-----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, AwS1g1MlcrzWENQ8srooayQhSvVq2scOun33na/tlL9MsSd9ltuFUiw14GwF+TSv Q9W4LqsHdrD4fIqOPlytsQ== 0000950129-97-001243.txt : 19970328 0000950129-97-001243.hdr.sgml : 19970328 ACCESSION NUMBER: 0000950129-97-001243 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 8 CONFORMED PERIOD OF REPORT: 19961231 FILED AS OF DATE: 19970327 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: 1934 Act SEC FILE NUMBER: 001-10447 FILM NUMBER: 97564295 BUSINESS ADDRESS: STREET 1: 15375 MEMORIAL DR CITY: HOUSTON STATE: TX ZIP: 77079 BUSINESS PHONE: 7135894600 10-K 1 CABOT OIL & GAS CORPORATION - 12/31/96 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, 1996 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 28, 1997), was approximately $345,000,000. As of February 28, 1997, there were 22,857,294 shares of Common Stock outstanding. DOCUMENTS INCORPORATED BY REFERENCE Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held May 6, 1997 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 15 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 16 ITEM 6 Selected Historical Financial Data 17 ITEM 7 Management's Discussion and Analysis of Financial Condition and Results of Operations 18 ITEM 8 Financial Statements and Supplementary Data 27 ITEM 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 53 PART III ITEM 10 Directors and Executive Officers of the Registrant 53 ITEM 11 Executive Compensation 53 ITEM 12 Security Ownership of Certain Beneficial Owners and Management 53 ITEM 13 Certain Relationships and Related Transactions 53 PART IV ITEM 14 Exhibits, Financial Statement Schedules and Reports on Form 8-K 54
------------------------ The statements regarding future financial performance and results and the other statements which are not historical facts contained in this report are forward-looking statements. The words "expect," "project," "estimate," "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 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, 1996, the Company had approximately 946.6 Bcfe of total proved reserves, 97% 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, 1996 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)(2)
Total Appalachian Western Company Region Region(2) - ---------------------------------------------------------------------------- RESERVES/PRODUCTION: Proved reserves Developed (Bcfe) 796.2 436.6 359.6 Undeveloped (Bcfe) 150.4 92.3 58.1 --------- --------- ------- Total (Bcfe) 946.6 528.9 417.7 ========= ========= ======= Daily production (Mmcfe) net 170.3 73.5 96.8 Gross productive wells 5,109 3,858 1,251 Net productive wells 4,258.0 3,578.8 679.1 Percent of wells operated 88.2% 97.0% 60.8% ACREAGE: Net acreage Developed acreage 992,151 755,269 236,882 Undeveloped acreage 416,753 258,733 158,020 --------- --------- ------- Total 1,408,904 1,014,002 394,902 ========= ========= =======
- ---------- (1) As of December 31, 1996. 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. 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, to a lesser extent, exploration. 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, 1996, the Company had approximately 529 Bcfe of proved reserves (substantially all natural gas) in the Appalachian Region, constituting 56% of the Company's total proved reserves. The Company has 3,858 productive wells (3,578.8 net), of which 3,744 wells are operated by the Company. There are multiple producing intervals which include the Medina, Berea, and Big Lime trend formations at depths primarily ranging from 1,500 to 6,000 feet. Average net daily production in 1996 was 73.5 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 1996, the Company drilled 123 wells (105.7 net) in the Appalachian Region, of which 98 were development wells (94.6 net). Capital and exploration expenditures, including pipeline expenditures for the year were $33.5 million. In the 1997 drilling program year, the Company has plans to drill 138 wells. At December 31, 1996, the Company had 1,014,002 net acres in the region, including 755,269 net developed acres. At year end, the Company had identified 271 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. 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. At December 31, 1996, the Company had approximately 417.7 Bcfe of proved reserves (93.1% natural gas) in the Western Region, constituting 44% of the Company's total proved reserves. ANADARKO The Company has 745 productive wells (486.7 net) in the Anadarko area of which 546 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 1996 was 48.6 Mmcfe. 3 5 In 1996, the Company drilled 41 wells (26.0 net) in Anadarko (39 development wells, 25.3 net). Capital and exploration expenditures for the year were $13.1 million. In the 1997 drilling program year, the Company has plans to drill 56 wells. At December 31, 1996, the Company had approximately 216,278 net acres, including approximately 184,368 net developed acres. At year end, the Company had identified 54 proved undeveloped drilling locations. ROCKY MOUNTAIN The Company has 318 productive wells (119.7 net) in the Rocky Mountain area of which 161 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 1996 was 32.7 Mmcfe. In 1996, the Company drilled 22 wells (17.1 net) in the Rocky Mountains (21 development wells, 16.1 net). Capital and exploration expenditures for the year were $13.9 million. In the 1997 drilling program year, the Company has plans to drill 36 wells. At December 31, 1996, the Company had approximately 154,947 net acres, including approximately 37,990 net developed acres. At year end, the Company had identified 46 proved undeveloped drilling locations. GULF COAST The Company has 188 productive wells (72.7 net) in the Gulf Coast area of which 54 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 1996 was 15.5 Mmcfe. In 1996, the Company drilled 10 wells (5.4 net) in the Gulf Coast (8 development wells, 4.8 net). Capital and exploration expenditures for the year were $12.2 million. In the 1997 drilling program year, the Company has plans to drill 26 wells. At December 31, 1996, the Company had approximately 23,677 net acres, including approximately 14,524 net developed acres. At year end, the Company had identified 3 proved undeveloped drilling locations. 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. In 1994, 1995 and 1996, there was 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 margins. 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 4 6 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 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 20% 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 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 3,400 miles of pipeline with interconnects to four 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. 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 subsidiaries purchase all of the Company's natural gas production in the Western Region. These marketing subsidiaries sell 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 20% of the Western Region's production is sold under a 15 year cogeneration contract with 12 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 northeastern interstate pipelines, affording the Company access to multiple markets. The Company also produces and markets approximately 1,100 barrels a day of crude oil/condensate in the Western Region at market responsive prices. RISK MANAGEMENT In 1996, 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 5 7 price swaps call for payments to (or to receive payments from) counterparties based upon the differential between a fixed and a variable gas price. At December 31, 1996, the open price swaps (744,000 Mmbtu in notional quantity) covered the months of January and February 1997. 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 for further discussion. RESERVES CURRENT RESERVES The following table sets forth information regarding the Company's estimates of its net proved reserves at December 31, 1996.
Natural Gas(Mmcf) Liquids(1)(MBbl) Total(2)(Mmcfe) - ------------------------------------------------------------------------------------------------------------ Developed Undeveloped Total Developed Undeveloped Total Developed Undeveloped Total - ------------------------------------------------------------------------------------------------------------ Appalachian 434,558 92,301 526,859 334 0 334 436,560 92,301 528,861 Western(3) 333,540 55,218 388,758 4,351 481 4,832 359,646 58,103 417,749 ------- ------- ------- ----- --- ----- ------- ------- ------- Total 768,098 147,519 915,617 4,685 481 5,166 796,206 150,404 946,610 ======= ======= ======= ===== === ===== ======= ======= =======
- --------- (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, 1996. 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 judgement. 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. 6 8 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, 1993 555,933 252,347 808,280 136 2,690 2,826 556,749 268,487 825,236 Revisions of prior estimates (9,088) (15,539) (24,627) 54 (152) (98) (8,764) (16,451) (25,215) Extensions, discoveries and other additions 32,391 32,438 64,829 0 181 181 32,391 33,524 65,915 Production (29,668) (28,651) (58,319) (21) (803) (824) (29,794) (33,469) (63,263) Purchases of reserves in place 16,963 151,994 168,957 0 5,992 5,992 16,963 187,946 204,909 Sales of reserves in place (6,037) 0 (6,037) (2) (39) (41) (6,049) (234) (6,283) ------- ------- ------- --- ----- ----- ------- ------- --------- 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 ======= ======= ======= === ===== ===== ======= ======= ========= PROVED DEVELOPED RESERVES: December 31, 1993 458,682 210,990 669,672 136 2,210 2,346 459,498 224,250 683,748 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
- --------- APP = Appalachian Region WEST = Western Region(1) (1) For the year ended December 31, 1993, the Western reserves are attributable to Anadarko only. 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. 7 9 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.
Year Ended December 31, 1996 1995 1994 - ------------------------------------------------------------------------- Net Wellhead Sales Volume: Natural Gas (Bcf)(1) Appalachian Region 26.2 26.4 28.7 Western Region(2) 32.6 29.8 28.3 Crude/Condensate/Ngl (MBbl) Appalachian Region 21 18 20 Western Region 576 722 804 Produced Natural Gas Sales Price ($/Mcf)(3) Appalachian Region $ 2.72 $ 2.22 $ 2.42 Western Region $ 2.02 $ 1.33 $ 1.65 Weighted Average $ 2.34 $ 1.75 $ 2.04 Crude/Condensate Sales Price ($/Bbl)(3) $21.14 $17.95 $ 16.66 Production Costs ($/Mcfe)(4) $ 0.56 $ 0.55 $ 0.62
- --------- (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. 8 10 ACREAGE The following tables summarize the Company's gross and net developed and undeveloped leasehold and mineral acreage at December 31, 1996. Acreage in which the Company's interest is limited to royalty and overriding royalty interests is excluded. The undeveloped mineral fee acreage in West Virginia is unleased. LEASEHOLD ACREAGE
At December 31, 1996 Developed Undeveloped Total - --------------------------------------------------------------------------------------------- Gross Net Gross Net Gross Net - --------------------------------------------------------------------------------------------- STATE Alabama -- -- 312 312 312 312 Arkansas -- -- 240 3 240 3 Colorado 14,742 13,406 60,283 53,314 75,025 66,720 Indiana -- -- 54,022 26,725 54,022 26,725 Kansas 33,104 29,210 6,591 2,785 39,695 31,995 Kentucky 2,680 990 15,677 7,656 18,357 8,646 Louisiana 1,541 290 4,697 904 6,238 1,194 Michigan 457 118 25,161 5,232 25,618 5,350 Montana 157 52 680 303 837 355 New York 19,365 15,557 2,282 2,216 21,647 17,773 North Dakota 160 20 870 96 1,030 116 Ohio 2,906 1,372 25,151 10,972 28,057 12,344 Oklahoma 172,234 113,811 43,832 28,737 216,066 142,548 Pennsylvania 129,577 122,144 58,454 53,209 188,031 175,353 Texas 70,453 41,447 20,708 7,849 91,161 49,296 Utah 1,740 446 23,231 19,133 24,971 19,579 Virginia 4,541 3,820 20,092 18,010 24,633 21,830 West Virginia 552,797 517,911 92,541 76,609 645,338 594,520 Wyoming 46,235 23,312 89,938 43,438 136,173 66,750 --------- ------- ------- ------- --------- --------- Total 1,052,689 883,906 544,762 357,503 1,597,451 1,241,409 ========= ======= ======= ======= ========= ========= CANADA Alberta 1,429 563 316 79 1,745 642 British Columbia 665 166 1,992 498 2,657 664 --------- ------- ------- ------- --------- --------- Total 2,094 729 2,308 577 4,402 1,306 ========= ======= ======= ======= ========= =========
MINERAL FEE ACREAGE
At December 31, 1996 Developed Undeveloped Total - --------------------------------------------------------------------------------------------- Gross Net Gross Net Gross Net - --------------------------------------------------------------------------------------------- STATE Colorado 174 25 265 21 439 46 Kansas 160 128 -- -- 160 128 Montana -- -- 589 75 589 75 New York -- -- 6,545 1,636 6,545 1,636 Oklahoma 16,581 13,979 240 49 16,821 14,028 Pennsylvania 70 70 1,618 547 1,688 617 Texas 27 27 847 424 874 451 Virginia 17,917 17,851 -- -- 17,917 17,851 West Virginia 89,201 75,436 56,882 55,921 146,083 131,357 --------- ------- ------- ------- --------- --------- Total 124,130 107,516 66,986 58,673 191,116 166,189 ========= ======= ======= ======= ========= ========= Aggregate Total 1,178,913 992,151 614,056 416,753 1,792,969 1,408,904 ========= ======= ======= ======= ========= =========
9 11 Total Net Acreage by Area of Operation
At December 31, 1996 Developed Undeveloped Total - ------------------------------------------------------------- Appalachian Region 755,269 258,733 1,014,002 Western Region 236,882 158,020 394,902 ======= ======= --======= Total 992,151 416,753 1,408,904 ======= ------- ---------
PRODUCTIVE WELL SUMMARY(1) The following table reflects the Company's ownership at December 31, 1996 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, North Texas, Kansas, North Dakota, Utah, South Texas, Colorado, Wyoming and Canada).
Natural Gas Oil Total Gross Net Gross Net Gross Net - ---------------------------------------------------------------------- Appalachian Region 3,837 3,564.9 21 13.9 3,858 3,578.8 Western Region 1,006 572.9 245 106.2 1,251 679.1 ----- ------- --- ----- ----- ------- Total 4,843 4,137.8 266 120.1 5,109 4,257.9 ===== ======= === ===== ===== =======
- --------- (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, 1996 1995 1994 Gross Net Gross Net Gross Net - --------------------------------------------------------------------------- APPALACHIAN REGION: Development Wells Natural Gas 85 81.6 18 16.7 133 128.2 Oil 1 1.0 0 0.0 0 0.0 Dry 12 12.0 6 4.8 7 6.5 Exploratory Wells Natural Gas 10 5.0 2 0.5 0 0 Oil 5 0.9 2 0.5 0 0 Dry 10 5.2 5 2.0 2 0.5 --- ----- -- ---- --- ----- Total 123 105.7 33 24.5 142 135.2 === ===== == ==== === ===== Wells Acquired(1) Natural Gas 15 11.8 3 3.7 9 21.1 Oil 0 0.0 0 0.0 0 0.0 --- ----- -- ---- --- ----- Total 15 11.8 3 3.7 9 21.1 === ===== == ==== === ===== Wells in Progress at End of Period 2 1.5 3 3.0 2 1.3
10 12
Year Ended December 31, 1996 1995 1994 - --------------------------------------------------------------------------- Gross Net Gross Net Gross Net - --------------------------------------------------------------------------- WESTERN REGION: Development Wells Natural Gas 52 35.4 42 21.2 48 24.7 Oil 1 .1 2 1.9 7 3.1 Dry 15 10.6 7 3.8 8 5.3 Exploratory Wells Natural Gas 1 0 1 0.3 0 0.0 Oil 0 0 0 0 0 0.0 Dry 4 2.4 8 3.9 3 0.8 -- ---- - --- --- ----- Total 73 48.5 60 31.1 66 33.9 == ==== = === === ===== Wells Acquired(1) Natural Gas 25 11.9 0 2.7 413 115.7 Oil 3 0.4 0 0.1 140 52.3 ----- Total 28 12.3 0 2.8 553 168.0 == ==== = === === ===== Wells in Progress at End of Period 4 1.5 6 5.3 7 1.9
- --------- (1) Includes the acquisition of net interest in certain wells in the Appalachian Region and in the Western Region in 1996, 1995 and 1994 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. OTHER BUSINESS MATTERS MAJOR CUSTOMER The Company had no sales to any customer that exceeded 10% of the Company's total gross revenues in 1996. SEASONALITY Demand for natural gas has historically been seasonal in nature, with peak demand and typically higher prices occurring during the colder winter months. 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. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion. Further, numerous departments and agencies, both federal and state, 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. 11 13 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 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 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 or 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 methods previously used to gather the necessary information and make monthly determinations of appropriate field and well 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 marketed. The Federal Energy Regulatory Commission (the "FERC") regulates the interstate transportation and sale for resale of natural gas by interstate and intrastate pipelines. The FERC previously regulated the maximum selling prices of certain categories of gas sold in "first sales" in interstate and intrastate commerce under the Natural Gas Policy Act. 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 sales of the Company's domestically produced natural gas may be sold at market prices, unless otherwise committed by contract. 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. Among other things, Order No. 636 required pipelines to unbundle the various services that they had provided in the past, such as sales, transmission and storage, and to offer these services individually to their customers. By requiring interstate pipelines to "unbundle" their services and to provide their customers with direct access to pipeline capacity held by them, Order No. 636 has 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 pipelines and obtain transportation of such gas on a nondiscriminatory basis. The effect of Order No. 636 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 most individual pipelines have final open access tariffs now in place, the FERC is continuing to review and assess the effectiveness of it regulations and the Company cannot predict what 12 14 new 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 could significantly affect the marketing of natural gas. Some of the more notable of these regulatory initiatives include (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 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 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 and 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) have 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 at this time 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 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 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 13 15 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 360 active employees as of December 31, 1996. The Company believes that its relations with its employees are satisfactory. The Company has not entered into any collective bargaining agreements with its employees. 14 16 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 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, 1996, the Company owned or operated approximately 3,400 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 judgements 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% of its natural gas production 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. 15 17 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, 1996 to December 31, 1996. EXECUTIVE OFFICERS OF THE REGISTRANT The following table shows certain information about the executive officers of the Company as of March 1, 1997, as such term is defined in Rule 3b-7 promulgated under the Securities Exchange Act of 1934, and certain other officers of the Company.
Name Age Position Officer Since - -------------------------------------------------------------------------------------------- Charles P. Siess, Jr. 70 Chairman of the Board, Chief Executive 1995 Officer and President Ray R. Seegmiller 61 Executive Vice President, Chief Operating 1995 Officer and Treasurer Jim L. Batt 61 Vice President, Land 1988 Jeff W. Hutton 41 Vice President, Marketing 1995 Gerald F. Reiger 45 Vice President and Regional Manager 1995 James M. Trimble 48 Vice President, Business Development 1987 and Engineering H. Baird Whitehead 46 Vice President and Regional Manager 1987 Paul F. Boling 43 Controller 1996 Lisa A. Machesney 41 Corporate Secretary and Managing Counsel 1995
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, Chief Executive Officer and President 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. 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. 16 18 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:
Cash High Low Dividends - ------------------------------------------------------------- 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 1995 First Quarter $ 16.00 $ 12.38 $ 0.04 Second Quarter 17.00 13.63 0.04 Third Quarter 15.38 13.00 0.04 Fourth Quarter 15.75 13.13 0.04
As of January 31, 1997, there were 1,478 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) 1996 1995 1994 1993 1992 - ------------------------------------------------------------------------------------------------------------ INCOME STATEMENT DATA: Net Operating Revenues $ 163,061 $ 121,083 $ 140,295 $ 115,816 $ 107,205 Income (Loss) from Operations 48,787 (116,758) 15,013 20,007 17,983 Net Income (Loss) Applicable to All Common Stockholders 15,258 (92,171) (5,444) 2,088 2,227 EARNINGS (LOSS) PER SHARE APPLICABLE TO ALL COMMON STOCKHOLDERS(1) $ .67 $ (4.05) $ (0.25) $ 0.10 $ 0.11 DIVIDENDS PER COMMON SHARE $ 0.16 $ 0.16 $ 0.16 $ 0.16 $ 0.16 BALANCE SHEET DATA: Properties and Equipment, Net $ 480,511 $ 474,371 $ 634,934 $ 400,270 $ 306,723 Total Assets 561,341 528,155 688,352 445,001 348,696 Long-Term Debt 248,000 249,000 268,363 169,000 120,000 Stockholders' Equity 160,704 147,856 243,082 153,529 118,313
- --------- (1) See "Earnings (Loss) Per Common Share" under Note 1 of the Notes to the Consolidated Financial Statements. 17 19 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 substantial up swing in gas prices, coupled with actions taken in 1995 designed to return the Company to long-term profitability, played an important part in the Company's performance in 1996 with record earnings and operating cash flows. Operating results for 1996 included the benefit of the following realizations: o The average produced natural gas price was $2.34 per Mcf, up 34% compared to 1995. o As a result of the improved pricing environment, margins on brokered natural gas sales increased 124%, or $3.1 million over 1995. o Under its continued program to divest non-strategic properties, the Company sold 339 wells located in the Appalachian Region, generating $4.6 million in cash proceeds and a gain on sale of $1.6 million. o Net interest costs were down $7.5 million, or 30%, primarily due to the absence of interest rate swaps that were in place in 1995, lower interest rates, a reduced debt balance and $1.7 million of interest income related to an income tax refund for tax periods prior to 1990. o Depreciation, depletion and amortization ("DD&A") expenses were down $6.9 million or $0.11 per Mcfe of production. This reduction was primarily the result of the impairment of long-lived assets recorded as a result of adopting SFAS 121 in September 1995, which reduced the depreciable basis of properties and equipment by $113.8 million. Operating cash flows reached a record level, increasing $34.0 million, or 82%, over 1995. Cash flows from operations, along with the $5.7 million of proceeds from the sale of non-strategic properties, predominantly funded (1) $73.3 million of capital and exploration expenditures, $49 million higher than 1995, and (2) $9.2 million of preferred and common stock dividend payments. The Company drilled 154.2 net wells with a net success rate of 80% compared to 55.4 net wells and a net 75% success rate in 1995. Along with the higher success rate in 1996, the Company replaced 118% of production, through drilling additions and revisions, versus 73% production replacement in 1995. In 1997 the Company plans to drill 256 wells and spend $78.3 million in capital and exploration expenditures, 7% higher than 1996 expenditures. Natural gas production equivalent was 62.3 Bcf, virtually unchanged compared to 1995. The production from new wells reversed the downward trend in production experienced in the early part of 1996 due to (1) the low level of development activity in 1995, drilling only 55 net wells compared to an average of 135 net wells per year over the previous five years, and (2) the sale of non-strategic properties, representing quarterly production of 0.6 Bcf. The Company had a number of gas price swaps in place to hedge a significant portion of its production for the first four months of 1996. For the remainder of 1996, the Company had one small hedge contract for the months of May through September 1996 in a notional quantity equal to 5,000 Mmbtu per day, or less than 4% of the Company's daily production. While the Company will selectively use gas price hedges from time-to-time to protect certain markets when substantial downside risks are perceived, management intends to structure the hedge positions in a manner that retains upside potential. 18 20 The Company's strategic pursuits are sensitive to energy commodity prices, particularly the price of natural gas. While gas prices in many regions of the U.S. moved up sharply in November and December of 1996 to near record levels and some industry analysts predict continued improvements in 1997 pricing over 1996, the gas market has demonstrated significant price volatility during the months of January, February, and March 1997. Consequently, there is considerable uncertainty about gas prices for the rest of 1997 and beyond. The Company remains focused on the following goals established in 1995, applying a three pronged strategy of growth through the drill bit, growth through synergistic acquisitions and growth through greater emphasis on marketing. The Company believes that progress toward these goals is appropriate in the current industry environment, enabling the Company to effectively achieve its strategy over the long term. o Increase cash flows, using a balance of increased production and reduced costs. Significant progress has been made toward this goal, and the Company expects to be profitable in 1997 if the Henry Hub average price for the full year is $1.80 or more, assuming a traditional correlation between Henry Hub prices and prices realized by the Company in its regional markets. o Maintain reserves per share while increasing production to protect long-term shareholder value. An aggressive 1997 drilling program is designed to result in 1997 production exceeding 1996, and reserves are also expected to increase. o Reduce debt as a percentage of total capitalization without diluting existing shareholder value. To achieve this goal, project returns will be compared with the marginal cost of debt when deciding whether to reinvest or pay down debt. Other financing alternatives will also be reviewed. The preceding paragraphs, discussing the Company's strategic pursuits and goals, contain forward-looking information. See FORWARD-LOOKING INFORMATION on page 23. 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 and demand were up significantly in 1996 over 1995, resulting in higher cash flows. The primary source of cash for the Company during 1996 was from funds generated from operations. 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 outflow of $1.7 million in 1996. Net cash inflow from operating and financing activities totalled $65.9 million, funding in most part the capital and exploration expenditures of $67.6 million, net of the $5.7 million in proceeds from the sale of assets. 19 21
(In millions) 1996 1995 1994 ------------------------------------------------------------------------------------------- Cash Flows Provided by Operating Activities $ 75.5 $ 41.5 $ 67.3 -------- ------- --------
Cash flows provided by operating activities in 1996 were substantially higher, increasing $34 million over 1995, due predominantly to higher natural gas prices. Cash flows provided by operating activities in 1995 were lower by $25.8 million compared with 1994 primarily due to lower gas prices and higher interest costs attributable to the 1994 and 1993 acquisitions.
(In millions) 1996 1995 1994 ------------------------------------------------------------------------------------------- Cash Flows Provided (Used) by Investing Activities $ (67.6) $ (14.0) $ (158.8) -------- ------- --------
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. Cash flows used by investing activities in 1995 were $144.8 million lower than in 1994 due primarily to a $48.0 million decrease in capital expenditures and the lack of a major acquisition in 1995 compared to the $78.5 million capital outlay for the WERCO acquisition in 1994. The 1995 capital expenditures were offset in part by proceeds of $8.4 million for a valuation adjustment on the WERCO acquisition and $10.3 million in proceeds from the sale of assets.
(In millions) 1996 1995 1994 ------------------------------------------------------------------------------------------- Cash Flows Provided (Used) by Financing Activities $ (9.6) $ (28.2) $ 92.4 -------- ------- --------
Cash flows provided (used) by financing activities from 1994 to 1995 were primarily borrowings from or payments on the Company's revolving credit facility while in 1996 most of the activity was dividend payments. In 1996 and 1995 the Company reduced its debt under this facility by $1.0 million and $19.0 million, respectively. In 1994 the Company's debt under this facility increased $99 million, including $78.5 million to partially fund the WERCO acquisition, $6.2 million to purchase additional drilling locations in connection with the 1993 acquisition of proved properties from Emax Oil Company ("Emax"), and $7.1 million for other property acquisitions and capital expenditures. Since June 1995, the Company's available credit line under the revolving credit facility has been $235 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 $168 million at December 31, 1996. The Company's 1997 interest expense is projected to be approximately $19 million. No principal payments are due in 1997. Capitalization information on the Company is as follows:
(In millions) 1996 1995 1994 ------------------------------------------------------------------------------------------- Long-Term Debt $ 248.0 $ 249.0 $ 268.3 Stockholders' Equity Common Stock 69.4 56.6 151.8 Preferred Stock 91.3 91.3 91.3 -------- ------- -------- Total 160.7 147.9 243.1 -------- ------- -------- Total Capitalization $ 408.7 $ 396.9 $ 511.4 ======== ======= ======== Debt to Capitalization 60.7% 62.7% 52.5% -------- ------- --------
20 22 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, 1996.
(In millions) 1996 1995 1994 ------------------------------------------------------------------------------------------- Capital Expenditures: Drilling and Facilities $ 42.7 $ 19.3 $ 47.9 Leasehold Acquisitions 4.3 2.0 4.7 Pipeline and Gathering 6.3 2.2 8.9 Other 0.7 1.2 2.3 -------- ------- -------- 54.0 24.7 63.8 -------- ------- -------- Proved Property Acquisitions 6.6 -- 8.9 WERCO Acquisition (5.3)(1) (8.4)(2) 216.2(3) -------- ------- -------- 1.3 (8.4) 225.1 -------- ------- -------- Exploration Expenses 12.6 8.0 8.0 -------- ------- -------- Total $ 67.9 $ 24.3 $ 296.9 ======== ======= ========
- --------- (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) Included in capital expenditures for the WERCO acquisition was $97.5 million in common and preferred stock of the Company and a $40.2 million non-cash component described in note (1). The substantial reduction in 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 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 1997 have been increased 7% compared with 1996. Depending on the level of future natural gas prices, the Company intends to review and adjust the capital and exploration expenditures planned for 1997 as industry conditions dictate. Presently, the Company projects $78 million in capital and exploration expenditures for 1997. The Company plans to drill 256 wells (167 net), compared with 196 wells (154 net) drilled in 1996. Capital dedicated to the drilling program for 1997 is $61 million. In addition to the drilling program, other 1997 capital expenditures are planned primarily for producing property acquisitions and for gathering and pipeline infrastructure maintenance and construction. During 1996, dividends were paid on the Company's common stock totaling $3.6 million, on the $3.125 convertible preferred stock totaling $2.2 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 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. 21 23 OTHER ISSUES AND CONTINGENCIES Encogen Gas Contract. See Item 3. Legal Proceedings on page 15 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 $1.02 per Mmbtu in 1996. In 1995 and 1996, the Company completed three transactions to monetize the value of these tax credits, resulting in revenues of $3.4 million in 1996 and approximately $20 million over the remaining six 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 revolving credit facility specifies 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, 1996 the calculated ratio for 1996 was 4.8 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 1996 produced natural gas sales price increased 34% compared to 1995 and is the predominant reason for its record 1996 earnings and operating cash flow performance since becoming a public company in 1990. While prices in most regions of the U.S. moved up sharply in November and December 1996, price volatility in the gas market has remained prevalent in the last few years, as demonstrated most recently in the first two months of 1997 with wide price swings in day-to-day trading on the NYMEX futures market. Given this continued price volatility, management cannot predict with certainty what pricing levels will be for the rest of 1997 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 1997 plans include an increase in capital spending, potentially negative changes in industry conditions might require the Company to adjust its 1997 spending plan to ensure the adequate funding of its capital requirements, including, among other things, reductions in capital expenditures or common stock dividends. 22 24 The Company believes its capital resources, supplemented, if necessary, with external financing, are adequate to meet its capital requirements. The preceding paragraphs contain forward-looking information. See FORWARD-LOOKING INFORMATION below. * * * FORWARD-LOOKING INFORMATION The statements regarding future financial performance and results and the other statements which are not historical facts contained in this report are forward-looking statements. The words "expect," "project," "estimate," "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. 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 merged its acquired holdings from the WERCO acquisition, located in the Rocky Mountains and the onshore Gulf Coast, with the Company's holdings in the Anadarko Region to form the "Western Region" in 1994. SELECTED FINANCIAL AND OPERATING DATA
(In millions except where specified) 1996 1995 1994 - ----------------------------------------------------------------------------- Net Operating Revenues $ 163.1 $ 121.1 $ 140.3 Operating Expenses 116.0 237.2 125.4 Interest Expense 17.4 24.9 16.7 Net Income (Loss) 15.3 (92.2) (5.4) Earnings (Loss) Per Share $ 0.67 $ (4.05) $ (0.25) Natural Gas Production (Bcf) Appalachia 26.8 27.5 29.7 West 32.0 30.2 28.6 ------- ------- ------- Total Company 58.8 57.7 58.3 ======= ======= ======= Produced Natural Gas Sales Price ($/Mcf) Appalachia $ 2.72 $ 2.22 $ 2.42 West $ 2.02 $ 1.33 $ 1.65 Total Company $ 2.34 $ 1.75 $ 2.04 Crude/Condensate Volume (MBbl) 520 618 687 Price ($/Bbl) $ 21.14 $ 17.95 $ 16.66
23 25 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, 1996.
(In millions) 1996 1995 1994 - ------------------------------------------------------------------------ Net Income (Loss) Before Selected Items $ 12.5 $ (17.3) $ (5.4) 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) $ 15.3 $ (92.2) $ (5.4) ======= ======= ======
1996 AND 1995 COMPARED Net Income (Loss) and Revenues. The Company reported a 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. 24 26 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. 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 totalled $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. 1995 AND 1994 COMPARED Net Income (Loss) and Revenues. The Company reported a net loss in 1995 of $17.3 million, or $0.76 per share, down $11.9 million, or $0.52, compared with 1994, excluding the impact of the selected items. The $74.9 million from special items, or $3.29 per share, 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 operating revenues decreased $8.7 million and $24.3 million, respectively. Natural gas production revenues comprised 84%, or $101.3 million, of total net operating revenues in 1995. The decrease in total net operating revenues was driven primarily by a 14% decrease in the average produced natural gas sales price, and in part by a 1% increase in natural gas production volumes due to higher gas purchased for resale (up 18%) as discussed below. Net income (loss) and operating income (loss), excluding selected items, were similarly impacted by the decline in the average natural gas price, as well as higher financing costs in connection with the 1994 WERCO and 1993 Emax acquisitions. Natural gas production volume in the Appalachian Region was down 2.1 Bcf, or 7%, to 27.5 Bcf due in part to higher pipeline curtailments and normal production declines not fully replaced by new production due primarily to reduced drilling activity in 1995. Natural gas production volumes were up 1.5 Bcf to 30.2 Bcf in the Western Region due primarily to a full year of operating results from the WERCO acquisition. The average Appalachian natural gas production sales price decreased $0.20 per Mcf, or 9%, to $2.22, decreasing net operating revenues by approximately $5.5 million. In the Western Region, the average natural gas production sales price decreased $0.32 per Mcf, or 19%, to $1.33, decreasing net operating revenues by approximately $9.7 million. Because the proportion of lower priced Western Region production sales volume relative to total Company production sales volume was up significantly, the weighted average natural gas production sales price for the total Company decreased $0.29 per Mcf, or 14%, to $1.75. Crude oil and condensate sales were virtually unchanged at 618 MBbl. 25 27 Costs and Expenses. Total costs and expenses, excluding the selected items, decreased $13.5 million, or 6%, due primarily to the following: o The costs of natural gas decreased $3.9 million to $92.8 million. The decrease was primarily due to a $0.42 per Mcf decrease in the average price of gas purchased for resale, partially offset by a 10.4 Bcf increase in gas purchased for resale (including gas exchanges and storage). o Direct operations expense decreased $5.0 million, or 15%, due in large part to reductions in (1) lease maintenance work and workovers, (2) field and regional office expenses due primarily to the cost reduction program, and (3) compressor rental and overhaul expenses. o Depreciation, depletion, amortization and impairment expense, excluding the $113.8 million impairment of long-lived assets in connection with SFAS 121, decreased $2.3 million due primarily to the decrease in the DD&A rate in the fourth quarter resulting from the SFAS 121 impairment. Due to the adoption of SFAS 121, the Company's DD&A rate is expected to decrease in future years by $0.13 per Mcfe. o General and administrative expense decreased $1.4 million, or 8%, due largely to costs savings realized from the cost reduction program. o The cost reduction program, recorded in the first quarter, consisted primarily of a 23% staff reduction, achieved through early retirement and involuntary termination programs. The pre-tax charges related to this action totalled $6.8 million, comprised of $3.8 million in salary and other severance related expense ($3.6 million paid during the nine months) and a $3.0 million non-cash charge for the impact of the staff reduction to the pension and postretirement benefits plans. o Taxes other than income decreased $0.9 million, or 7.6%, due primarily to the decline in gas revenue. Interest expense was up $8.2 million, or 49%, due to the increase in debt primarily attributable to the WERCO acquisition in 1994 and the Emax acquisition in 1993. Income tax benefit was up $54.4 million due to the comparable decrease in earnings before income tax. The Company's effective tax rate was virtually unchanged. 26 28 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page - -------------------------------------------------------------------------- Report of Independent Accountants 28 Consolidated Statement of Operations 29 Consolidated Balance Sheet 30 Consolidated Statement of Cash Flows 31 Consolidated Statement of Stockholders' Equity 32 Notes to Consolidated Financial Statements 33 Supplemental Oil & Gas Information (Unaudited) 49 Quarterly Financial Information (Unaudited) 53
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 judgements 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. March 7, 1997 Charles P. Siess, Jr. Chairman of the Board, Chief Executive Officer and President 27 29 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, 1996 and 1995, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 1996. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Cabot Oil & Gas Corporation as of December 31, 1996 and 1995, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 1996, 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 7, 1997 28 30 CABOT OIL & GAS CORPORATION CONSOLIDATED STATEMENT OF OPERATIONS
Year Ended December 31, (In thousands, except per share amounts) 1996 1995 1994 - --------------------------------------------------------------------------------------- NET OPERATING REVENUES Natural Gas Production $ 137,482 $ 101,260 $ 119,076 Crude Oil and Condensate 10,992 11,089 11,445 Brokered Natural Gas Margin 5,619 2,509 3,802 Other 8,968 6,225 5,972 --------- --------- --------- 163,061 121,083 140,295 OPERATING EXPENSES Direct Operations 28,361 28,328 33,332 Exploration 12,559 8,031 8,014 Depreciation, Depletion and Amortization 42,689 47,206 51,040 Impairment of Long-Lived Assets (Note 15) -- 113,795 -- Impairment of Unproved Properties 2,701 5,047 3,556 General and Administrative 16,823 16,785 17,278 Cost Reduction Program (Note 12) -- 6,820 -- Taxes Other Than Income 12,826 11,215 12,141 --------- --------- --------- 115,959 237,227 125,361 Gain (Loss) on Sale of Assets 1,685 (614) 79 --------- --------- --------- INCOME (LOSS) FROM OPERATIONS 48,787 (116,758) 15,013 Interest Expense 17,409 24,885 16,651 --------- --------- --------- Income (Loss) Before Income Tax Expense 31,378 (141,643) (1,638) Income Tax Expense (Benefit) 10,554 (55,025) (643) --------- --------- --------- NET INCOME (LOSS) 20,824 (86,618) (995) Dividend Requirement on Preferred Stock 5,566 5,553 4,449 --------- --------- --------- Net Income (Loss) Applicable to Common Stockholders $ 15,258 $ (92,171) $ (5,444) ========= ========= ========= Earnings (Loss) Per Share Applicable to Common Stockholders $ 0.67 $ (4.05) $ (0.25) ========= ========= ========= Average Common Shares Outstanding 22,807 22,775 22,018 ========= ========= =========
- --------- The accompanying notes are an integral part of these consolidated financial statements. 29 31 CABOT OIL & GAS CORPORATION CONSOLIDATED BALANCE SHEET
December 31, (In thousands) 1996 1995 - ------------------------------------------------------------------------------------ ASSETS CURRENT ASSETS Cash and Cash Equivalents $ 1,367 $ 3,029 Accounts Receivable 67,810 42,014 Inventories 8,797 5,596 Other 1,663 1,709 --------- --------- Total Current Assets 79,637 52,348 PROPERTIES AND EQUIPMENT (Successful Efforts Method) 480,511 474,371 OTHER ASSETS 1,193 1,436 --------- --------- $ 561,341 $ 528,155 ========= ========= LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES Accounts Payable $ 56,338 $ 48,122 Accrued Liabilities 16,279 12,759 --------- --------- Total Current Liabilities 72,617 60,881 LONG-TERM DEBT 248,000 249,000 DEFERRED INCOME TAXES 69,427 62,752 OTHER LIABILITIES 10,593 7,666 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; 692,439 Shares in 1996 and 1995 -- 6% Convertible Redeemable Preferred; $50 Stated Value; 1,134,000 Shares in 1996 and 1995 183 183 Common Stock: Authorized -- 40,000,000 Shares of $0.10 Par Value Issued and Outstanding -- 22,847,345 Shares and 22,783,319 Shares at December 31, 1996 and 1995, respectively 2,284 2,278 Class B Common Stock: Authorized -- 800,000 Shares of $0.10 Par Value No Shares Issued -- -- Additional Paid-in Capital 243,283 242,058 Accumulated Deficit (85,046) (96,663) --------- --------- Total Stockholders' Equity 160,704 147,856 --------- --------- $ 561,341 $ 528,155 ========= =========
- --------- The accompanying notes are an integral part of these consolidated financial statements. 30 32 CABOT OIL & GAS CORPORATION CONSOLIDATED STATEMENT OF CASH FLOWS
Year Ended December 31, (In thousands) 1996 1995 1994 - -------------------------------------------------------------------------------------------- CASH FLOWS FROM OPERATING ACTIVITIES Net Income (Loss) $ 20,824 $ (86,618) $ (995) Adjustments to Reconcile Net Income (Loss) to Cash Provided by Operations: Depletion, Depreciation, and Amortization 42,689 47,206 51,040 Impairment of Long-Lived Assets -- 113,795 -- Impairment of Unproved Properties 2,701 5,047 3,556 Deferred Income Tax Expense (Benefit) 12,017 (55,055) (796) Loss (Gain) on Sale of Assets (1,685) 614 (79) Exploration Expense 12,559 8,031 8,014 Other, Net 176 3,178 (1,535) Changes in Assets and Liabilities: Accounts Receivable (25,796) (3,848) (2,870) Inventories (3,201) 2,788 (2,691) Other Current Assets 46 (13) (944) Other Assets 243 (37) (1,306) Accounts Payable and Accrued Liabilities 11,199 5,838 16,167 Other Liabilities 3,713 565 (258) --------- --------- --------- Net Cash Provided by Operations 75,485 41,491 67,303 --------- --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES Capital Expenditures (60,719) (24,672) (72,684) Cost of Major Acquisition(1) -- 8,402 (78,525) Proceeds from Sale of Assets 5,725 10,291 400 Exploration Expense (12,559) (8,031) (8,014) --------- --------- --------- Net Cash Used by Investing (67,553) (14,010) (158,823) --------- --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES Increase in Debt 6,000 16,000 125,833 Decrease in Debt (7,000) (35,363) (27,000) Exercise of Stock Options 613 348 654 Preferred Dividends Paid (5,566) (5,566) (3,550) Common Dividends Paid and Other, Net (3,641) (3,644) (3,541) --------- --------- --------- Net Cash Provided (Used) by Financing (9,594) (28,225) 92,396 --------- --------- --------- Net Increase (Decrease) in Cash and Cash Equivalents (1,662) (744) 876 Cash and Cash Equivalents, Beginning of Year 3,029 3,773 2,897 --------- --------- --------- Cash and Cash Equivalents, End of Year $ 1,367 $ 3,029 $ 3,773 ========= ========= =========
- --------- (1) Excludes non-cash consideration of $97.5 million of the Company's common and preferred stock issued in connection with the WERCO acquisition. See Note 11 WERCO Acquisition. The accompanying notes are an integral part of these consolidated financial statements. 31 33 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, 1993 $ 2,058 $ 69 $143,264 $ 8,138 $ 153,529 Net Loss (995) (995) Exercise of Stock Options 4 650 654 Issuance of Common Stock 213 40,546 40,759 Issuance of Preferred Stock 114 56,586 56,700 Preferred Stock Dividends (4,449) (4,449) Common Stock Dividends at $0.16 Per Share (3,551) (3,551) Tax Benefit of Stock Options 425 425 Other 10 10 ------- ----- -------- -------- --------- Balance at December 31, 1994 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, 1995 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, 1996 $ 2,284 $ 183 $243,283 $(85,046) $ 160,704 ======= ===== ======== ======== =========
- --------- The accompanying notes are an integral part of these consolidated financial statements. 32 34 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. The results of operations of oil and gas properties purchased in the acquisition of Washington Energy Resources Company ("WERCO") have been included with those of the Company since May 2, 1994. 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 the sum of expected future net cash flows is less than the net book value (See Note 15 Accounting For Long-Lived Assets). 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 33 35 when a group of proved properties (or field), constituting the amortization base, has been retired, abandoned or sold. 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 $10.4 million and $6.2 million at December 31, 1996 and 1995, respectively. EARNINGS (LOSS) PER COMMON SHARE Earnings (loss) per common share is computed by dividing net income (loss), less dividends on preferred stock, by the weighted average number of shares of common stock ("Common Stock") outstanding during the respective periods. The dilutive effect of stock options on earnings per common share is insignificant for all periods and is not included in the computation of earnings per common share. 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. RISK MANAGEMENT ACTIVITIES From time to time, the Company enters into certain commodity derivative contracts as a hedging strategy to manage commodity price risk associated with its inventories, production or other contractual commitments. The natural gas price swap is the type of derivative instrument utilized by the Company. A natural gas price swap is an agreement between two parties to exchange periodic payments, usually on a monthly basis. One party pays a fixed price while the other party typically pays a variable price. Notional quantities of natural gas 34 36 are used in each agreement, as the agreements do not involve the physical exchange or delivery of natural gas. Gains or losses on these hedging activities are generally recognized over the period that the inventory, production or other underlying commitment is hedged. Unrealized gains or losses associated with any natural gas price swap contracts not considered to be a hedge are recognized currently in the results of operations. 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 years ended 1995 and 1994 have been reclassified to conform with the 1996 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) 1996 1995 - ------------------------------------------------------------ Unproved Oil and Gas Properties $ 15,746 $ 12,488 Proved Oil and Gas Properties 811,726 800,373 Gathering and Pipeline Systems 150,910 146,330 Land, Building and Improvements 5,221 5,551 Other 16,028 15,243 --------- --------- 999,631 979,985 Accumulated Depreciation, Depletion and Amortization (519,120) (505,614) --------- --------- $ 480,511 $ 474,371 ========= =========
As a component of accumulated depreciation, depletion and amortization, total accrued future plug and abandonment cost was $14.8 million and $15.0 million at December 31, 1996 and 1995, respectively. The Company believes that this accrual adequately provides for its estimated future plug and abandonment cost. 35 37 3. ADDITIONAL BALANCE SHEET INFORMATION Certain balance sheet amounts are comprised of the following:
December 31, (In thousands) 1996 1995 - ------------------------------------------------------------------------ Accounts Receivable Trade Accounts $ 63,458 $ 38,119 Other Accounts 5,021 5,138 -------- -------- 68,479 43,257 Allowance for Doubtful Accounts (669) (1,243) -------- -------- $ 67,810 $ 42,014 ======== ======== Accounts Payable Trade Accounts $ 12,277 $ 9,312 Natural Gas Purchases 20,726 12,523 Royalty and Other Owners 13,469 10,842 Capital Costs 5,409 6,518 Dividends Payable 1,391 1,391 Taxes Other Than Income 1,170 749 Gas Price Swaps (Note 13) -- 3,205 Other Accounts 1,896 3,582 -------- -------- $ 56,338 $ 48,122 ======== ======== Accrued Liabilities Employee Benefits $ 4,432 $ 2,506 Taxes Other Than Income 8,407 7,633 Interest Payable 2,188 1,883 Other Accrued 1,252 737 -------- -------- $ 16,279 $ 12,759 ======== ======== Other Liabilities Postretirement Benefits Other Than Pension $ 1,853 $ 2,640 Accrued Pension Cost 4,022 3,144 Taxes Other Than Income and Other 4,718 1,882 -------- -------- $ 10,593 $ 7,666 ======== ========
4. INVENTORIES Inventories are comprised of the following:
December 31, (In thousands) 1996 1995 - --------------------------------------------------------- Natural Gas in Storage $ 7,312 $ 4,058 Tubular Goods and Well Equipment 1,677 1,485 Pipeline Exchange Balances (192) 53 ------- ------- $ 8,797 $ 5,596 ======= =======
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 more favorable rate, prime rate minus 1% versus prime rate, the terms of the new line of 36 38 credit are comparable to the previous line of credit. At December 31, 1996 and 1995, 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 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. 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 or the repurchase of equity securities. Such covenants about dividends and equity securities are less restrictive than the covenants contained in the Credit Facility referred to below. REVOLVING CREDIT AGREEMENT In January 1990, the Company entered into an $85 million Revolving Credit Agreement (the "Credit Facility") with a bank (later expanded to five banks and a $260 million available line of credit). In 1995, the Company amended its Credit Facility decreasing the available credit line to $235 million. 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 1996, the revolving term under the Credit Facility was extended one year to June 1998. 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, 1996, 1995 and 1994 were 6.6%, 6.8% and 5.7%, respectively. Although the revolving term of the Credit Facility expires in June 1998, 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. 37 39 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, 1996, 1995 and 1994 are comprised of the following:
(In thousands) 1996 1995 1994 - ------------------------------------------------------------------------------- QUALIFIED: Current Year Service Cost $ 737 $ 722 $ 901 Interest Accrued on Pension Obligation 744 742 652 Actual Return on Plan Assets (948) (1,327) (428) Net Amortization 448 934 102 Curtailment Gain -- (376) -- Special Termination Benefit -- 766 -- ------- ------- ------- Net Periodic Pension Cost $ 981 $ 1,461 $ 1,227 ======= ======= ======= NON-QUALIFIED: Current Year Service Cost $ 90 $ 63 $ 134 Interest Accrued on Pension Obligation 6 23 32 Net Amortization 34 39 49 Curtailment Loss -- 37 -- Settlement Charge -- 174 -- ------- ------- ------- Net Periodic Pension Cost $ 130 $ 336 $ 215 ======= ======= =======
The following table sets forth the funded status of the Company's pension plans at December 31, 1996 and 1995, respectively:
1996 1995 (In thousands) Qualified Non-Qualified Qualified Non-Qualified - -------------------------------------------------------------------------------------------------- Actuarial Present Value of: Vested Benefit Obligation $ 6,946 $ 31 $ 6,281 $ 65 Accumulated Benefit Obligation 7,621 81 6,864 83 Projected Benefit Obligation $ 10,960 $ 81 $ 10,069 $ 83 Plan Assets at Fair Value 7,074 -- 6,417 -- -------- -------- -------- -------- Projected Benefit Obligation in Excess of Plan Assets 3,886 81 3,652 83 Unrecognized Net Gain 1,750 140 1,232 44 Unrecognized Prior Service Cost (950) (386) (1,037) (423) -------- -------- -------- -------- Accrued (Prepaid) Pension Cost $ 4,686 $ (165) $ 3,847 $ (296) ======== ======== ======== ========
38 40 Assumptions used to determine benefit obligations and pension costs are as follows:
1996 1995 1994 - --------------------------------------------------------------------------- Discount Rate 7.50% 7.50%(1) 8.50% Rate of Increase in Compensation Levels 4.50% 4.50%(1) 5.50% 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, $0.8 million and $0.9 million in 1996, 1995 and 1994, 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 295 retirees and 273 retirees at the end of 1996 and 1995, 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 1996, 1995 and 1994, 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, 1996, 1995 and 1994 are comprised of the following:
(In thousands) 1996 1995 1994 - ----------------------------------------------------------------------------------------------------------- Service Cost of Benefits Earned During the Year $ 99 $ 140 $ 152 Interest Cost on the Accumulated Postretirement Benefit Obligation 522 517 470 Amortization Benefit of the Unrecognized Gain (163) (249) (207) Amortization Cost (Benefit) of the Unrecognized Transition Obligation (807) (821) (859) Curtailment Loss -- 2,074 -- Special Termination -- 503 -- ------- ------- ------- Total Postretirement Benefit Cost (Benefit) $ (349) $ 2,164 $ (444) ======= ======= =======
The health care cost trend rate used to measure the expected cost in 1997 for medical benefits to retirees over age 65 was 8.4%, 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 9.5%, 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, 1996 and 1995 was 7.5%. 39 41 A one-percentage-point increase in health care cost trend rates for future periods would increase the accumulated net postretirement benefit obligation by approximately $216 thousand and, accordingly, the total postretirement benefit cost recognized in 1996 would have also increased by approximately $23 thousand. The funded status of the Company's postretirement benefit obligation at December 31, 1996 and 1995 is comprised of the following:
(In thousands) 1996 1995 - -------------------------------------------------------------------------------- Plan Assets at Fair Value $ -- $ -- Accumulated Postretirement Benefits Other Than Pensions Retirees 5,681 5,512 Active Participants 1,526 1,722 ------- ------- 7,207 7,234 Unrecognized Cumulative Net Gain 2,614 2,546 Unrecognized Transition Obligation (7,587) (6,779) ------- ------- Accrued Postretirement Benefit Liability $ 2,234 $ 3,001 ======= =======
7. INCOME TAXES Income tax expense (benefit) is summarized as follows:
Year Ended December 31, (In thousands) 1996 1995 1994 - --------------------------------------------------------------------------- CURRENT: Federal $ (1,229) $ -- $ -- State 316 30 153 -------- -------- -------- Total (913) 30 153 -------- -------- -------- DEFERRED: Federal 9,756 (46,430) (1,987) State 1,711 (8,625) 1,191 -------- -------- -------- Total 11,467 (55,055) (796) -------- -------- -------- Total Income Tax Expense (Benefit) $ 10,554 $(55,025) $ (643) ======== ======== ========
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) 1996 1995 1994 - --------------------------------------------------------------------------------------- Statutory Federal Income Tax Rate 35% 35% 35% Computed "Expected" Federal Income Tax $ 10,982 $(49,575) $ (574) State Income Tax, Net of Federal Income Tax 1,317 (5,586) 873 Other, Net (1,745) 136 (942) -------- -------- -------- Total Income Tax Expense (Benefit) $ 10,554 $(55,025) $ (643) ======== ======== ========
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. 40 42 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, 1996 and 1995 were as follows:
(In thousands) 1996 1995 - ---------------------------------------------------------------------------- DEFERRED TAX LIABILITIES: Property, Plant and Equipment $ 115,099 $ 110,582 --------- --------- DEFERRED TAX ASSETS: Alternative Minimum Tax Credit Carryforwards 3,786 4,614 Net Operating Loss Carryforwards 17,708 22,620 Note Receivable on Section 29 Monetization(1) 18,347 15,048 Items Accrued for Financial Reporting Purposes 5,831 5,548 --------- --------- 45,672 47,830 --------- --------- Net Deferred Tax Liabilities $ 69,427 $ 62,752 ========= =========
- ---------- (1) As a result of the monetization of Section 29 tax credits in 1996 and 1995, 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, 1996, the Company has a net operating loss carryforward for regular income tax reporting purposes of $50.1 million which will begin expiring in 2009. In addition, the Company has an alternative minimum tax credit carryforward of $3.8 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 totalled $4.8 million, $4.9 million and $5.5 million for the years ended December 31, 1996, 1995 and 1994, respectively. Future minimum rental commitments under non-cancelable leases in effect at December 31, 1996 are as follows:
(In thousands) 1997 $ 3,364 1998 2,723 1999 1,916 2000 1,051 2001 695 Thereafter 1,080 -------- $ 10,829 ========
Minimum rental commitments are not reduced by minimum sublease rental income of $1.8 million due in the future under non-cancelable subleases. CONTINGENCIES The Company is a defendant in various lawsuits and is involved in other gas contract issues. In the opinion of the Company, final judgements 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. 41 43 The Company sells approximately 20% of its natural gas production 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) 1996 1995 1994 - ------------------------------------------------------------------------ Interest $ 17,105 $ 24,744 $ 16,002 Income Taxes $ 873 $ 197 $ 210
At December 31, 1996 and 1995, 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. 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 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:
December 31, 1996 1995 1994 - ------------------------------------------------------------------ Shares Under Option at Beginning of Period 1,310,318 953,775 684,525 Granted 311,750 565,750 301,900 Exercised 41,094 2,400 12,050 Surrendered or Expired 48,621 206,807 20,600 --------- --------- --------- Shares Under Option at End of Period 1,532,353 1,310,318 953,775 ========= ========= ========= Option Price Range per Share $ 13.25 - $ 13.25 - $ 13.25 - 26.00 26.00 26.00 Options Exercisable at End of Period 1,021,362 852,692 447,907 ========= ========= =========
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. 42 44 The pro forma results of operations, had the Company adopted SFAS 123, were net income of $14.8 million, or $0.65 per share, in 1996 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 1996 and 1995 were $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 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 1996 and 1995 are 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, 1996, such restrictions had no adverse impact on the Company's ability to pay regular dividends. 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 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, 1996, 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 and 1995, 692,439 shares of the Company's $3.125 cumulative convertible preferred stock ("$3.125 preferred stock") were issued and outstanding. Each share has a stated value of $50 and is convertible any time by the holder into Common Stock at a conversion price of $21 per share, subject to adjustment. The $3.125 preferred stock is redeemable by the Company for a stated redemption price per share, starting at $55 per share in 1993 and declining to $50 per share in 2003, plus accrued dividends. Prior to May 31, 1997, the Company's option to redeem the $3.125 preferred stock is subject to a provision that the Common Stock closing price must equal at least 130% of the conversion price for 20 of 30 consecutive trade days. The 43 45 Company also has the option to convert the $3.125 preferred stock to Common Stock at the conversion price provided the Company has the right to redeem the $3.125 preferred stock, as described above, and the closing price of the Common Stock is at least equal to the conversion price for 20 consecutive trading days. 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. 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 termination's 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. 44 46 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, 1996 December 31, 1995 Carrying Estimated Carrying Estimated (In thousands) Amount Fair Value Amount Fair Value - ----------------------------------------------------------------------------------- DEBT: 10.18% Notes $ 80,000 $ 86,433 $ 80,000 $ 89,258 Credit Facility 168,000 168,000 169,000 169,000 --------- --------- --------- --------- $ 248,000 $ 254,433 $ 249,000 $ 258,258 ========= ========= ========= ========= OTHER FINANCIAL INSTRUMENTS: Gas Price Swaps -- $ 763 -- $ (4,176)
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 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. 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 including a $2.6 million charge in December 1995 when cash payments were made to close out the remaining swap positions. GAS PRICE SWAPS The Company has entered into several price swap agreements with counterparties. In a majority of the natural gas price swap agreements, the Company receives 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. 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. Excluding the 'uncovered' hedge contracts, the estimated fair value of price swaps in the table above are 45 47 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). After entering into certain fixed price sales contracts to meet the needs of its customers, the Company opened gas swap agreements to convert these fixed price contracts to market-sensitive price contracts. During 1996, these agreements had total notional quantities of 1,002,000 Mmbtu in closed contracts and another 744,000 Mmbtu in open contracts at December 31, 1996. 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. 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 $113.8 million ($69.2 million after tax). 16. SALE OF NON-CORE OIL AND GAS PROPERTIES 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. 46 48 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 ($3.4 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 until the production payment is satisfied. 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 $15.7 million, $12.5 million, and $20.8 million at December 31, 1996, 1995, and 1994, 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). 47 49
1996 1995 1994 --------------------- ------------------------ ------------------------ Successful Full Successful Full Successful Full (In thousands, except per share amounts) Efforts Cost Efforts Cost Efforts Cost - ------------------------------------------------------------------------------------------------------------------------- BALANCE SHEET: Properties and Equipment, Net $ 480,511 $ 657,957 $ 474,371 $ 646,322 $ 634,934 $ 684,114 Stockholders' Equity 160,704 269,833 147,856 253,606 243,082 273,328 INCOME STATEMENT: Depreciation, Depletion, Amortization and Unproved Property Impairment $ 45,390 $ 50,769 $ 52,253 $ 51,922 $ 54,596 $ 56,027 Impairment of Long-Lived Assets -- -- 113,795 -- -- -- Impairment - Full Cost Ceiling -- -- -- -- -- 76,100 Net Income (Loss) Applicable to Common Stockholders 15,258 18,637 (92,171) (17,481) (5,444) (48,245) Earnings (Loss) Per Share $ 0.67 $ 0.82 $ (4.05) $ (0.77) $ (0.25) $ (2.19)
48 50 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, 1996, 1995 and 1994 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 10, 1997 that, based on their investigation and subject to the limitations described in such letter, it was their judgement that the results of those estimates and projections for 1996 were reasonable in the aggregate. No major discovery or other favorable or adverse event subsequent to December 31, 1996 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 (more than 99%) or Canada.
Natural Gas ------------------------------------- December 31, (Millions of cubic feet) 1996 1995 1994 - ------------------------------------------------------------------------------------------ PROVED RESERVES Beginning of Year 889,850 953,083 808,280 Revisions of Prior Estimates 2,774 14,032 (24,627) Extensions, Discoveries and Other Additions 69,708 34,408 64,829 Production (58,762) (57,721) (58,319) Purchases of Reserves in Place 37,397 1,416 168,957 Sales of Reserves in Place (25,350) (55,368) (6,037) --------- --------- --------- End of Year 915,617 889,850 953,083 ========= ========= ========= PROVED DEVELOPED RESERVES 768,097 747,235 805,913 ========= ========= =========
49 51
Liquids ---------------------------------------- December 31, (Thousands of barrels) 1996 1995 1994 - ---------------------------------------------------------------------------------------------- PROVED RESERVES Beginning of Year 5,310 8,036 2,826 Revisions of Prior Estimates (132) (648) (98) Extensions, Discoveries and Other Additions 386 174 181 Production (597) (740) (824) Purchases of Reserves in Place 215 15 5,992 Sales of Reserves in Place (16) (1,527) (41) -------- -------- -------- End of Year 5,166 5,310 8,036 ======== ======== ======== PROVED DEVELOPED RESERVES 4,685 4,970 7,704 ======== ======== ========
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) 1996 1995 1994 - ------------------------------------------------------------------------------ Aggregate Capitalized Costs Relating to Oil and Gas Producing Activities $ 997,531 $ 977,885 $ 980,676 Aggregate Accumulated Depreciation, Depletion and Amortization $ 517,249 $ 503,757 $ 346,080
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) 1996 1995 1994 - ------------------------------------------------------------------------------------ Property Acquisition Costs - Proved $ 6,637 $ 33 $ 184,835 Property Acquisition Costs - Unproved 4,355 2,006 4,685 Exploration and Extension Well Costs 14,192 8,670 9,402 Development Costs 41,036 18,610 46,463 --------- --------- --------- Total costs $ 66,220 $ 29,319 $ 245,385 ========= ========= =========
50 52 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) 1996 1995 1994 - -------------------------------------------------------------------------- Operating Revenues $ 150,096 $ 110,418 $ 126,307 Costs and Expenses Production 35,161 34,062 39,114 Other Operating 15,155 22,783 16,787 Exploration 12,559 8,031 8,014 Depreciation, Depletion and Amortization 40,810 161,886 48,075 --------- --------- --------- Total Cost and Expenses 103,685 226,762 111,990 --------- --------- --------- Income (Loss) Before Income Taxes 46,411 (116,344) 14,317 Provision for Income Taxes Expense (Benefit) 16,244 (40,720) 5,011 --------- --------- --------- Results of Operations $ 30,167 $ (75,624) $ 9,306 ========= ========= =========
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, 1996, 1995 and 1994 were for oil ($/Bbl) $22.86, $17.06 and $18.34, respectively, and for natural gas ($/Mcf) $3.55, $2.06 and $1.88, 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. 51 53 Standardized Measure is as follows:
Year Ended December 31, (In thousands) 1996(1) 1995(1) 1994 - ------------------------------------------------------------------------------------------ Future Cash Inflows $ 3,528,558 $ 2,194,751 $ 2,219,559 Future Production and Development Costs (773,631) (644,586) (723,767) ----------- ----------- ----------- Future Net Cash Flows Before Income Taxes 2,754,927 1,550,165 1,495,792 10% Annual Discount for Estimated Timing of Cash Flows (1,589,290) (884,861) (880,130) ----------- ----------- ----------- Standardized Measure of Discounted Future Net Cash Flows Before Income Taxes 1,165,637 665,304 615,662 Future Income Tax Expenses, Net of 10% Annual Discount(2) (331,331) (152,356) (125,167) ----------- ----------- ----------- Standardized Measure of Discounted Future Net Cash Flows $ 834,306 $ 512,948 $ 490,495 =========== =========== ===========
(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 $887,583, $462,058 and $433,212 for the years ended December 31, 1996, 1995 and 1994, respectively. 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) 1996 1995 1994 - ------------------------------------------------------------------------------------------ Beginning of Year $ 512,948 $ 490,495 $ 467,900 Discoveries and Extensions, Net of Related Future Costs 99,983 21,881 24,188 Net Changes in Prices and Production Costs 416,042 57,057 (133,750) Accretion of Discount 66,530 61,566 64,110 Revisions of Previous Quantity Estimates, Timing and Other (7,874) 1,707 (32,654) Development Costs Incurred 10,294 5,665 16,631 Sales and Transfers, Net of Production Costs (114,935) (76,356) (87,193) Net Purchases (Sales) of Reserves in Place 30,293 (21,878) 123,232 Net Change in Income Taxes (178,975) (27,189) 48,031 --------- --------- --------- End of Year $ 834,306 $ 512,948 $ 490,495 ========= ========= =========
52 54 CABOT OIL & GAS CORPORATION QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
(In thousands except per share amounts) First Second Third Fourth Total - --------------------------------------------------------------------------------------------------------------- 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 Earnings Per Share $ 0.23 $ 0.04 $ 0.13 $ 0.27 $ 0.67 1995 Net Operating Revenues $ 32,587 $ 29,621 $ 29,623 $ 29,252 $ 121,083 Operating Income (Loss) (5,366) (680) (111,708)(1) 996 (116,758) Net Loss (8,200) (5,291) (73,309)(1) (5,371) (92,171) Loss Per Share $ (0.36) $ (0.23) $ (3.22) $ (0.24) $ (4.05)
- ---------- (1) Includes a $113.8 million charge ($69.2 million after tax) for the impairment of long-lived assets resulting from the adoption of SFAS 121. 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 1997 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. 53 55 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, SCHEDULES AND REPORTS ON FORM 8-K A. INDEX 1. CONSOLIDATED FINANCIAL STATEMENTS See Index on page 27 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 $3.125 Convertible Preferred Stock (Form 10-K for 1993). 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. 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 Certificate of Designation for 6% Convertible Redeemable Preferred Stock (Form 10-K for 1994). 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). 10.7 Transaction Agreement between Cabot Corporation and the Company dated February 1, 1991 (Registration Statement No. 33-37455). 54 56 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. 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). 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 10, 1997. B. REPORTS ON FORM 8-K None 55 57 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 1997. CABOT OIL & GAS CORPORATION By: /s/ Charles P. Siess, Jr. -------------------------------- Charles P. Siess, Jr. Chairman of the Board, Chief Executive Officer and President 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, March 10, 1997 - -------------------------------- Chief Executive Officer and President Charles P. Siess, Jr (Principal Executive Officer) /s/ Ray R. Seegmiller Executive Vice President, Chief Operating March 10, 1997 - -------------------------------- Officer and Treasurer Ray R. Seegmiller /s/ Paul F. Boling Controller (Principal Accounting Officer) March 10, 1997 - -------------------------------- Paul F. Boling /s/ Robert F. Bailey Director March 10, 1997 - -------------------------------- Robert F. Bailey /s/ Samuel W. Bodman Director March 10, 1997 - -------------------------------- Samuel W. Bodman /s/ Henry O. Boswell Director March 10, 1997 - -------------------------------- Henry O. Boswell /s/ John G. L. Cabot Director March 10, 1997 - -------------------------------- John G. L. Cabot /s/ William R. Esler Director March 10, 1997 - -------------------------------- William R. Esler /s/ William H. Knoell Director March 10, 1997 - -------------------------------- William H. Knoell /s/ C. Wayne Nance Director March 10, 1997 - -------------------------------- C. Wayne Nance /s/ William P. Vititoe Director March 10, 1997 - -------------------------------- William P. Vititoe
56 58 INDEX TO EXHIBITS
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 $3.125 Convertible Preferred Stock (Form 10-K for 1993). 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. 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 Certificate of Designation for 6% Convertible Redeemable Preferred Stock (Form 10-K for 1994). 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). 10.7 Transaction Agreement between Cabot Corporation and the Company dated February 1, 1991 (Registration Statement No. 33-37455).
59 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. 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). 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 10, 1997.
EX-4.5B 2 AMENDED & RESTATED CREDIT AGREEMENT DATED 5/30/95 1 EXHIBIT 4.5(b) [CONFORMED COPY] AMENDMENT NO. 2 TO CREDIT AGREEMENT AMENDMENT dated as of December 24, 1996 to the Amended and Restated Credit Agreement dated as of May 30, 1995 (as heretofore amended, the "Agreement") among Cabot Oil & Gas Corporation, the Banks listed on the signature pages thereof and Morgan Guaranty Trust Company of New York, as Agent. W I T N E S S E T H: WHEREAS, the parties hereto desire to amend the Agreement as set forth below; NOW, THEREFORE, the parties hereto agree as follows: SECTION 1. Definitions, References. Unless otherwise specifically defined herein, each term used herein which is defined in the Agreement shall have the meaning assigned to such term in the Agreement. Each reference therein to "this Agreement", "hereof", "hereunder", "herein" and "hereby" and each similar reference contained in the Agreement shall from and after the date hereof refer to the Agreement as amended hereby. SECTION 2. Amendment of the Agreement. The Agreement is amended as follows: (a) The phrases "not less than 60 days prior to such Extension Date" and "within 30 days prior to such Extension Date" appearing in Section 2.13 are changed to "not later than April 15 preceding such Extension Date" and "not later than May 15 preceding such Extension Date", respectively. (b) The dates "April 1" and October 1" appearing in Section 5.09(a) are changed to "March 15" and "September 15", respectively and the phrase "commencing October 1, 1995," appearing in Section 5.09(a) is deleted. (c) The number "60" appearing in Section 5.10(b)(ii) is changed to "30". 2 (d) Section 5.13 is amended to read in its entirety as follows: "The Annual Coverage Ratio will at no time be less than 2.8:1. For this purpose: "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 most recently ended on or prior to such date." "Consolidated Cash Flow" means, for any period, the net cash from operating activities of the Borrower 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 (i) consolidated interest charges incurred by the Borrower and its Consolidated Subsidiaries during such period and (ii) income tax expense. "Consolidated Interest Expense" means, for any period, the interest expense of the Borrower and its Consolidated Subsidiaries determined on a consolidated basis for such period in accordance with generally accepted accounting principles. (e) The text of Section 5.14 is deleted in its entirety. SECTION 3. Governing Law. This Amendment shall be governed by and construed in accordance with the laws of the State of New York. SECTION 4. Counterparts; Effectiveness. This Amendment may be signed in any number of counterparts, each of which shall be an original, with the same effect as if the signatures thereto and hereto were upon the same instrument. This Amendment shall become effective as of the date hereof when the Agent shall have received duly executed counterparts hereof signed by the Borrower and the Required Banks (or, in the case of any party as to which an executed counterpart shall not have been received, the Agent shall have received telegraphic, telex or other written 2 3 confirmation from such party of execution of a counterpart hereof by such party). 3 4 IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed as of the date first above written. CABOT OIL & GAS CORPORATION By Scott C. Schroeder ------------------------------ Title: Assistant Treasurer MORGAN GUARANTY TRUST COMPANY OF NEW YORK By Carl J. Mehldau, Jr. ------------------------------ Title: TEXAS COMMERCE BANK NATIONAL ASSOCIATION By Lori Vetters ------------------------------ Title: NATIONSBANK OF TEXAS, N.A. By Kristen B. Palmer ------------------------------ Title: THE FIRST NATIONAL BANK OF BOSTON By Virginia Ryan ------------------------------ Title: 4 5 THE BANK OF MONTREAL By /s/ ROBERT L. ROBERTS ----------------------------- Title: Director MORGAN GUARANTY TRUST COMPANY OF NEW YORK, as Agent By /s/ CARL J. MEHLDAU, JR. ----------------------------- Title: Associate 5 EX-10.10D 3 THIRD - FIFTH AMENDMENTS TO THE SAVINGS INVEST PLN 1 EXHIBIT 10.10(d) CABOT OIL & GAS CORPORATION SAVINGS INVESTMENT PLAN (As Established Effective January 1, 1991) Third Amendment Cabot Oil & Gas Corporation, a Delaware corporation (the "Company"), having established the Cabot Oil & Gas Corporation Savings Investment Plan, effective January 1, 1991 (the "Plan"), and having reserved the right under Section 10.4 thereof to amend the Plan, does hereby amend Section 8 of the Plan, effective January 1, 1993, to add Section 8.5 as follows: "8.5 Member's Right to Transfer Eligible Rollover Distribution: A. Rule: This Section applies to distributions made on or after January 1, 1993. Notwithstanding any provision of the Plan to the contrary that would otherwise limit a distributee's election under this Section, a distributee may elect, at the time and in the manner prescribed by the plan administrator, to have any portion of an eligible rollover distribution paid directly to an eligible retirement plan specified by the distributee in a direct rollover. B. Definitions: (a) Eligible Rollover Distribution: An eligible rollover distribution is any distribution of all or any portion of the balance to the credit of the distributee, except that an eligible rollover distribution does not include: any distribution that is one of a series of substantially equal periodic payments (not less frequently than annually) made for the life (or life expectancy) of the distributee or the joint lives (or joint life expectancies) of the distributee and the distributee's designated beneficiary, or for a specified period of ten (10) years or more, any distribution to the extent such distribution is required under Section 401(a)(9) of the Code; and the portion of any distribution that is not includable in gross income (determined without regard to the exclusion for net unrealized appreciation with respect to employer securities). 2 (b) Eligible Retirement Plan: An eligible retirement plan is an individual retirement account described in Section 408(a) of the Code, an individual retirement annuity described in Section 408(b) of the Code, an annuity plan described in Section 403(a) of the Code, or a qualified trust described in Section 401(a) of the Code, that accepts the distributee's eligible rollover distribution. However, in the case of an eligible rollover distribution to the surviving spouse, an eligible retirement plan is an individual retirement account or individual retirement annuity. (c) Distributee: A distributee includes an Employee or former Employee. In addition, the Employee's or former Employee's surviving spouse and the Employee's or former Employee's spouse or former spouse who is the alternate payee under a qualified domestic relations order, as defined in Section 414(p) of the Code, are distributees with regard to the interest of the spouse or former spouse. (d) Direct Rollover: A direct rollover is a payment by the Plan to the eligible retirement plan specified by the distributee." IN WITNESS WHEREOF, the Company has caused this Amendment to be executed by its duly authorized officers this 22 day of October, 1996, but effective as of January 1, 1993. CABOT OIL & GAS CORPORATION By: /s/ L.P. SIMS JR. ---------------------------------- L.P. Sims Jr. ATTEST: /s/ LISA A. MACHESNEY - ----------------------- Corporate Secretary -2- 3 CABOT OIL & GAS CORPORATION SAVINGS INVESTMENT PLAN (As Established Effective January 1, 1991) Fourth Amendment Cabot Oil & Gas Corporation, a Delaware corporation (the "Company"), having established the Cabot Oil & Gas Corporation Savings Investment Plan, effective January 1, 1991 (the "Plan"), and having reserved the right under Section 10.4 thereof to amend the Plan, does hereby amend the Plan, effective as of January 1, 1994, unless otherwise specified herein, as follows: 1. Section 1.11 of the Plan is hereby amended by adding the following three paragraphs at the end thereof: "In addition to other applicable limitations set forth in the Plan, and notwithstanding any other provision of the Plan to the contrary, for Plan Years beginning on or after January 1, 1994, the Compensation of each Employee taken into account under the Plan shall not exceed $150,000, as adjusted by the Commissioner for increases in the cost of living in accordance with Section 401(a)(17)(B) of the Internal Revenue Code. The cost-of-living adjustment in effect for a calendar year applies to any period, not exceeding 12 months, over which Compensation is determined (determination period) beginning in such calendar year. If a determination period consists of fewer than 12 months, the Compensation limit will be multiplied by a fraction, the numerator of which is the number of months in the determination period, and the denominator of which is 12. For Plan Years beginning on or after January 1, 1994, any reference in this Plan to the limitation under Section 401(a)(17) of the Code shall mean the Compensation limit set forth in this provision. If Compensation for any prior determination period is taken into account in determining an Employee's benefits accruing in the current Plan Year, the Compensation for that prior determination period is subject to the Compensation limit in effect for that prior determination period. For this purpose, for determination periods beginning before the first day of the first Plan Year 4 beginning on or after January 1, 1994, the Commission limit is $150,000. For purposes of applying the $150,000 limit on Compensation, the family unit of an Employee who either is a 5% owner or is both a highly compensated employee and one of the ten most highly compensated employees will be treated as a single Employee with one Compensation, and the $150,000 limit will be allocated among the members of the family unit in proportion to the total Compensation of each member of the family unit. For this purpose, a family unit consists of the Employee who is a 5% owner or one of the ten most highly compensated employees, the Employee's spouse, and the Employee's lineal descendants who have not attained age 19 before the close of the year." 2. the twelfth sentence in Section 4.1A of the Plan is hereby amended, effective January 1, 1991, to read as follows: "Any Excess Deferrals which have not been returned to the Member by April 15 of the following year shall be treated as Annual Additions under Article XII of the Plan." 3. The last three sentences of Section 12(TV)(5) of the Plan are hereby replace with the following: "For purposes of applying the limitations in this Article, amounts included as compensation are those actually paid or made available to a Member within the Limitation Year. For Limitation years beginning prior to January 1, 1994, Compensation shall be limited to $235,840 (unless adjusted in the same manner as permitted under Code Section 415(d)). For Limitation Years beginning on or after January 1, 1994, Compensation shall be limited to $150,000 (unless adjusted in the same manner as permitted under Code Section 415(d)). Notwithstanding anything to the contrary in the definition, Compensation shall include any and all items which may be includable in Compensation under Section 415(c)(3) of the Code." IN WITNESS WHEREOF, the Company has caused this amendment to be executed by its duly authorized officers this 30th day of December, 1994, but effective as of the dates specified herein. CABOT OIL & GAS CORPORATION By /s/ STEVEN W. THOLEN ------------------------------ Treasurer -2- 5 CABOT OIL & GAS CORPORATION SAVINGS INVESTMENT PLAN (As Established Effective January 1, 1991) Fifth Amendment Cabot Oil & Gas Corporation, a Delaware corporation (the "Company"), having established the Cabot Oil & Gas Corporation Savings Investment Plan, effective January 1, 1991 (the "Plan"), and having reserved the right under Section 10.4 thereof to amend the Plan, does hereby amend the first sentence of Section 6.5 of the Plan by replacing it with three sentences, effective as of October 1, 1996, to read as follows: "6.5 Loans to Members: Except as provided below, the availability of loans are limited to Members who are Employees (hereinafter "Borrowers"), who may make a application to the Committee to borrow from the Accounts maintained by or for the Borrower in the Trust Fund. Additionally, in order for the exemption set forth in 29 C.F.R. 2550.408b-1 to apply to the Plan, a Borrower may also include, but only to the extent not resulting in discrimination prohibited by Section 401(a)(4) of the Code, any other Member or Beneficiary who is a "party in interest" with respect to the Plan within the meaning of ERISA Section 3(14). It is within the sole discretion of the Committee whether or not to permit such a loan." IN WITNESS WHEREOF, the Company has caused this Amendment to be executed by its duly authorized officers this 22 day of October, 1996, but effective as of the date specified herein. CABOT OIL & GAS CORPORATION By: /s/ L.P. SIMS JR. ---------------------------------- L.P. Sims Jr. ATTEST: /s/ LISA A. MACHESNEY - ----------------------- Corporate Secretary EX-21.1 4 SUBSIDIARIES OF CABOT OIL & GAS CORP. 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 L.L.P. 1 EXHIBIT 23.1 CONSENT OF INDEPENDENT ACCOUNTANTS We consent to the incorporation by reference in the registration statements of Cabot Oil and Gas Corporation on Form S-8 filed on June 23, 1991 and on October 29, 1993 of our report dated March 7, 1997, on our audits of the consolidated financial statements of Cabot Oil and Gas Corporation as of December 31, 1996 and 1995, and for each of the three years in the period ended December 31, 1996, which report is 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 and gas properties, and accounting for the impairment of long-lived assets. COOPERS & LYBRAND L.L.P. Houston, Texas March 26, 1997 EX-23.2 6 CONSENT OF MILLER & LENTS, LTD. 1 EXHIBIT 23.2 [MILLER AND LENTS, LTD. LETTERHEAD] March 10, 1997 Cabot Oil & Gas Corporation 15375 Memorial Drive Houston, TX 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 to the use of its report dated February 10, 1997 regarding the Cabot Oil & Gas Corporation Proved Reserves and Future Net Revenues as of January 1, 1997, 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. Yours very truly, MILLER AND LENTS, LTD. By: /s/ JAMES A. COLE ------------------------------------ James A. Cole Senior Vice President JAC/mk EX-27 7 FINANCIAL DATA SCHEDULE
5 1,000 YEAR DEC-31-1996 DEC-31-1996 1,367 0 68,479 (669) 8,797 79,637 999,631 (519,120) 561,341 72,617 248,000 0 91,321 154,428 (85,054) 561,341 154,093 163,061 115,958 115,958 0 0 17,409 31,378 10,554 15,258 0 0 0 15,258 0.67 0
EX-28.1 8 MILLER & LENTS, LTD. REVIEW LETTER DATED - 2/10/97 1 EXHIBIT 28.1 [MILLER AND LENTS, LTD LETTERHEAD] February 10, 1997 Cabot Oil & Gas Corporation 15375 Memorial Drive Houston, TX 77079 Re: Review of Proved Reserves And Future Net Revenues As of January 1, 1997 Gentlemen: At your request, we reviewed the estimates of proved reserves of oil 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, 1997. 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 Oil, MBbls. 4,684.8 480.8 5,165.6 Net Gas, MMcf 768,097.4 147,519.6 915,617.0 Future Net Revenues Undiscounted, M$ 2,357,932.0 396,994.0 2,754,926.0 Discounted at 10 Percent, M$ 1,026,203.0 139,433.8 1,165,637.0
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 10, 1997 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 and Canada. 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 and gas as of Cabot's fiscal year end, December 31, 1996, 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 10, 1997 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 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-----