on behalf of Indemnitee in connection with any Proceeding within twenty days after the receipt by the Company of a statement or statements from Indemnitee requesting such advance or advances from time to time, whether prior to or after final disposition of such Proceeding. Such statement or statements shall reasonably evidence the Expenses incurred by Indemnitee and shall include or be preceded or accompanied by an undertaking by or on behalf of Indemnitee to repay any Expenses advanced if it shall ultimately be determined that Indemnitee is not entitled to be indemnified against such Expenses. Section 8. Procedure for Determination of Entitlement to Indemnification. (a) To obtain indemnification under this Agreement, Indemnitee shall submit to the Company a written request, including therein or therewith such documentation and information as is reasonably available to Indemnitee and is reasonably necessary to determine whether and to what extent Indemnitee is entitled to indemnification. The Secretary of the Company shall, promptly upon receipt of such a request for indemnification, advise the Board of Directors in writing that Indemnitee has requested indemnification. (b) Upon written request by Indemnitee for indemnification pursuant to the first sentence of Section 8(a) hereof, a determination, if required by applicable law, with respect to Indemnitee's entitlement thereto shall be made in the specific case: (i) if a Change in Control (as hereinafter defined) shall have occurred, by Independent Counsel (as hereinafter defined) (unless Indemnitee shall request that such determination be made by the Board of Directors or the stockholders, in which case by the person or persons or in the manner provided for in clauses (ii) or (iii) of this Section 8(b)) in a written opinion to the Board of Directors, a copy of which shall be delivered to Indemnitee; (ii) if a Change of Control shall not have occurred, (A) by the Board of Directors by a majority vote of a quorum consisting of Disinterested Directors (as hereinafter defined), or (B) if a quorum of the Board of Directors consisting of Disinterested Directors so directs, by Independent Counsel in a written opinion to the Board of Directors, a copy of which shall be delivered to Indemnitee or (C) if so directed by the Board of Directors, by the stockholders of the Company; or (iii) as provided in Section 9(b) of this Agreement; and, if it is so determined that Indemnitee is entitled to indemnification, payment to Indemnitee shall be made within ten (10) days after such determination. Indemnitee shall cooperate with the person, persons or entity making such determination with respect to Indemnitee's entitlement to indemnification, including providing to such person, persons or entity upon reasonable advance request any documentation or information which is not privileged or otherwise protected from disclosure and which is reasonably available to Indemnitee and reasonably necessary to such determination. Any costs or expenses (including attorneys, fees and disbursements) incurred by Indemnitee in so cooperating with the person, persons or entity making such determination shall be borne by the Company (irrespective of the determination as to Indemnitee's entitlement to indemnification) and the Company hereby indemnifies and agrees to hold Indemnitee harmless therefrom. -3- 4 (c) In the event the determination of entitlement to indemnification is to be made by Independent Counsel pursuant to Section 8(b) hereof, the Independent Counsel shall be selected as provided in this Section 8(c). If a Change of Control shall not have occurred, the Independent Counsel shall be selected by the Board of Directors, and the Company shall give written notice to Indemnitee advising him of the identity of the Independent Counsel so selected. If a Change of Control shall have occurred, the Independent Counsel shall be selected by Indemnitee (unless Indemnitee shall request that such selection be made by the Board of Directors, in which event the preceding sentence shall apply), and Indemnitee shall give written notice to the Company advising it of the identity of the Independent Counsel so selected. In either event, Indemnitee or the Company, as the case may be, may, within 7 days after such written notice of selection shall have been given, deliver to the Company or to Indemnitee, as the case may be, a written objection to such selection. Such objection may be asserted only on the ground that the Independent Counsel so selected does not meet the requirements of "Independent Counsel" as defined in Section 17 of this Agreement, and the objection shall set forth with particularity the factual basis of such assertion. If such written objection is made, the Independent Counsel so selected may not serve as Independent Counsel unless and until a court has determined that such objection is without merit. If, within 20 days after submission by Indemnitee of a written request for indemnification pursuant to Section 8(a) hereof, no Independent Counsel shall have been selected and not objected to, either the Company or Indemnitee may petition the Court of Chancery of the State of Delaware or other court of competent jurisdiction for resolution of any objection which shall have been made by the Company or Indemnitee to the other's selection of Independent Counsel and/or for the appointment as Independent Counsel of a person selected by the Court or by such other person as the Court shall designate, and the person with respect to whom an objection is so resolved or the person so appointed shall act as Independent Counsel under Section 8(b) hereof. The Company shall pay any and all reasonable fees and expenses of Independent Counsel incurred by such Independent Counsel in connection with acting pursuant to Section 8(b) hereof, and the Company shall pay all reasonable fees and expenses incident to the procedures of this Section 8(c), regardless of the manner in which such Independent Counsel was selected or appointed. Upon the due commencement of any judicial proceeding or arbitration pursuant to Section 10(a)(iii) of this Agreement, Independent Counsel shall be discharged and relieved of any further responsibility in such capacity (such to the applicable standards of professional conduct then prevailing). -4- 5 Section 9. Presumptions and Effect of Certain Proceedings. (a) If a Change of Control shall have occurred, in making a determination with respect to entitlement to indemnification hereunder, the person or persons or entity making such determination shall presume that Indemnitee is entitled to indemnification under this Agreement if Indemnitee has submitted a request for indemnification in accordance with Section 8(a) of this Agreement, and the Company shall have the burden of proof to overcome that presumption in connection with the making by any person, persons or entity of any determination contrary to that presumption. (b) If the person, persons or entity empowered or selected under Section 8 of this Agreement to determine whether Indemnitee is entitled to indemnification shall not have made a determination within 60 days after receipt by the Company of the request therefor, the requisite determination of entitlement to indemnification shall be deemed to have been made and Indemnitee shall be entitled to such indemnification, absent (i) a misstatement by Indemnitee of a material fact, or an omission of a material fact necessary to make Indemnitee's statement not materially misleading, in connection with the request for indemnification, or (ii) a prohibition of such indemnification under applicable law; provided, however, that such 60-day period may be extended for a reasonable time, not to exceed an additional 30 days, if the person, persons or entity making the determination with respect to entitlement to indemnification in good faith requires such additional time for the obtaining or evaluating of documentation and/or information relating thereto; and provided, further, that the foregoing provisions of this Section 9(b) shall not apply (i) if the determination of entitlement to indemnification is to be made by the stockholders pursuant to Section 8(b) of this Agreement and if (A) within 15 days after receipt by the Company of the request for such determination the Board of Directors has resolved to submit such determination to the stockholders for their consideration at an annual meeting thereof to be held within 75 days after such receipt and such determination is made thereat, or (B) a special meeting of stockholders is called within 15 days after such receipt for the purpose of making such determination, such meeting is held for such purpose within 60 days after having been so called and such determination is made thereat, or (ii) if the determination of entitlement to indemnification is to be made by Independent Counsel pursuant to Section 8(b) of this Agreement. (c) The termination of any Proceeding or of any claim, issue or matter therein, by judgment, order, settlement or conviction, or upon a plea of nolo contendere or its equivalent, shall not (except as otherwise expressly provided in this Agreement) of itself adversely affect the right of Indemnitee to indemnification or create a presumption that Indemnitee did not act in good faith and in a manner which he reasonably believed to be in or not opposed to the best interests of the Company or, with respect to any criminal Proceeding, that Indemnitee had reasonable cause to believe that his conduct was unlawful. -5- 6 Section 10. Remedies of Indemnitee. (a) In the event that (i) a determination is made pursuant to Section 8 of this Agreement that Indemnitee is not entitled to indemnification under this Agreement, (ii) advancement of Expenses is not timely made pursuant to Section 7 of this Agreement, (iii) the determination of entitlement to indemnification is to be made by Independent Counsel pursuant to Section 8(b) of this Agreement and such determination shall not have been made and delivered in a written opinion within 90 days after receipt by the Company of the request for indemnification, or (iv) payment of indemnification is not made pursuant to Section 6 of this Agreement within ten (10) days after receipt by the Company of a written request therefor, or (v) payment of indemnification is not made within ten (10) days after a determination has been made that Indemnitee is entitled to indemnification or such determination is deemed to have been made pursuant to Section 8 or 9 of this Agreement, Indemnitee shall be entitled to an adjudication in an appropriate court of the State of Delaware, or in any other court of competent jurisdiction, of his entitlement to such indemnification or advancement of Expenses. Alternatively, Indemnitee, at his option, may seek an award in arbitration to be conducted by a single arbitrator pursuant to the rules of the American Arbitration Association. Indemnitee shall commence such proceeding seeking an adjudication or an award in arbitration within 180 days following the date on which Indemnitee first has the right to commence such proceeding pursuant to this Section 10(a); provided, however, that the foregoing clause shall not apply in respect of a proceeding brought by an Indemnitee to enforce his rights under Section 5 of the Agreement. (b) In the event that a determination shall have been made pursuant to Section 8 of this Agreement that Indemnitee is not entitled to indemnification, any judicial proceeding or arbitration commenced pursuant to this Section 10 shall be conducted in all respects as a de novo trial, or arbitration, on the merits and Indemnitee shall not be prejudiced by reason of that adverse determination. If a Change of Control shall have occurred, in any judicial proceeding or arbitration commenced pursuant to this Section 10 the Company shall have the burden of proving that Indemnitee is not entitled to indemnification or advancement of Expenses, as the case may be. (c) If a determination shall have been made or deemed to have been made pursuant to Section 8 or 9 of this Agreement that Indemnitee is entitled to indemnification, the Company shall be bound by such determination in any judicial proceeding or arbitration commenced pursuant to this Section 10, absent (i) a misstatement by Indemnitee of a material fact, or an omission of a material fact necessary to make Indemnitee's statement not materially misleading, in connection with the request for indemnification, or (ii) a prohibition of such indemnification under applicable law. -6- 7 (d) The Company shall be precluded from asserting in any judicial proceeding or arbitration commenced pursuant to this Section 10 that the procedures and presumptions of this Agreement are not valid, binding and enforceable and shall stipulate in any such court or before any such arbitrator that the Company is bound by all the provisions of this Agreement. (e) In the event that Indemnitee, pursuant to this Section 10, seeks a judicial adjudication of an award in arbitration to enforce his rights under, or to recover damages for breach of, this Agreement, Indemnitee shall be entitled to recover from the Company, and shall be indemnified by the Company against, any and all expenses (of the types described in the definition of Expenses in Section 17 of this Agreement) actually and reasonably incurred by him in such judicial adjudication or arbitration, but only if he prevails therein. If it shall be determined in said judicial adjudication or arbitration that Indemnitee is entitled to receive part but not all of the indemnification or advancement of expenses sought, the expenses incurred by Indemnitee in connection with such judicial adjudication or arbitration shall be appropriately prorated. Section 11. Non-Exclusivity; Survival of Rights; Insurance; Subrogation. (a) The rights of indemnification and to receive advancement of Expenses as provided by this Agreement shall not be deemed exclusive of any other rights to which Indemnitee may at any time be entitled under applicable law, the Certificate of Incorporation, the By-Laws, any agreement, a vote of stockholders or a resolution of directors, or otherwise. No amendment, alteration or repeal of this Agreement or any provision hereof shall be effective as to any Indemnitee with respect to any action taken or omitted by such Indemnitee in his Corporate Status prior to such amendment, alteration or repeal. (b) To the extent that the Company maintains an insurance policy or policies providing liability insurance for directors, officers or employees of the Company or of any other corporation, partnership, joint venture, trust employee benefit plan or other enterprise which such person serves at the request of the Company, Indemnitee shall be covered by such policy or policies in accordance with its or their terms to the maximum extent of the coverage available for any such director, officer, employee or agent under such policy or policies. (c) In the event of any payment under this Agreement, the Company shall be subrogated to the extent of such payment to all of the rights of recovery of Indemnitee, who shall execute all papers required and take all action necessary to secure such rights, including execution of such documents as are necessary to enable the Company to bring suit to enforce such rights. -7- 8 (d) The Company shall not be liable under this Agreement to make any payment of amounts otherwise indemnifiable hereunder if and to the extent that Indemnitee has otherwise actually received such payment under any insurance policy, contract, agreement or otherwise. Section 12. Duration of Agreement. This Agreement shall continue for so long as the Indemnitee may have any liability or potential liability by virtue of serving as a director, officer or employee of the Company or of any other corporation, partnership, joint venture, trust, employee benefit plan or other enterprise which Indemnitee served at the request of the Company, including without limitation, the final termination of all pending Proceedings in respect of which Indemnitee is granted rights of indemnification or advancement of expenses hereunder and of any proceeding commenced by Indemnitee pursuant to Section 10 of this Agreement relating thereto. This Agreement shall be binding upon the Company and its successors and assigns and shall insure to the benefit of Indemnitee and his heirs, executors and administrators. Section 13. Severability. If any provision or provisions of this Agreement shall be held to be invalid, illegal or unenforceable for any reason whatsoever: (a) the validity, legality and enforceability of the remaining provisions of this agreement (including without limitation, each portion of any Section of this Agreement containing any such provision held to be invalid, illegal or unenforceable) shall not in any way be affected or impaired thereby; and (b) to the fullest extent possible, the provisions of this Agreement (including, without limitation, each portion of any Section of this Agreement containing any such provision held to be invalid, illegal or unenforceable, that is not itself invalid, illegal or unenforceable) shall be construed so as to give effect to the intent manifested by the provision held invalid, illegal or unenforceable. Section 14. Exception to Right of Indemnification or Advancement of Expenses. Notwithstanding any other provision of this Agreement, Indemnitee shall not be entitled to indemnification or advancement of Expenses under this Agreement with respect to any Proceeding, or any claim therein, brought or made by him against the Company except for any claim or proceeding or in respect of this Agreement and/or the Indemnitee's rights hereunder. Section 15. Identical Counterparts. This Agreement may be executed in one or more counterparts, each of which shall for all purposes be deemed to be an original but all of which together shall constitute one and the same Agreement. Only one such counterpart signed by the party against whom enforceability is sought needs to be produced to evidence the existence of this Agreement. Section 16. Headings. The headings of the paragraphs of this Agreement are inserted for convenience only and shall not be deemed to constitute part of this Agreement or to affect the construction thereof. -8- 9 Section 17. Definitions. For purposes of this Agreement: (a) "Change in Control" means a change in control of the Company occurring after the Effective Date of a nature that would be required to be reported in response to Item 6(e) of Schedule 14A of Regulation 14A (or in response to any similar item on any similar schedule or form) promulgated under the Securities Exchange Act of 1934 (the "Act"), whether or not the Company is then subject to such reporting requirement; provided, however, that, without limitation, such a Change in Control shall be deemed to have occurred if after the Effective Date (i) any "person" (as such term is used in Section 13(d) and 14(d) of the Act) is or becomes the "beneficial owner" (as defined in Rule 13d-3 under the Act), directly or indirectly, of securities of the Company representing 20% or more of the combined voting power of the Company's then outstanding securities entitled to vote generally in the election of directors without the prior approval of at least two-thirds of the members of the Board of Directors in office immediately prior to such person attaining such percentage interest; (ii) the Company is a party to a merger, consolidation, sale of assets or other reorganization, or a proxy contest, as a consequence of which members of the Board of Directors in office immediately prior to such transaction or event constitute less than a majority of the Board of Directors thereafter; or (iii) during any period of two consecutive years, individuals who at the beginning of such period constituted the Board of Directors (including for this purpose any new director whose election or nomination for election by the Company's stockholders was approved by a vote of at least two-thirds of the directors then still in office who were directors at the beginning of such period) cease for any reason to constitute at least a majority of the Board of Directors. (b) "Corporate Status" describes the status of a person who is or was a director, officer or employee of the Company or of any other corporation, partnership, joint venture, trust, employee benefit plan or other enterprise which such person is or was serving at the request of the Company. (c) "Disinterested Director" means a director of the Company who is not and was not a party to the Proceeding in respect of which indemnification is sought by Indemnitee. (d) "Effective Date" means August 5, 1994. (e) "Expenses" shall include all reasonable attorneys fees, retainers, court costs, transcript costs, fees of experts, witness fees, travel expenses, duplicating costs, printing and binding costs, telephone charges, postage, delivery service fees, and all other disbursements or expenses of the types customarily incurred in connection with prosecuting, defending, preparing to prosecute or defined, investigating, or being or preparing to be a witness in a Proceeding. -9- 10 (f) "Independent Counsel" means a law firm, or a member of a law firm, that is experience in matters of corporation law and neither presently is, nor in the past five years has been, retained to represent: (i) the Company or Indemnitee in any matter material to either such party, or (ii) any other party to the Proceeding giving rise to a claim for indemnification hereunder. Notwithstanding the foregoing, the term "Independent Counsel" shall not include any person who, under the applicable standards of professional conduct then prevailing, would have a conflict of interest in representing either the Company or Indemnitee in an action to determine Indemnitee's rights under this Agreement. (g) "Proceeding" includes any action, suit, arbitration, alternate dispute resolution mechanism, investigation, administrative hearing or any other proceeding whether civil, criminal, administrative or investigative. Section 18. Modification and Waiver. No supplement, modification or amendment of this Agreement shall be binding unless executed in writing by both of the parties hereto. No waiver of any of the provisions of this Agreement shall be deemed or shall constitute a wavier of any other provisions hereof (whether or not similar) nor shall such waiver constitute a continuing waiver. Section 19. Notice by Indemnitee. Indemnitee agrees promptly to notify the Company in writing upon being served with any summons, citation, subpoena, complaint, indictment, information or other document relating to any Proceeding or matter which may be subject to indemnification or advancement of Expenses covered hereunder. Section 20. Notices. All notices, requests, demands and other communications hereunder shall be in writing and shall be deemed and shall be deemed to have been duly given if (i) delivered by hand and receipted for by the party to whom said notice or other communication shall have been directed, or (ii) mailed by certified or registered mail with postage prepaid, on the third business day after the date on which it is so mailed: (a) If to Indemnitee, to: 15375 Memorial Drive Houston, Texas 77079 (b) If to the Company to: 15375 Memorial Drive Houston, Texas 77079 or to such other address as may have been furnished to Indemnitee by the Company or to the Company by Indemnitee, as the case may be. -10- 11 Section 21. Governing Law. The parties agree that this Agreement shall be governed by, and construed and enforced in accordance with, the laws of the State of Delaware. Section 22. Miscellaneous. Use of the masculine pronoun shall be deemed to include usage of the feminine pronoun where appropriate. IN WITNESS WHEREOF, the parties hereto have executed this Agreement on the day and year first above written. ATTEST: CABOT OIL & GAS CORPORATION By: By: ------------------------ --------------------------- INDEMNITEE ------------------------------ Address: ------------------------------ ------------------------------ ------------------------------ -11- EX-21.1 4 SUBSIDIARIES OF CABOT OIL & GAS CORPORATION 1 Exhibit 21.1 SUBSIDIARIES OF CABOT OIL & GAS CORPORATION Big Sandy Gas Company Cabot Oil & Gas Marketing Corporation * Cabot Oil & Gas U.K. Limited Cabot Petroleum North Sea, Ltd. Cranberry Pipeline Corporation * Franklin Brine Treatment Corporation * Denotes significant subsidiary. EX-23.1 5 CONSENT OF COOPERS & LYBRAND LLP 1 Exhibit 23.1 CONSENT OF INDEPENDENT ACCOUNTANTS We consent to the incorporation by reference in the registration statement of Cabot Oil & Gas Corporation on Form S-8 filed on June 23, 1991 and on October 29, 1993 of our report dated March 6, 1998, on our audits of the consolidated financial statements of Cabot Oil & Gas Corporation as of December 31, 1997, which report in included in this Annual Report on Form 10-K. Our report refers to a change in 1995 in the method of applying the unit-of-production method to calculate depreciation and depletion on producing oil & gas properties, and accounting for the impairment of long-lived assets. COOPERS & LYBRAND L.L.P. Houston, Texas March 6, 1998 EX-23.2 6 CONSENT OF MILLER AND LENTS, LTD 1 Exhibit 23.2 [Miller and Lents, Ltd. Letterhead] March 11, 1998 Cabot Oil & Gas Corporation 15375 Memorial Drive Houston, Texas 77079 Re: Securities and Exchange Commission Form 10-K of Cabot Oil & Gas Corporation Gentlemen: The firm of Miller and Lents, Ltd. consents to the use of its name and the use of its report dated February 9, 1998 regarding Cabot Oil & Gas Corporation Proved Reserves and Future Net Revenues as of January 1, 1998, which report is to be included by reference in Form 10-K to be filed by Cabot Oil & Gas Corporation with the Securities and Exchange Commission. Miller and Lents, Ltd. has no interests in Cabot Oil & Gas Corporation, or in any of its affiliated companies or subsidiaries and is not to receive any such interest as payment for such report and has no director, officer, or employee employed or otherwise connected with Cabot Oil & Gas Corporation. We are not employed by Cabot Oil & Gas Corporation on a contingent basis. Very truly yours, MILLER AND LENTS, LTD. By: /s/ JAMES A. COLE ----------------- James A. Cole Senior Vice President JAC/mk EX-27 7 FINANCIAL DATA SCHEDULE
5 0000858470 CABOT OIL & GAS CORPORATION 1,000 YEAR DEC-31-1997 JAN-01-1997 DEC-31-1997 1,784 0 60,211 (529) 6,875 70,533 906,780 (437,381) 541,805 85,872 199,000 0 56,700 192,913 (65,551) 541,805 177,293 185,127 121,336 121,336 0 0 17,961 45,891 17,557 23,231 0 0 0 23,231 1.00 0.97
EX-28.1 8 MILLER AND LENTS, LTD. REVIEW LETTER, DATED 2/9/98 1 Exhibit 28.1 [Miller and Lents, Ltd. Letterhead] February 9, 1998 Cabot Oil & Gas Corporation 15375 Memorial Drive Houston, TX 77079 Re: Review of Proved Reserves And Future Net Revenues As of January 1, 1998 Gentlemen: At your request, we reviewed the estimates of proved reserves of oil, natural gas liquids, and gas and the future net revenues associated with these reserves that Cabot Oil & Gas Corporation, hereinafter Cabot, attributes to its net interests in oil and gas properties as of January 1, 1998. Cabot's estimates, shown below, are in accordance with the definitions contained in Securities and Exchange Commission Regulation S-X, Rule 4-10(a).
Proved Reserves ----------------------------------------- Developed Undeveloped Total ----------------------------------------- Net Liquids, MBbls 4,859.1 1,009.9 5,869.0 Net Gas, MMcf 738,764.2 164,664.7 903,428.9 Future Net Revenues Undiscounted, M$ 1,581,487.0 271,111.4 1,852,598.4 Discounted at 10 Percent, M$ 744,537.2 94,223.6 838,760.8
Based on our investigations and subject to the limitations described hereinafter, it is our judgment that (1) Cabot has an effective system for gathering data and documenting information required to estimate its proved reserves and to project its future net revenues, (2) in making its estimates and 2 Cabot Oil & Gas Corporation February 9, 1998 Page 2 projections, Cabot used appropriate engineering, geologic, and evaluation principles and techniques that are in accordance with practices generally accepted in the petroleum industry, and (3) the results of those estimates and projections are, in the aggregate, reasonable. All reserves discussed herein are located within the continental United States. Gas volumes were estimated at the appropriate pressure base and temperature base that are established for each well or field by the applicable sales contract or regulatory body. Total gas reserves were obtained by summing the reserves for all the individual properties and are therefore stated herein at a mixed pressure base. Cabot represents that the future net revenues reported herein were computed based on prices being received for oil, natural gas liquids, and gas as of Cabot's fiscal year end, December 31, 1997, and are in accordance with Securities and Exchange Commission guidelines. The present value of future net revenues was computed by discounting the future net revenues at 10 per cent per annum. Estimates of future net revenues and the present value of future net revenues are not intended and should not be interpreted to represent fair market values for the estimated reserves. In conducting our investigations, we reviewed the pertinent available engineering, geological, and accounting information for each well or designated property to satisfy ourselves that Cabot's estimates of reserves and future production forecasts and economic projections are, in the aggregate, reasonable. We independently selected a sampling of properties in each region and reviewed the direct operating expenses and product prices used in the economic projections. In its estimates of proved reserves and future net revenues associated with its proved reserves, Cabot has considered that a portion of its facilities associated with the movement of its gas in the Appalachian Region to its markets are unusual in that the construction and operation of these facilities are highly dependent on its producing operations. Cabot has deemed the portion of the cost of these facilities associated with its revenue interest gas as costs that are attributable to its oil and gas producing activities, and accordingly, has included these costs in its computation of the future net revenues associated with its proved reserves. Reserve estimates were based on decline curve extrapolations, material balance calculations, volumetric calculations, analogies, or combinations of these methods for each well, reservoir, or field. Reserve estimates from volumetric calculations and from analogies are often less certain than reserve estimates based on well performance obtained over a period during which a substantial portion of the reserves were produced. In making its projections, Cabot estimated yearly well abandonment costs except where salvage values were assumed to offset these expenses. Costs for possible future environmental claims were not included. Cabot's estimates include no adjustments for production prepayments, exchange agreements, gas balancing, or similar arrangements. We were provided with no information concerning these conditions, and we have made no investigations of these matters as such was beyond the scope of this investigation. 3 Cabot Oil & Gas Corporation February 9, 1998 Page 3 The evaluations presented in this report, with the exceptions of those parameters specified by others, reflect our informed judgments based on accepted standards of professional investigation but are subject to those generally recognized uncertainties associated with interpretation of geological, geophysical, and engineering information. Government policies and market conditions different from those employed in this study may cause the total quantity of oil, natural gas liquids, or gas to be recovered, actual production rates, prices received, or operating and capital costs to vary from those presented in this report. In conducting these evaluations, we relied upon production histories, accounting and cost data, and other financial, operating, engineering, and geological data supplied by Cabot. To a lesser extent, nonproprietary data existing in the files of Miller and Lents, Ltd., and data obtained from commercial services were used. We also relied, without independent verification, upon Cabot's representation of its ownership interests, payout balances and reversionary interests, the current prices, and the transportation fees applicable to each property. Miller and Lents, Ltd. is an independent oil and gas consulting firm. None of the principals of this firm have any financial interests in Cabot or any of its affiliated companies. Our fee is not contingent upon the results of our work or report, and we have not performed other services for Cabot that would affect our objectivity. Very truly yours, MILLER AND LENTS, LTD. By: /s/James A. Cole ----------------------- James A. Cole Senior Vice President JAC/mk -----END PRIVACY-ENHANCED MESSAGE-----