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, 1995 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) (713) 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. [X] 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 March 1, 1996), was approximately $336,950,000. As of February 29, 1996, there were 22,796,580 shares of Common Stock outstanding. DOCUMENTS INCORPORATED BY REFERENCE Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held May 16, 1996 are incorporated herein by reference in Items 10, 11, 12, and 13 of Part III of this report.
2 TABLE OF CONTENTS PART I <TABLE> <CAPTION> PAGE <S> <C> ITEMS 1 AND 2 Business and Properties 1 ITEM 3 Legal Proceedings 13 ITEM 4 Submission of Matters to a Vote of Security Holders 14 Executive Officers of the Registrant 14 PART II ITEM 5 Market for Registrant's Common Equity and Related Stockholder Matters 15 ITEM 6 Selected Historical Financial Data 15 ITEM 7 Management's Discussion and Analysis of Financial Condition and Results of Operations 16 ITEM 8 Financial Statements and Supplementary Data 26 ITEM 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 51 PART III ITEM 10 Directors and Executive Officers of the Registrant 51 ITEM 11 Executive Compensation 51 ITEM 12 Security Ownership of Certain Beneficial Owners and Management 51 ITEM 13 Certain Relationships and Related Transactions 51 PART IV ITEM 14 Exhibits, Financial Statement Schedules and Reports on Form 8-K 52 </TABLE> --------------------- 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 that involve risks and uncertainties, including, but not limited to, market factors, market prices of natural gas and oil, results of 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.
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, Pennsylvania and New York and in the Western Region, including the Anadarko Basin of southwestern Kansas, Oklahoma and the Texas Panhandle, the Green River Basin of Wyoming, and South Texas. At December 31, 1995, the Company had approximately 922 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, 1995, 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) <TABLE> <CAPTION> Total Appalachian Western Company Region Region(2) - --------------------------------------------------------------------------------------------------- <S> <C> <C> <C> RESERVES/PRODUCTION: Proved reserves Developed (Bcfe) 777.1 431.5 345.6 Undeveloped (Bcfe) 144.6 85.4 59.2 ------------------------------------- Total (Bcfe) 921.7 516.9 404.8 ===================================== Daily production (MMcfe) net 170.3 75.7 94.6 Gross productive wells 5,279.0 4,100.0 1,179.0 Net productive wells 4,403.6 3,768.9 634.7 Percent of wells operated 89.4% 97.6% 61.1% ACREAGE/INFRASTRUCTURE: Net acreage (thousands of acres) Developed acreage 983,800 753,427 230,373 Undeveloped acreage 454,596 290,615 163,981 ------------------------------------- Total 1,438,396 1,044,042 394,354 ===================================== </TABLE> - -------------------------------------------------------------------------------- (1) As of December 31, 1995. 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. 1
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 50 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 of 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 New York. Operations are managed by a regional office in Pittsburgh. At December 31, 1995, the Company had approximately 517 Bcfe of proved reserves (substantially all natural gas) in the Appalachian Region, constituting 56% of the Company's total proved reserves. The Company has 4,100 productive wells (3,768.9 net), of which 4,014 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 1995 was 75.7 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 1995, the Company drilled 33 wells (24.5 net) in the Appalachian Region, of which 24 were development wells (21.5 net). Capital and exploration expenditures, including pipeline expenditures for the year were $10.9 million. In the 1996 drilling program year, the Company has plans to drill 96.0 net wells. At December 31, 1995, the Company had 1,044,042 net acres in the region, including 753,427 net developed acres. At year end, the Company had identified 259.2 net 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, 1995, the Company had approximately 405 Bcfe of proved reserves (92.5% natural gas) in the Western Region, constituting 44% of the Company's total proved reserves. ANADARKO The Company has 728 productive wells (486.2 net) in the Anadarko area of which 544 wells are operated by the Company. Principal producing intervals in Anadarko are in the Chase, Chester and Morrow formations at depths ranging from 1,500 to 11,000 feet. Average net daily production in 1995 was 50.6 MMcfe. 2
5 In 1995, the Company drilled 31 wells (19.4 net) in Anadarko. Capital and exploration expenditures for the year were $6.7 million. In the 1996 drilling program year, the Company has plans to drill 35.4 net wells. At December 31, 1995, the Company had approximately 197,934 net acres, including approximately 177,082 net developed acres. At year end, the Company had identified 40.4 net proved undeveloped drilling locations. ROCKY MOUNTAIN The Company has 279 productive wells (96.0 net) in the Rocky Mountain area of which 141 wells are operated by the Company. Principal producing intervals in Rocky Mountain are in the Frontier and Dakota formations at depths ranging from 7,500 to 13,500 feet. Average net daily production in 1995 was 31.4 MMcfe. In 1995, the Company drilled 19 wells (6.3 net) in the Rocky Mountains. Capital and exploration expenditures for the year were $6.5 million. In the 1996 drilling program year, the Company has plans to drill 22.3 net wells. At December 31, 1995, the Company had approximately 172,827 net acres, including approximately 37,990 net developed acres. At year end, the Company had identified 15.3 net proved undeveloped drilling locations. GULF COAST The Company has 172 productive wells (52.5 net) in the Gulf Coast area of which 44 wells are operated by the Company. Principal producing intervals in Gulf Coast are in the Frio, Wilcox and Vicksburg formations at depths ranging from 2,000 to 14,000 feet. Average net daily production in 1995 was 12.7 MMcfe. In 1995, the Company drilled 10 wells (5.4 net) in Gulf Coast. Capital and exploration expenditures for the year were $7.7 million. In the 1996 drilling program year, the Company has plans to drill 6.9 net wells. At December 31, 1995, the Company had approximately 23,593 net acres, including approximately 15,301 net developed acres. At year end, the Company had identified 3.3 net 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. Sales volumes grew substantially in 1995 as the Company increased the amount of natural gas purchased for resale. This increase was primarily due to an increase in gas purchased from producers and marketers in the Rocky Mountain area and was resold to markets in the Rockies and Pacific Northwest Regions. Volumes purchased and sold in the Western Region increased from approximately 4.3 Bcf in 1994 to approximately 16.4 Bcf in 1995. The marketing of natural gas has changed significantly as a result of 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 and it has also provided the Company the opportunity to reach broader markets. In 1994 and 1995, 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. 3
6 APPALACHIAN REGION The Company's principal markets for its Appalachian Region natural gas are in the northeastern United States. The Company's marketing subsidiary purchases the Company's natural gas production in the Appalachian Region as well as production from local third-party producers and other suppliers to aggregate larger volumes of natural gas for resale. This marketing subsidiary sells natural gas to industrial customers, local distribution companies ("LDCs") and gas marketers both on and off the Company's pipeline 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 3,600 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 35% 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 midwest and northwestern 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 25% of the Western Region's production is sold under a cogeneration contract with 13 years remaining and a price escalation of 5% per year. The Western Region properties are connected to the majority of the midwestern and northwestern interstate pipelines, affording the Company access to multiple markets. The Company also produces and markets approximately 2,000 barrels a day of crude oil/condensate in the Western Region at market responsive prices. 4
7 RISK MANAGEMENT In 1995, the Company entered into certain transactions to manage price risks associated with its production and purchase commitments. The Company utilized certain natural gas price swap agreements ("price swaps") to attempt to manage price risk more effectively and improve the Company's realized natural gas prices. These price swaps call for payments to (or to receive payments from) counterparties based upon the differential between a fixed and a variable gas price. At December 31, 1995, a majority of the open price swaps (16,085,000 MMbtu in notional quantity) cover the months of January through April 1996 and a remaining contract (1,260,000 MMbtu in notional quantity) covers the production months of November 1996 to February 1997. The Company plans to continue 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, 1995. <TABLE> <CAPTION> Natural Gas (MMcf) Liquids(1) (MBbl) Total(2) (MMcfe) ------------------------------------------------------------------------------------------------- Developed Undeveloped Total Developed Undeveloped Total Developed Undeveloped Total - ------------------------------------------------------------------------------------------------------------------ <S> <C> <C> <C> <C> <C> <C> <C> <C> <C> Appalachian 430,165 85,391 515,556 219 0 219 431,477 85,391 516,868 Western(3) 317,070 57,224 374,294 4,751 339 5,090 345,579 59,260 404,839 ------------------------------------------------------------------------------------------------- Total 747,235 142,615 889,850 4,970 339 5,309 777,056 144,651 921,707 ================================================================================================= </TABLE> - ------------------------------------------------------------------------------- (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 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 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, 1995. There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond the control of the Company and, therefore, the reserve information set forth in this Form 10-K represents only estimates. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based. In general, the volume of production from oil and gas properties owned by the Company declines as reserves are depleted. Except to the extent the Company acquires additional properties containing proved reserves or conducts successful exploration and development activities or both, the proved reserves of the Company will decline as reserves are produced. 5
8 HISTORICAL RESERVES The following table sets forth certain information regarding the Company's estimated proved reserves for the periods indicated. <TABLE> <CAPTION> Oil, Condensate Natural Gas (MMcf) & NGLs (MBbl) Total (MMcfe) - ----------------------------------------------------------------------------------------------------------------------- APP WEST TOTAL APP WEST TOTAL APP WEST TOTAL - ----------------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> <C> <C> <C> <C> DECEMBER 31, 1992 505,264 219,402 724,666 116 1,683 1,799 505,960 229,500 735,460 Revisions of prior estimates (17,621) (649) (18,270) (6) (349) (355) (17,657) (2,743) (20,400) Extensions, discoveries and other additions 35,439 22,826 58,265 1 436 437 35,445 25,442 60,887 Production (26,191) (19,859) (46,050) (13) (332) (345) (26,269) (21,851) (48,120) Purchases of reserves in place 60,508 32,623 93,131 38 1,293 1,331 60,736 40,381 101,117 Sales of reserves in place (1,466) (1,996) (3,462) 0 (41) (41) (1,466) (2,242) (3,708) ------------------------------------------------------------------------------------ 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 ==================================================================================== PROVED DEVELOPED RESERVES: December 31, 1992 398,895 184,778 583,673 116 1,394 1,510 399,591 193,142 592,733 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 </TABLE> - ------------------------------------------------------------------------------- (1) For the year ended December 31, 1993 and 1992 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. APP = Appalachian Region WEST = Western Region(1) 6
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. <TABLE> <CAPTION> Year Ended December 31, 1995 1994 1993 - ---------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> Net Wellhead Sales Volume: Natural Gas (Bcf)(1) Appalachian Region 26.4 28.7 23.1 Western Region(2) 29.8 28.3 19.8 Crude/Condensate/Ngl (MBbl) Appalachian Region 18 20 13 Western Region 722 804 332 Purchased Gas Volumes (Bcf) 57.1 48.3 21.6 Purchase Cost ($/Mcf) $ 1.51 $ 1.92 $ 2.09 Natural Gas Sales Price ($/Mcf)(3) Appalachian Region $ 2.18 $ 2.47 $ 2.69 Western Region $ 1.37 $ 1.73 $ 1.94 Weighted Average $ 1.75 $ 2.14 $ 2.40 Crude/Condensate Sales Price ($/Bbl)(3) $ 17.95 $ 16.66 $ 16.58 Production Costs ($/Mcfe)(4) $ 0.55 $ 0.62 $ 0.65 </TABLE> - -------------------------------------------------------------------------------- (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. For the year ended December 31, 1993 includes Anadarko only. (3) Represents the average sales prices for all volumes (including royalty volumes) sold by the Company during the periods shown. (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. ACREAGE The following tables summarize the Company's gross and net developed and undeveloped leasehold and mineral acreage at December 31, 1995. 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. 7
10 LEASEHOLD ACREAGE <TABLE> <CAPTION> At December 31, 1995 Developed Undeveloped Total Gross Net Gross Net Gross Net - -------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> <C> STATE Alabama -- -- 2,543 2,402 2,543 2,402 Arkansas -- -- 240 6 240 6 Colorado 14,742 13,406 50,481 44,387 65,223 57,793 Indiana -- -- 42,404 27,696 42,404 27,696 Kansas 32,303 28,965 16,873 5,136 49,176 34,101 Kentucky 2,680 983 15,677 7,655 18,357 8,639 Louisiana 1,571 297 4,267 790 5,838 1,087 Michigan -- -- 231 38 231 38 Montana 157 52 680 303 837 355 New York 21,562 16,080 2,625 2,503 24,187 18,583 North Dakota 160 20 870 96 1,030 116 Ohio 2,581 1,291 38,544 17,626 41,125 18,917 Oklahoma 163,930 106,914 20,983 15,365 184,913 122,279 Pennsylvania 163,004 150,491 90,264 80,378 253,268 230,869 Texas 69,574 42,073 8,250 5,110 77,824 47,183 Utah 1,740 529 27,079 22,271 28,819 22,800 Virginia 3,748 3,095 15,737 15,737 19,485 18,832 West Virginia 551,263 516,083 94,623 80,729 645,886 596,812 Wyoming 46,877 23,895 111,254 66,231 158,131 90,125 ------------------------------------------------------------------------ Total 1,075,892 904,174 543,625 394,459 1,619,517 1,298,633 ======================================================================== CANADA Alberta 80 42 1,666 645 1,746 687 British Columbia 83 21 3,235 809 3,318 830 ------------------------------------------------------------------------ Total 163 63 4,901 1,454 5,064 1,517 ======================================================================== </TABLE> MINERAL FEE ACREAGE <TABLE> <CAPTION> At December 31, 1995 Developed Undeveloped Total Gross Net Gross Net Gross Net - -------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> <C> 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 13,979 160 9 16,741 13,988 Pennsylvania 70 70 1,621 550 1,691 620 Texas 27 27 652 326 679 353 West Virginia 79,100 65,334 56,905 56,066 136,005 121,400 ------------------------------------------------------------------------ Total 96,112 79,563 66,737 58,683 162,849 138,246 ======================================================================== Aggregate Total 1,172,167 983,800 615,263 454,596 1,787,430 1,438,396 ======================================================================== </TABLE> 8
11 TOTAL NET ACREAGE BY AREA OF OPERATION <TABLE> <CAPTION> At December 31, 1995 Developed Undeveloped Total - -------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> Appalachian Region 753,427 290,615 1,044,042 Western Region 230,373 163,981 394,354 ---------------------------------------------------------- Total 983,800 454,596 1,438,396 ========================================================== </TABLE> PRODUCTIVE WELL SUMMARY(1) The following table reflects the Company's ownership at December 31, 1995 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). <TABLE> <CAPTION> Natural Gas Oil Total Gross Net Gross Net Gross Net - --------------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> <C> Appalachian Region 4,084.0 3,757.3 16.0 11.6 4,100 3,768.9 Western Region 948.5 549.5 230.5 85.3 1,179 634.7 --------------------------------------------------------------------------- Total 5,032.5 4,306.8 246.5 96.9 5,279 4,403.6 =========================================================================== </TABLE> - -------------------------------------------------------------------------------- (1) "Productive" wells are producing wells and wells capable of production. DRILLING ACTIVITY The Company drilled, participated in the drilling of, or acquired wells as set forth in the table below for the periods indicated: <TABLE> <CAPTION> Year Ended December 31, 1995 1994 1993 - --------------------------------------------------------------------------------------------------------- Gross Net Gross Net Gross Net - --------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> <C> APPALACHIAN REGION: Development Wells Natural Gas 18 16.7 133 128.2 117 114.5 Oil 0 0.0 0 0.0 0 0.0 Dry 6 4.8 7 6.5 5 5.0 Exploratory Wells Natural Gas 2 0.5 0 0 1 0.3 Oil 2 0.5 0 0 0 0.0 Dry 5 2.0 2 0.5 3 2.3 ------------------------------------------------------------ Total 33 24.5 142 135.2 126 122.1 ============================================================ Wells Acquired(1) Natural Gas 3 3.7 9 21.1 396 397.8 Oil 0 0.0 0 0.0 6 6.0 ------------------------------------------------------------ Total 3 3.7 9 21.1 402 403.8 ============================================================ Wells in Progress at End of Period 3 3.0 2 1.3 0 0.0 </TABLE> 9
12 <TABLE> <CAPTION> Year Ended December 31, 1995 1994 1993 - --------------------------------------------------------------------------------------------------------- Gross Net Gross Net Gross Net - --------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> <C> Western Region:(2) Development Wells Natural Gas 42 21.2 48 24.7 26 19.2 Oil 2 1.9 7 3.1 5 3.6 Dry 7 3.8 8 5.3 5 4.9 Exploratory Wells Natural Gas 1 0.3 0 0 0 0.0 Oil 0 0 0 0 0 0.0 Dry 8 3.9 3 0.8 0 0.0 ------------------------------------------------------------ Total 60 31.1 66 33.9 36 27.7 ============================================================ Wells Acquired(1) Natural Gas 0 2.7 413 115.7 218 106.5 Oil 0 0.1 140 52.3 303 63.6 ------------------------------------------------------------ Total 0 2.8 553 168.0 521 170.1 ============================================================ Wells in Progress at End of Period 6 5.3 7 1.9 3 3.0 </TABLE> - -------------------------------------------------------------------------------- (1) Includes the acquisition of net interest in certain wells in the Appalachian Region and in the Western Region in 1995, 1994 and 1993 in which the Company already held an ownership interest. (2) The year ended December 31, 1993 included information for Anadarko only. 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 revenues in 1995. 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, 10
13 have issued rules and regulations affecting the oil and natural gas industry and its individual members, compliance with which is often difficult and costly and some of which may carry substantial penalties for non-compliance. The regulatory burden on the oil and natural gas industry increases its cost of doing business and, consequently, affects its profitability. Inasmuch as such laws and regulations are frequently expanded, amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with such regulations. However, the Company does not believe that under present regulations it is affected in a significantly different manner by these regulations than others in the industry. EXPLORATION AND PRODUCTION 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 11
14 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, the Company cannot predict what new regulations may be adopted by the FERC and other regulatory authorities, or what effect subsequent regulations may have on the Company's activities. Further, even though the implementation of Order No. 636 on individual interstate pipelines is essentially complete, many of the individual pipeline restructuring proceedings, as well as Order No. 636 itself and the regulations promulgated thereunder, are subject to pending appellate review and could possibly be changed as a result of future court orders. 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 to the pipeline's nonregulated affiliate, (ii) the completion of a rulemaking 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, and (vi) a policy statement regarding market-based rates and other non-cost-based rates for interstate pipeline transmission and storage capacity. 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 has attempted to address some of these concerns in its orders authorizing such "spin-downs," but it remains to be seen what effect these activities will have on access to markets and the cost to do business. As to all of these recent FERC 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 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. It is possible that increasingly strict requirements will be imposed by environmental laws and enforcement policies thereunder. The Company is also subject to the Federal Clean Air Act and the Federal Clean Air Act Amendment of 1990 which added significantly to the existing requirements established by the Federal Clean Air Act. It is not anticipated that the Company will be required in the near future to expend amounts that are material in relation to its total capital expenditures program by reason of environmental laws and regulations, but inas-much as such laws and regulations are frequently changed, the Company is unable to predict the ultimate cost of such compliance. 12
15 The Company owns and operates a brine treatment plant in Pennsylvania which processes fluids generated by drilling and production operations. See "Exploration, Development and Production -- Appalachian Region." The plant's operations are regulated by Pennsylvania's Department of Environmental Regulation. EMPLOYEES The Company had approximately 359 active employees as of December 31, 1995. The Company believes that its relations with its employees are satisfactory. The Company has not entered into any collective bargaining agreements with its employees. OTHER The Company's profitability depends on certain factors that are beyond its control, such as natural gas and crude oil prices. The nature of the oil and gas business involves a variety of risks, including the risk of experiencing certain 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, 1995, the Company owned or operated approximately 3,600 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 of any period but would not have a material adverse effect on the Company's financial position. In February 1993, Barby Energy Corporation and certain other parties filed suit in Beaver County, Oklahoma against the Company to determine the rights and interests of the parties in and to the oil, gas and other minerals underlying a tract of land in Beaver County, Oklahoma, to quiet title to said mineral estate, and for an accounting and payment of production proceeds attributable to said mineral estate. Specifically at issue is whether there was continuous production from an oil and gas well located on the property since July 5, 1965. Plaintiffs claim there was a cessation of production, and therefore, all right, title and interest to such property reverted to them and that they are entitled to all revenues from such production since the date cessation of production occurred. The Company believes that it holds a valid oil and gas lease covering the interest claimed by the plaintiffs. The trial commenced on February 6, 1995 and, pursuant to an order entered on February 13, 1995, the judge denied and overruled all of the plaintiffs' claims. On March 16, 1995, Barby appealed the decision of the trial court to the Oklahoma Supreme Court. Barby requested that the Oklahoma Supreme Court retain the case. Subsequently, the Oklahoma Supreme Court decided not to retain the case and assigned the appeal to the Oklahoma Court of Appeals. The Barby appeal has been stayed pending settlement discussions. 13
16 In September 1995, Barby filed a separate action in state court in Oklahoma, purporting to represent all similarly situated royalty owners in Oklahoma, alleging improper calculation of royalties and seeking actual and punitive damages. The Company has denied the material allegations of the complaint. No formal discovery has yet been conducted. This action has been stayed pending settlement discussions. Although no assurances can be given, the Company believes that the ultimate outcome of the above litigation will not have a material adverse effect on the Company's financial position. 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, 1995 to December 31, 1995. EXECUTIVE OFFICERS OF THE REGISTRANT The following table shows certain information about the executive officers of the Company as of March 1, 1996, as such term is defined in Rule 3b-7 promulgated under the Securities Exchange Act of 1934, and certain other officers of the Company. <TABLE> <CAPTION> Name Age Position Officer Since -------------------------------------------------------------------------------------------------- <S> <C> <C> <C> Charles P. Siess, Jr. 69 Chairman of the Board, Chief Executive 1995 Officer and President Jim L. Batt 60 Vice President, Land 1988 Jeff W. Hutton 40 Vice President, Marketing 1995 Gerald F. Reiger 43 Vice President and Regional Manager 1994 Ray R. Seegmiller 60 Vice President, Chief Financial Officer 1995 and Treasurer James M. Trimble 47 Vice President, Business Development 1987 and Engineering H. Baird Whitehead 45 Vice President and Regional Manager 1987 Frank A. Pici 40 Controller 1994 Lisa A. Machesney 40 Corporate Secretary and Managing Counsel 1995 </TABLE> 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 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 has been Vice President, Chief Financial Officer and Treasurer of the Company since 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. 14
17 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: <TABLE> <CAPTION> Cash High Low Dividends -------------------------------------------------------- <S> <C> <C> <C> <C> 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 1994 First Quarter $ 23.50 $ 19.13 $ 0.04 Second Quarter 23.25 18.75 0.04 Third Quarter 22.25 18.38 0.04 Fourth Quarter 19.88 13.38 0.04 </TABLE> As of January 31, 1996, there were 1,302 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. <TABLE> <CAPTION> Year Ended December 31, 1995 1994 1993 1992 1991 - ------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> INCOME STATEMENT DATA: Revenues $ 213,923 $ 237,067 $ 164,295 $ 147,608 $ 140,484 Income (Loss) from Operations (116,758) 15,013 20,007 17,983 13,707 Net Income (Loss) Applicable to All Common Stockholders (92,171) (5,444) 2,088 2,227 229 EARNINGS (LOSS) PER SHARE APPLICABLE TO ALL COMMON STOCKHOLDERS(1) $ (4.05) $ (0.25) $ 0.10 $ 0.11 $ 0.01 DIVIDENDS PER COMMON SHARE $ 0.16 $ 0.16 $ 0.16 $ 0.16 $ 0.16 BALANCE SHEET DATA: Oil and Gas Properties $ 399,984 $ 554,137 $ 322,163 $ 229,778 $ 229,538 Total Assets 528,155 688,352 445,001 348,696 334,311 Long-Term Debt 249,000 268,363 169,000 120,000 105,000 Stockholders' Equity 147,856 243,082 153,529 118,313 119,241 - ------------------------------------------------------------------------------------------------------- </TABLE> (1) See "Earnings (Loss) Per Common Share" under Note 1 of the Notes to the Consolidated Financial Statements. 15
18 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 Due to the difficult industry conditions of 1995, the Company was in an economic squeeze, caught between depressed natural gas prices, the lowest on Company record since going public in 1990, and high operating costs. Compounding the problem were increased financing costs from the 1994 and 1993 acquisitions, made when gas prices were significantly higher. This squeeze caused a net loss for the year and reduced cash flow below the level needed to sustain drilling and, in turn, maintain reserves and production. In order to meet the challenges of 1995 and strive to return the Company to profitability in 1996 and beyond, the Company took the following actions in 1995: o Implemented a cost reduction program which reduced the total workforce by 115 employees, resulting in a $6.8 million charge in the first quarter. Combined with an additional reduction of 20 managers and employees in October, the reduction in annual payroll and fringe benefit expenses is expected to exceed $7 million, or 25%, in 1996. o Monetized its Section 29 tight sands tax credits, receiving $2.8 million in 1995 and projected cash inflows of $3 million in 1996 and another $17 million over the remaining six years. o Sold over 580 non-core and marginal wells in the Western Region, generating $7.6 million in proceeds as part of an ongoing company-wide asset rationalization program, which will carry into 1996. o Completed a valuation adjustment on the 1994 WERCO acquisition, receiving a cash payment of $8.4 million. o Monetized settlement claims for $4.3 million in connection with the remaining value of gas sales contracts terminated by Columbia Gas Transmission Corporation as part of its 1991 bankruptcy filing. These actions improved cash flow in 1995 by reducing costs or increasing cash inflows, and allowed the Company to reduce the debt level to $249 million at year end, substantially below the $268 million at the beginning of the year, while expanding the drilling program in the fourth quarter by $9 million. During 1995, the Company adopted Statement of Financial Accounting Standards No. 121, relating to the impairment of long-lived assets, recording a $113.8 million charge ($69.2 million after-tax, or $3.04 per share) in the third quarter. While the charge has no affect on cash flow, it is expected to reduce future DD&A expense by approximately 15% or $0.13 per Mcfe produced. The Company drilled 55 net wells with a drilling success rate of 75%, compared to 169 net wells drilled in 1994 at a success rate of 92%. After drilling only 23 net wells in the first three quarters, the Company stepped up its program in the fourth quarter, drilling 32 net wells. The 1995 drilling program was the smallest in its history as a public company. In 1996, the Company plans to drill 161 net wells. Natural gas production remained virtually flat at 57.7 Bcf compared to 58.3 Bcf in 1994. While a full year of production from the WERCO properties increased production by 3.2 Bcf, production declines in the Appalachian Region and Anadarko area, primarily due to the reduced drilling program and the asset rationalization program, more than offset the increase. Natural gas sales exceeded 112 Bcf in 1995, an increase of 10 Bcf, or 10%, over 1994. This increase was the result of an expanded marketing program with respect to third-party natural gas purchased for resale ("brokered gas"). 16
19 The Company's expanded marketing effort increased purchase and resale volumes of third-party natural gas by 8.7 Bcf, or 18%, from 1994. The most significant part of this increase was in natural gas purchased and resold in brokered arrangements which increased from 23.7 Bcf in 1994 to 31.2 Bcf in 1995. The Company realized a contribution to operating income from these brokered arrangements of approximately 3 cents per Mcf in 1995, compared with approximately 5 cents per Mcf in 1994. As a hedging strategy to manage commodity price risk associated with its production and purchase commitments, from time to time the Company enters into commodity derivative contracts, such as natural gas price swaps and options. At year end the Company had a number of price swaps in place to hedge a significant portion of its production in the first quarter of 1996. Due to an unprecedented decoupling of the Nymex price from realizable sales prices outside of the northeastern markets, many producers' hedges were left uncovered, including the Company's hedges of its Western Region production. Accordingly, the Company recorded a $3.2 million pre-tax charge at year end when these uncovered hedges were marked to market (see Notes 1 and 13 of the Notes to the Consolidated Financial Statements). By changing the terms of the hedges, management has taken the necessary steps to prevent future hedge contracts from becoming 'uncovered' and, when opportunities arise, will continue to use hedging instruments to reduce downside price risk on its production and purchase commitments. The Company's strategic pursuits are sensitive to energy commodity prices, particularly the price of natural gas. The average natural gas price realized by the Company in 1995 was approximately 18% lower than 1994 and was the lowest average price realized since the Company became publicly traded. Excluding the SFAS 121 long-lived asset impairment of $69.2 million (after tax), lower natural gas prices and increased financing costs related to the 1994 and 1993 acquisitions were the primary factors that caused the net loss and reduced cash flows for the year. While gas prices in certain regions of the U.S. have moved up sharply in 1996 and some industry analysts predict improvements in 1996 pricing compared to 1995, the gas market has continued to demonstrate significant price volatility during the months of January and February 1996. Consequently, there is still considerable uncertainty among industry analysts about future gas prices for the rest of 1996 and beyond. Because of this challenging price environment, the Company is focused on the following goals: 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 1996 if the Henry Hub average price is $1.80 or more and assuming a traditional correlation between Henry Hub prices and prices in the physical markets. o Maintain reserves per share while increasing production to protect long-term shareholder value. The expanded 1995 drilling program and an aggressive 1996 program are designed to result in 1996 production exceeding 1995, while 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 Company believes that progress toward these goals is appropriate in the current price environment, and should enable the Company to pursue its strategic objectives over the long term. FINANCIAL CONDITION CAPITAL RESOURCES AND LIQUIDITY The Company's capital resources consist primarily of cash flows from oil and gas properties and asset-based borrowing supported by its oil and gas reserves. The Company's level of earnings and cash flow depends on many factors, including the price of natural gas and oil and its ability to control or reduce costs. Demand for oil 17
20 and gas has historically been subject to seasonal influences characterized by peak demand and higher prices in the winter heating season. During 1995, the Company did not experience significant curtailments of production due to market conditions. However, during the months of August and September 1995, the Company elected to withhold approximately 12 MMcf per day of natural gas from markets, or about 7% of its productive capacity, due to low prices, which had the effect of reducing cash flows for the month. Primary sources of cash for the Company during the three-year period ended December 31, 1995 were funds generated from operations and bank borrowing. Primary uses of cash for the same period were funds used in operations, exploration and development expenditures, acquisitions, repayment of debt and dividends. The Company had a net cash outflow of $0.7 million in 1995. Net cash inflow from operating and financing activities totalled $13.3 million, funding in most part the capital and exploration expenditures of $14.0 million, net of the $8.4 million valuation adjustment on the WERCO acquisition and $10.3 million in proceeds for the sale of assets. <TABLE> <CAPTION> (In millions) 1995 1994 1993 ------------------------------------------------------------------------------------- <S> <C> <C> <C> Cash Flows Provided by Operating Activities $ 41.5 $ 67.3 $ 55.4 ================================ </TABLE> 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. Cash flows provided by operating activities in 1994 were higher by $11.9 million compared with 1993 primarily due to the cash flows generated from the oil and gas properties acquired in the WERCO acquisition. <TABLE> <CAPTION> (In millions) 1995 1994 1993 ------------------------------------------------------------------------------------- <S> <C> <C> <C> Cash Flows Used by Investing Activities $ 14.0 $ 158.8 $ 98.9 ================================ </TABLE> Cash flows used by investing activities in 1995 were $144.8 million lower than in 1994 primarily due 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. Cash flows used by investing activities in 1994 were $59.9 million higher than in 1993 primarily due to $52.9 million of increased capital expenditures from development drilling activity and the WERCO acquisition. <TABLE> <CAPTION> (In millions) 1995 1994 1993 ------------------------------------------------------------------------------------- <S> <C> <C> <C> Cash Flows Provided (Used) by Financing Activities $ (28.2) $ 92.4 $ 45.3 ================================ </TABLE> Cash flows provided by financing activities from 1993 to 1995 were primarily borrowings from or payments on the Company's revolving credit facility. In 1995 the Company reduced its debt under this facility by $19.0 million. 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. During 1995, the Company's the available credit line under the revolving credit facility was reduced to $235 million, or $25 million lower than 1994. This brought the credit line to a level more consistent with the Company's needs and lowered the annual commitments fees paid on the unused portion of the credit line. 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 $169 million at December 31, 1995. 18
21 The Company's 1996 debt service is projected to be approximately $19 million. No principal payments are due in 1996, assuming the continued renewal of the revolving facility. During 1995, the Company had recorded charges totaling $1.8 million to interest expense in connection with the net payments made on interest rate swap agreements. In December 1995, the Company closed all interest rate swap agreements, resulting in an additional charge to interest expense of $2.6 million. Capitalization information on the Company is as follows: <TABLE> <CAPTION> (In millions) 1995 1994 1993 ---------------------------------------------------------------------------- <S> <C> <C> <C> Long-Term Debt $ 249.0 $ 268.3 $ 169.0 Stockholders' Equity Common Stock 56.6 151.8 118.9 Preferred Stock 91.3 91.3 34.6 ------------------------------------ Total 147.9 243.1 153.5 ------------------------------------ Total Capitalization $ 396.9 $ 511.4 $ 322.5 ==================================== Debt to Capitalization 62.7% 52.5% 52.4% ==================================== </TABLE> The Company's capitalization reflects the non-cash impact to equity of the $69.2 million SFAS 121 impairment of long-lived assets. (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, 1995. <TABLE> <CAPTION> (In millions) 1995 1994 1993 ---------------------------------------------------------------------------- <S> <C> <C> <C> Capital Expenditures: Drilling and Facilities $ 19.3 $ 47.9 $ 34.6 Leasehold Acquisitions 2.0 4.7 3.9 Pipeline and Gathering 2.2 8.9 6.8 Other 1.2 2.3 1.3 ------------------------------------ 24.7 63.8 46.6 ------------------------------------ Proved Property Acquisitions -- 8.9 82.4(1) WERCO Acquisition (8.4)(3) 216.2(2) -- ------------------------------------ (8.4) 225.1 82.4 ------------------------------------ Exploration Expenses 8.0 8.0 6.9 ------------------------------------ Total $ 24.3 $ 296.9 $ 135.9 ==================================== </TABLE> - -------------------------------------------------------------------------------- (1) Includes $34.6 million of non-cash consideration for the purchase of properties from the Harken Anadarko Partners, L.P. ("Harken"). (2) 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 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". (3) A net cash payment received in connection with a valuation adjustment on the 1994 WERCO acquisition. 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. 19
22 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 1996 have been significantly increased compared with 1995. Depending on the level of future natural gas prices, the Company intends to review and adjust the capital and exploration expenditures planned for 1996 as industry conditions dictate. Presently, the Company projects $69 million in capital and exploration expenditures for 1996. The Company plans to drill 220 (161 net), compared with 93 wells (55 net) drilled in 1995. Capital dedicated to the drilling program for 1996 is $41 million. Other 1996 capital expenditures are planned primarily for producing property acquisitions and for gathering and pipeline infrastructure maintenance and construction. During 1995, dividends were paid on the Company's common stock totalling $3.6 million, on the $3.125 convertible preferred stock totalling $2.2 million, and on the 6% convertible redeemable preferred stock totalling $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. OTHER ISSUES AND CONTINGENCIES Barby Lawsuit. In February 1993, Barby Energy Corporation and certain other parties filed suit in Beaver County, Oklahoma against the Company to determine the rights and interests of the parties in and to the oil, gas and other minerals underlying a tract of land in Beaver County, Oklahoma, to quiet title to said mineral estate, and for an accounting and payment of production proceeds attributable to said mineral estate. Specifically at issue was whether there was continuous production from an oil and gas well located on the property at issue since July 5, 1965. Plaintiffs claimed there was a cessation of production, and therefore, all right, title and interest to such property reverted to them and they were entitled to all revenues from such production since the date cessation of production occurred. The Company maintained that it holds a valid oil and gas lease covering the interest claimed by the plaintiffs. The trial commenced on February 6, 1995 and, pursuant to an order entered on February 13, 1995, the judge denied and overruled all of the plaintiffs' claims. On March 16, 1995, Barby appealed the decision of the trial court to the Oklahoma Supreme Court. Barby requested that the Oklahoma Supreme Court retain the case. Subsequently, the Oklahoma Supreme Court decided not to retain the case and assigned the appeal to the Oklahoma Court of Appeals. The Barby appeal has been stayed pending settlement discussions. In September 1995, Barby filed a separate action in state court in Oklahoma, purporting to represent all similarly situated royalty owners in Oklahoma, alleging improper calculation of royalties and seeking actual and punitive damages. The Company has denied the material allegations of the complaint. No formal discovery has yet been conducted. The action has been stayed pending settlement discussions. Although no assurances can be given, the Company believes that the ultimate outcome of the above litigation will not have a material adverse effect on the Company's financial position. 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 $1.00 per MMbtu in 1995. As a result of the WERCO acquisition, certain production from qualifying formations in the Rocky Mountains also qualifies for the tight gas sands tax credit. However, the benefits of all such credits have been lost in recent years due to the Company's regular net operating loss positions. As such, the Company 20
23 completed two transactions in 1995 to monetize the value of these tax credits, resulting in future revenues of $3 million in 1996 and approximately $17 million over the remaining six years (See Note 18 of the Notes to the Consolidated Financial Statements for further discussion). The Company 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 ("IDCs") 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% (30% for 1993) 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 debt covenants in the Company's various debt instruments. Among other requirements, the Company's revolving credit facility specifies a minimum cash flow to debt service coverage ratio of 1.2 to 1.0, projected for the next two years utilizing the banks assumptions. At December 31, 1995, the calculated ratio for 1996 and 1997 was 2.7 to 1, assuming the continued renewal of the revolving facility. 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 1995 natural gas price decreased 18% compared with the average natural gas price received in 1994. The deterioration of gas prices during 1995 has negatively impacted the Company's earnings and cash flows and has contributed significantly to the net loss recorded in 1995. While prices in certain regions of the U.S. have moved up sharply in the first two months of 1996, the volatility of natural gas prices in recent years remains prevalent in 1996 with wide price swings in day-to-day trading on the Nymex futures market and the recent decoupling of the Nymex from the markets outside the Northeast. Given this continued price volatility, management cannot predict with certainty what pricing levels will be for the remainder of 1996. 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 1996 plans include a significant increase in capital spending, potentially negative changes in industry conditions might require the Company to adjust its 1996 spending plan to ensure the availability of capital, including, among other things, reductions in capital expenditures or common stock dividends. The Company believes that higher production volumes and natural gas prices over time coupled with the Company's continuing efforts to reduce costs and invest in projects with high rates of return will return the Company to profitability. Furthermore, the Company believes its capital resources, supplemented, if necessary, with external financing, are adequate to meet its capital requirements. 21
24 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 <TABLE> <CAPTION> (In millions except where specified) 1995 1994 1993 ---------------------------------------------------------------------------- <S> <C> <C> <C> Revenues $ 213.9 $ 237.1 $ 164.3 Costs and Expenses 330.1 222.1 145.6 Interest Expense 24.9 16.7 10.3 Net Income (Loss) (92.2) (5.4) 2.1 Earnings (Loss) Per Share $ (4.05) $ (0.25) $ 0.10 Natural Gas Sales (Bcf) Appalachia 52.6 56.9 39.9 West 59.7 45.6 24.5 --------------------------------- Total Company 112.3 102.5 64.4 ================================= Natural Gas Production (Bcf) Appalachia 27.5 29.7 26.2 West 30.2 28.6 19.8 --------------------------------- Total Company 57.7 58.3 46.0 ================================= Natural Gas Prices ($/Mcf) Appalachia $ 2.18 $ 2.47 $ 2.69 West $ 1.37 $ 1.73 $ 1.94 Total Company $ 1.75 $ 2.14 $ 2.40 Crude/Condensate Volume (MBbl) 618 687 345 Price ($/Bbl) $ 17.95 $ 16.66 $ 16.58 </TABLE> The table below presents the effects of certain selected items ("selected items") on the Company's results of operations for the three years ended December 31, 1995. <TABLE> <CAPTION> (In millions) 1995 1994 1993 ---------------------------------------------------------------------------- <S> <C> <C> <C> Net Income (Loss) Before Selected Items $ (17.3) $ (5.4) $ 5.1 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) Early adoption of SFAS 112 (0.4) Consolidation of office space (0.3) Deferred tax adjustment due to federal rate change (2.3) --------------------------------- Net Income (Loss) $ (92.2) $ (5.4) $ 2.1 ================================= </TABLE> 22
25 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 sales comprised 92%, or $196.6 million, of total revenue in 1995. The decrease in total revenues was driven primarily by an 18% decrease in the average natural gas price, partially offset by a 9% increase in natural gas sales 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 sales volumes were down 4.3 Bcf to 52.6 Bcf in the Appalachian Region due to a decrease in gas purchased for resale. 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. The reduction in sales due to the production decline in Appalachia was primarily offset by net changes in gas storage and exchanges. Natural gas sales volumes were up 13.6 Bcf to 64.0 Bcf in the Western Region due primarily to higher production volume (up 1.5 Bcf) and gas purchased for resale (up 13.1 Bcf), all of which are primarily due to a full year of operating results from the WERCO acquisition. The average Appalachian natural gas sales price decreased $0.29 per Mcf, or 12%, to $2.18, decreasing operating revenues by approximately $15.4 million. In the Western Region, the average natural gas sales price decreased $0.36 per Mcf, or 21%, to $1.37, decreasing operating revenues by approximately $21.4 million. Because the proportion of lower priced Western Region sales volume relative to total Company sales volume was up significantly, the weighted average natural gas price for the total Company decreased $0.39 per Mcf, or 18%, to $1.75. Crude oil and condensate sales were virtually unchanged at 618 MBbl. 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. 23
26 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. 1994 AND 1993 COMPARED Net Income (Loss) and Revenues. The Company recorded a net loss in 1994 of $5.4 million, down $10.5 million, or $0.48 per share, compared with 1993, excluding the impact of the selected items. Excluding the pre-tax effects of the selected items in the table above, operating income decreased $6.2 million and revenues increased $72.8 million. Natural gas sales comprised 93%, or $219.7 million, of total revenue in 1994. The increase in revenues was primarily due to the WERCO acquisition ($42.1 million), an increase in natural gas purchased for resale ($32.3 million) and an increase in core production volumes ($5.9 million). Net income and operating income, however, were negatively impacted in 1994 by an 11% decline in the average natural gas price and higher depreciation expense and additional financing cost associated with the WERCO acquisition. The Company added two new operating areas through the WERCO acquisition in the Rocky Mountains and onshore Gulf Coast. The WERCO acquisition provides the Company with development and exploration opportunities in the Green River Basin of the Rocky Mountains and in the onshore Gulf Coast; an increase in reserves which exceeded one trillion cubic feet equivalent of natural gas; and the expansion of the Company's production base by approximately 40% annualized. Operating results from the WERCO acquisition for the eight months ended December 31, 1994 were as follows: 9.5 Bcf of natural gas production, 19.4 Bcf of natural gas sales, 357 MBbl of oil production and $42.1 million of revenues. Total natural gas and oil revenues from the acquired properties were $33.7 million and $6.0 million, respectively. The average natural gas price received on the WERCO acquisition in 1994 was $1.74 per Mcf. Natural gas sales volumes were up 17.0 Bcf to 56.9 Bcf in the Appalachian Region primarily attributable to an increase in natural gas purchased for resale and, to a lesser extent, increased production. Production volume was up 3.5 Bcf to 29.7 Bcf in the Appalachian Region primarily due to expanded production associated with the Emax acquisition. Production volume in the Western Region was up 8.8 Bcf to 28.6 Bcf due to increased production associated with the WERCO acquisition. Natural gas sales volumes in the Western Region were up 21 Bcf primarily due to the increased production and, to a lesser extent, increased volumes of natural gas purchased for resale. The average Appalachian natural gas sales price decreased $0.22 per Mcf, or 8%, to $2.47, reducing operating revenues by approximately $12.3 million. In the Western Region, the average natural gas sales price also decreased $0.21 per Mcf, or 11%, to $1.73, reducing operating revenues by approximately $9.6 million. Lower spot market gas prices, both for Company production and the increased volume of natural gas purchased for resale, along with a change in the weighted mix of sales volumes due to sales from new operating areas, were the primary reasons the Company's overall weighted average natural gas sales price decreased $0.26 per Mcf to $2.14 compared with 1993. Crude oil and condensate sales increased 342 MBbl to 687 MBbl due primarily to the Harken acquisition (89 MBbl) and the WERCO acquisition (357 MBbl). 24
27 Costs and Expenses. Total costs and expenses increased $76.5 million, or 53%, to $222.1 million primarily due to expanded operations associated with the WERCO acquisition and an increase in natural gas purchased for resale: o The cost of natural gas purchases increased $48.3 million to $96.8 million. The WERCO acquisition increased this cost by $18.0 million. The remaining $30.3 million primarily was due to a 15.1 Bcf increase in natural gas purchased for resale, net of storage. o Direct operations expenses increased $4.7 million, or 16%, primarily due to $3.7 million of operating expenses attributable to the WERCO acquisition and $1.6 million increased operating expenses attributable to the first full year of operations on the Emax and Harken acquisitions. Direct operations expense per Mcfe of production decreased $0.07, or 12%, to $0.53 due to increased production primarily attributable to the WERCO acquisition. o Exploration expense increased $1.1 million due to the WERCO acquisition. o Depreciation, depletion, amortization and impairment expense increased $20.1 million, or 58%, primarily due to the Harken, Emax and WERCO acquisitions. DD&A and impairment expense per Mcfe of production increased $0.15, or 21%, to $0.86 due primarily to the acquisitions in general and further affected by the required accounting treatment of the tax free nature of the WERCO acquisition. o General and administrative expenses decreased $0.7 million, or 4%, excluding $0.4 million attributable to the WERCO acquisition, primarily due to reduced fringe benefit and employee-related expenses. General and administrative expenses per Mcfe of production decreased $0.09, or 25%, to $0.27 due to the expanded production base, primarily from the WERCO acquisition. o Taxes other than income increased $2.7 million, or 28%, primarily due to the WERCO acquisition. This expense remained virtually unchanged on a unit of production basis. Interest expense increased $6.3 million, or 61%, primarily due to a $99 million debt increase and an increase in the interest rate attributable to the Company's revolving credit facility. The WERCO acquisition and the purchase of additional drilling locations in connection with the Emax acquisition accounted for $84.7 million, or 86%, of the debt increase. Income tax expense decreased $6.8 million (to a $0.6 million benefit) due to the decrease in 1994 earnings before income taxes and a $2.9 million charge in the third quarter of 1993 to record an increase in the federal income tax rate. The dividend requirement on preferred stock increased $3.0 million due primarily to the $2.3 million associated with the 6% convertible redeemable preferred stock issued in connection with the WERCO acquisition. The remaining $0.7 million increase was attributable to the $3.125 cumulative convertible preferred stock, issued May 3, 1993, for which only 8 months of dividends were reflected in the corresponding period of 1993. 25
28 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO CONSOLIDATED FINANCIAL STATEMENTS <TABLE> <CAPTION> Page --------------------------------------------------------------------------- <S> <C> Report of Independent Accountants 27 Consolidated Statement of Operations 28 Consolidated Balance Sheet 29 Consolidated Statement of Cash Flows 30 Consolidated Statement of Stockholders' Equity 31 Notes to Consolidated Financial Statements 32 Supplemental Oil & Gas Information 47 Quarterly Financial Information (Unaudited) 51 </TABLE> 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 1, 1996 Charles P. Siess, Jr. Chairman of the Board, Chief Executive Officer and President 26
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, 1995 and 1994, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 1995. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Cabot Oil & Gas Corporation as of December 31, 1995 and 1994, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 1995, 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 1, 1996 27
30 CABOT OIL & GAS CORPORATION CONSOLIDATED STATEMENT OF OPERATIONS <TABLE> <CAPTION> Year Ended December 31, (In thousands, except per share amounts) 1995 1994 1993 ---------------------------------------------------------------------------------------- <S> <C> <C> <C> REVENUES Natural Gas $ 196,609 $ 219,650 $ 154,792 Crude Oil and Condensate 11,089 11,445 5,715 Other 6,225 5,972 3,788 --------------------------------- 213,923 237,067 164,295 COSTS AND EXPENSES Costs of Natural Gas 92,840 96,772 48,479 Direct Operations 28,328 33,332 28,681 Exploration 8,031 8,014 6,943 Depreciation, Depletion and Amortization 47,206 51,040 31,621 Impairment of Long-Lived Assets (Note 15) 113,795 -- -- Impairment of Unproved Properties 5,047 3,556 2,834 General and Administrative 16,785 17,278 17,539 Cost Reduction Program (Note 12) 6,820 -- -- Taxes Other Than Income 11,215 12,141 9,490 --------------------------------- 330,067 222,133 145,587 GAIN (LOSS) ON SALE OF ASSETS (614) 79 1,299 --------------------------------- INCOME (LOSS) FROM OPERATIONS (116,758) 15,013 20,007 Interest Expense 24,885 16,651 10,328 --------------------------------- INCOME (LOSS) BEFORE INCOME TAX EXPENSE (141,643) (1,638) 9,679 Income Tax Expense (Benefit) (55,025) (643) 6,159 --------------------------------- NET INCOME (LOSS) (86,618) (995) 3,520 Dividend Requirement on Preferred Stock 5,553 4,449 1,432 --------------------------------- Net Income (Loss) Applicable to Common Stockholders $ (92,171) $ (5,444) $ 2,088 ================================= Earnings (Loss) Per Share Applicable to Common Stockholders $ (4.05) $ (0.25) $ 0.10 ================================= Average Common Shares Outstanding 22,775 22,018 20,507 ================================= </TABLE> - ------------------------------------------------------------------------------- The accompanying notes are an integral part of these consolidated financial statements. 28
31 CABOT OIL & GAS CORPORATION CONSOLIDATED BALANCE SHEET <TABLE> <CAPTION> December 31, (In thousands) 1995 1994 ------------------------------------------------------------------------------- <S> <C> <C> ASSETS CURRENT ASSETS Cash and Cash Equivalents $ 3,029 $ 3,773 Accounts Receivable 42,014 38,166 Inventories 5,596 8,384 Other 1,709 1,696 --------------------- Total Current Assets 52,348 52,019 PROPERTIES AND EQUIPMENT (Successful Efforts Method) 474,371 634,934 OTHER ASSETS 1,436 1,399 --------------------- $ 528,155 $ 688,352 ===================== LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES Accounts Payable $ 48,122 $ 39,990 Accrued Liabilities 12,759 13,750 --------------------- Total Current Liabilities 60,881 53,740 LONG-TERM DEBT 249,000 268,363 DEFERRED INCOME TAXES 62,752 117,807 OTHER LIABILITIES 7,666 5,360 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 1995 and 1994 -- 6% Convertible Redeemable Preferred; $50 Stated Value; 1,134,000 Shares in 1995 and 1994 183 183 Common Stock: Authorized -- 40,000,000 Shares of $0.10 Par Value Issued and Outstanding -- 22,783,319 Shares and 22,757,007 Shares at December 31, 1995 and 1994, respectively 2,278 2,275 Class B Common Stock: Authorized -- 800,000 Shares of $0.10 Par Value No Shares Issued -- -- Additional Paid-in Capital 242,058 241,471 Accumulated Deficit (96,663) (847) --------------------- Total Stockholders' Equity 147,856 243,082 --------------------- $ 528,155 $ 688,352 ===================== </TABLE> - -------------------------------------------------------------------------------- The accompanying notes are an integral part of these consolidated financial statements. 29
32 CABOT OIL & GAS CORPORATION CONSOLIDATED STATEMENT OF CASH FLOWS <TABLE> <CAPTION> Year Ended December 31, (In thousands) 1995 1994 1993 ---------------------------------------------------------------------------------------- <S> <C> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES Net Income (Loss) $ (86,618) $ (995) $ 3,520 Adjustments to Reconcile Net Income (Loss) to Cash Provided by Operations: Depletion, Depreciation, and Amortization 47,206 51,040 31,621 Impairment of Long-Lived Assets 113,795 -- -- Impairment of Unproved Properties 5,047 3,556 2,834 Deferred Income Tax Expense (Benefit) (55,055) (796) 7,058 Loss (Gain) on Sale of Assets 614 (79) (1,299) Exploration Expense 8,031 8,014 6,943 Postretirement Benefits Other than Pension 1,742 (866) (339) Other, Net 1,436 (669) (67) Changes in Assets and Liabilities: Accounts Receivable (3,848) (2,870) (780) Inventories 2,788 (2,691) 65 Other Current Assets (13) (944) (395) Other Assets (37) (1,306) 147 Accounts Payable and Accrued Liabilities 5,838 16,167 5,591 Other Liabilities 565 (258) 551 --------------------------------- Net Cash Provided by Operations 41,491 67,303 55,450 --------------------------------- CASH FLOWS FROM INVESTING ACTIVITIES Capital Expenditures (24,672) (72,684) (94,377) Cost of Major Acquisition(1) 8,402 (78,525) -- Proceeds from Sale of Assets 10,291 400 2,410 Exploration Expense (8,031) (8,014) (6,943) --------------------------------- Net Cash Used by Investing (14,010) (158,823) (98,910) --------------------------------- CASH FLOWS FROM FINANCING ACTIVITIES Increase in Debt 16,000 125,833 67,720 Decrease in Debt (35,363) (27,000) (20,000) Exercise of Stock Options 348 654 1,742 Dividends Paid (9,210) (7,091) (4,207) --------------------------------- Net Cash Provided (Used) by Financing (28,225) 92,396 45,255 --------------------------------- Net Increase (Decrease) in Cash and Cash Equivalents (744) 876 1,795 Cash and Cash Equivalents, Beginning of Year 3,773 2,897 1,102 --------------------------------- Cash and Cash Equivalents, End of Year $ 3,029 $ 3,773 $ 2,897 ================================= </TABLE> - ----------------------------------------------------------------------------- (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. 30
33 CABOT OIL & GAS CORPORATION CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY <TABLE> <CAPTION> Retained Common Preferred Paid-In Earnings (In thousands) Stock Stock Capital (Deficit) Total --------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> Balance at December 31, 1992 2,046 -- 106,936 9,331 118,313 Net Income 3,520 3,520 Exercise of Stock Options 12 1,730 1,742 Issuance of Preferred Stock 69 34,552 34,621 Preferred Stock Dividends at $2.07 Per Share (1,432) (1,432) Common Stock Dividends at $0.16 Per Share (3,281) (3,281) Other 46 46 ------------------------------------------------------------ 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 at $2.44 Per Share (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 at $3.04 Per Share (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 ============================================================ </TABLE> - -------------------------------------------------------------------------------- The accompanying notes are an integral part of these consolidated financial statements. 31
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. In addition, the Company limits the total amount of unamortized capitalized costs to the value of future net revenues, based on current prices and costs. 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. 32
35 Costs of retired, sold or abandoned properties, constituting a part of an amortization base, are charged to accumulated depreciation, depletion, and amortization. Accordingly, gain or loss, if any, is recognized only when a group of proved properties (or field), constituting the amortization base, has been retired, abandoned or sold. 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 $6.2 million and $6.9 million at December 31, 1995 and 1994, respectively. EARNINGS (LOSS) PER COMMON SHARE Earnings (loss) per common share is computed by dividing net income (loss), as adjusted for 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 1993 and May 1994, 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. 33
36 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 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. The Company had certain hedge natural gas price swap contracts in December 1995 that were left 'uncovered' due to an unprecedented decoupling of the Nymex gas price from realizable sales prices in the physical markets. The unrealized loss attributable to these contracts was recorded currently. 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. Actual results could differ from those estimates. 2. PROPERTIES AND EQUIPMENT Properties and equipment are comprised of the following: <TABLE> <CAPTION> December 31, (In thousands) 1995 1994 ---------------------------------------------------------------------------- <S> <C> <C> Unproved Oil and Gas Properties $ 12,488 $ 20,847 Proved Oil and Gas Properties 800,373 796,390 Gathering and Pipeline Systems 146,330 146,131 Land, Building and Improvements 5,551 5,533 Other 15,243 13,875 --------------------- 979,985 982,776 Accumulated Depreciation, Depletion and Amortization (505,614) (347,842) --------------------- $ 474,371 $ 634,934 ===================== </TABLE> As a component of accumulated depreciation, depletion and amortization, total accrued future plug and abandonment cost was $15.0 million and $14.4 million at December 31, 1995 and 1994, respectively. The Company believes that this accrual adequately provides for its estimated future plug and abandonment cost. 34
37 3. ADDITIONAL BALANCE SHEET INFORMATION Certain balance sheet amounts are comprised of the following: <TABLE> <CAPTION> December 31, (In thousands) 1995 1994 ------------------------------------------------------------------------ <S> <C> <C> Accounts Receivable Trade Accounts $ 38,119 $ 36,246 Other Accounts 5,138 3,245 --------------------- 43,257 39,491 Allowance for Doubtful Accounts (1,243) (1,325) --------------------- $ 42,014 $ 38,166 ===================== Accounts Payable Trade Accounts $ 9,312 $ 10,818 Natural Gas Purchases 12,523 7,938 Royalty and Other Owners 10,842 12,691 Capital Costs 6,518 4,097 Dividends Payable 1,391 1,404 Taxes Other Than Income 749 690 Gas Price Swaps (Note 13) 3,205 -- Other Accounts 3,582 2,352 --------------------- $ 48,122 $ 39,990 ===================== Accrued Liabilities Employee Benefits $ 2,506 $ 3,182 Taxes Other Than Income 7,633 7,886 Interest Payable 1,883 1,742 Other Accrued 737 940 --------------------- $ 12,759 $ 13,750 ===================== Other Liabilities Postretirement Benefits Other Than Pension $ 2,640 $ 898 Accrued Pension Cost 3,144 2,299 Taxes Other Than Income 1,482 1,593 Other 400 570 --------------------- $ 7,666 $ 5,360 ===================== </TABLE> 4. INVENTORIES Inventories are comprised of the following: <TABLE> <CAPTION> December 31, (In thousands) 1995 1994 ------------------------------------------------------------------------ <S> <C> <C> Natural Gas in Storage $ 4,058 $ 5,777 Tubular Goods and Well Equipment 1,485 2,120 Pipeline Exchange Balances 53 487 --------------------- $ 5,596 $ 8,384 ===================== </TABLE> 35
38 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. At December 31, 1995 and 1994, no debt was outstanding under the line. 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 equal annual principal payments beginning in 1998. The Company may prepay all or any portion of the indebtedness on any date with a prepayment premium. Excluding the $2.6 million charge in December 1995 to terminate the remaining interest rate swaps, the Company's effective interest rates for the 10.18% Notes in the two years ended December 31, 1995 and 1994 were 12.6% and 10.65%, respectively, due to the impact of the interest rate swap instruments obtained in 1993 (see "Interest Rate Swap Agreements" under Note 13 Financial Instruments). 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. As of February 1996, the Company's available borrowing capacity is $315 million. 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, 1995, 1994 and 1993 were 6.8%, 5.7% and 4.6%, respectively. Although the revolving term of the Credit Facility expires in June 1996, 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 and commitment fees are subject to increase if the indebtedness 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) restricting certain payments associated with repurchasing equity securities of the Company or declaring dividends ("Restricted Payments", as defined in the Credit Facility), if immediately prior to or after giving effect to such payments, the aggregate of such Restricted Payments exceeds 15% of cash flows available for debt service, as defined in the Credit Facility, or an event of default has occurred under the Credit Facility. In addition, the Credit Facility prohibits the Company from incurring recourse indebtedness (determined on a consolidated basis) in excess of the debt limit (presently $315 million) subject to certain adjustments, including adjustments for sales or acquisitions of oil and gas properties and other changes in projected cash flows available for debt service. 36
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, 1995, 1994 and 1993 are comprised of the following: <TABLE> <CAPTION> (In thousands) 1995 1994 1993 - ------------------------------------------------------------------------------------------ <S> <C> <C> <C> QUALIFIED: Current Year Service Cost $ 722 $ 901 $ 816 Interest Accrued on Pension Obligation 742 652 578 Actual Return on Plan Assets (1,327) (428) (366) Net Amortization 934 102 118 Curtailment Gain (376) - - Special Termination Benefit 766 - - -------------------------------------- Net Periodic Pension Cost $ 1,461 1,227 1,146 ====================================== NON-QUALIFIED: Current Year Service Cost $ 63 $ 134 $ 84 Interest Accrued on Pension Obligation 23 32 5 Net Amortization 39 49 33 Curtailment Loss 37 - - Settlement Charge 174 - - -------------------------------------- Net Periodic Pension Cost $ 336 $ 215 $ 122 ====================================== </TABLE> The following table sets forth the funded status of the Company's pension plans at December 31, 1995 and 1994, respectively: <TABLE> <CAPTION> 1995 1994 (In thousands) Qualified Non-Qualified Qualified Non-Qualified - ----------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> Actuarial Present Value of: Vested Benefit Obligation $ 6,281 $ 65 $ 3,680 $ 68 Accumulated Benefit Obligation 6,864 83 4,258 182 Projected Benefit Obligation $ 10,069 $ 83 $ 8,395 $ 385 Plan Assets at Fair Value 6,417 - 4,861 - ------------------------------------------------ Projected Benefit Obligation in Excess of Plan Assets 3,652 83 3,534 385 Unrecognized Net Gain 1,232 44 972 70 Unrecognized Prior Service Cost (1,037) (423) (1,316) (537) ------------------------------------------------ Accrued (Prepaid) Pension Cost $ 3,847 $ (296) $ 3,190 $ (82) ================================================ </TABLE> 37
40 Assumptions used to determine benefit obligations and pension costs are as follows: <TABLE> <CAPTION> 1995 1994 1993 - -------------------------------------------------------------------------------------- <S> <C> <C> <C> Discount Rate 7.50%(1) 8.50% 7.50% Rate of Increase in Compensation Levels 4.50%(1) 5.50% 5.50% Long-Term Rate of Return on Plan Assets 9.00% 9.00% 9.00% - -------------------------------------------------------------------------------------- </TABLE> (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 $0.8 million, $0.9 million and $0.7 million in 1995, 1994, and 1993, 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 273 retirees and 234 retirees at the end of 1995 and 1994, 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 1995, 1994 and 1993, 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, 1995, 1994 and 1993 are comprised of the following: <TABLE> <CAPTION> (In thousands) 1995 1994 1993 - ------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> Service Cost of Benefits Earned During the Year $ 140 $ 152 $ 210 Interest Cost on the Accumulated Postretirement Benefit Obligation 517 470 667 Amortization Benefit of the Unrecognized Gain (249) (207) - Amortization Cost (Benefit) of the Unrecognized Transition Obligation (821) (859) (858) Curtailment Loss 2,074 - - Special Termination 503 - - ---------------------------- Total Postretirement Benefit Cost (Benefit) $ 2,164 $ (444) $ 19 ============================ </TABLE> The health care cost trend rate used to measure the expected cost in 1996 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 1996 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. 38
41 The weighted average discount rate used in determining the actuarial present value of the benefit obligation at December 31, 1995 and 1994 was 7.5% and 8.5%, respectively. A one-percentage-point increase in health care cost trend rates for future periods would increase the accumulated net postretirement benefit obligation by approximately $265 thousand and, accordingly, the total postretirement benefit cost recognized in 1995 would have also increased by approximately $25 thousand. The funded status of the Company's postretirement benefit obligation at December 31, 1995 and 1994 is comprised of the following: <TABLE> <CAPTION> (In thousands) 1995 1994 - --------------------------------------------------------------------------------------------------- <S> <C> <C> Plan Assets at Fair Value $ - $ - Accumulated Postretirement Benefits Other Than Pensions Retirees 5,512 4,007 Active Participants 1,722 1,503 ---------------------------- 7,234 5,510 Unrecognized Cumulative Net Gain 2,546 3,735 Unrecognized Transition Obligation (6,779) (7,990) ---------------------------- Accrued Postretirement Benefit Liability $ 3,001 $ 1,255 ============================ </TABLE> 7. INCOME TAXES Income tax expense (benefit) is summarized as follows: <TABLE> <CAPTION> Year Ended December 31, (In thousands) 1995 1994 1993 - ------------------------------------------------------------------------------------------ <S> <C> <C> <C> CURRENT: Federal $ - $ - $ (796) State 30 153 (103) -------------------------------------- Total 30 153 (899) -------------------------------------- DEFERRED: Federal (46,430) (1,987) 4,909 State (8,625) 1,191 2,149 -------------------------------------- Total (55,055) (796) 7,058 -------------------------------------- Total Income Tax Expense (Benefit) $ (55,025) $ (643) $ 6,159 ====================================== </TABLE> Total income taxes were different than the amounts computed by applying the statutory federal income tax rate as follows: <TABLE> <CAPTION> Year Ended December 31, (In thousands) 1995 1994 1993 - ------------------------------------------------------------------------------------------ <S> <C> <C> <C> Statutory Federal Income Tax Rate 35% 35% 35% Computed "Expected" Federal Income Tax $ (49,575) $ (574) $ 3,388 State Income Tax, Net of Federal Income Tax (5,586) 873 1,330 Other, Net 136 (942) 1,441 ---------------------------------------- Total Income Tax Expense (Benefit) $ (55,025) $ (643) $ 6,159 ======================================== </TABLE> 39
42 Income taxes for the year ended December 31, 1993 were increased by $2.3 million due to a change in the federal income tax rate. 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, 1995 and 1994 were as follows: <TABLE> <CAPTION> (In thousands) 1995 1994 - ---------------------------------------------------------------------------------------- <S> <C> <C> DEFERRED TAX LIABILITIES: Property, Plant and Equipment $ 110,582 $ 138,287 --------------------------- DEFERRED TAX ASSETS: Alternative Minimum Tax Credit Carryforwards 4,614 5,108 Net Operating Loss Carryforwards 22,620 11,748 Note Receivable on Section 29 Monetization(1) 15,048 - Items Accrued for Financial Reporting Purposes 5,548 3,624 --------------------------- 47,830 20,480 --------------------------- Net Deferred Tax Liabilities $ 62,752 $ 117,807 =========================== </TABLE> - -------------------------------------------------------------------------------- (1) As a result of the monetization of Section 29 tax credits, 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, 1995, the Company has a net operating loss carryforward for regular income tax reporting purposes of $59.5 million which will begin expiring in 2006. In addition, the Company has an alternative minimum tax credit carryforward of $4.6 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. 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 $4.9 million, $5.5 million and $5.0 million for the years ended December 31, 1995, 1994 and 1993, respectively. Future minimum rental commitments under non-cancelable leases in effect at December 31, 1995 are as follows: <TABLE> <CAPTION> (In thousands) --------------------------------------- <S> <C> 1996 $ 3,381 1997 2,958 1998 2,280 1999 1,614 2000 835 Thereafter 1,914 --------- $ 12,982 ========= </TABLE> Minimum rental commitments are not reduced by minimum sublease rental income of $2.1 million due in the future under non-cancelable subleases. 40
43 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 of any period but would not have a material adverse effect on the Company's financial position. In February 1993, Barby Energy Corporation and certain other parties filed suit in Beaver County, Oklahoma against the Company to determine the rights and interests of the parties in and to the oil, gas and other minerals underlying a tract of land in Beaver County, Oklahoma, to quiet title to said mineral estate, and for an accounting and payment of production proceeds attributable to said mineral estate. Specifically at issue is whether there was continuous production from an oil and gas well located on the property since July 5, 1965. Plaintiffs claim there was a cessation of production, and therefore, all right, title and interest to such property reverted to them and that they are entitled to all revenues from such production since the date cessation of production occurred. The Company believes that it holds a valid oil and gas lease covering the interest claimed by the plaintiffs. The trial commenced on February 6, 1995 and, pursuant to an order entered on February 13, 1995, the judge denied and overruled all of the plaintiffs' claims. Barby requested that the Oklahoma Supreme Court retain the case. Subsequently, the Oklahoma Supreme Court decided not to retain the case and assigned the appeal to the Oklahoma Court of Appeals. The Barby appeal has been stayed pending settlement discussions. In September 1995, Barby filed a separate action in state court in Oklahoma, purporting to represent all similarly situated royalty owners in Oklahoma, alleging improper calculation of royalties and seeking actual and punitive damages. The Company has denied the material allegations of the complaint. No formal discovery has yet been conducted. The action has been stayed pending settlement discussions. Although no assurances can be given, the Company believes that the ultimate outcome of the above litigation will not have a material adverse effect on the Company's financial position. 9. CASH FLOW INFORMATION Cash paid for interest and income taxes is as follows: <TABLE> <CAPTION> Year Ended December 31, (In thousands) 1995 1994 1993 - --------------------------------------------------------------------------------- <S> <C> <C> <C> Interest $ 24,744 $ 16,002 $ 10,536 Income Taxes $ 197 $ 210 $ 1,282 </TABLE> At December 31, 1995 and 1994, 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 1989, 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 41
44 the date of grant. The minimum exercise period for stock options is from the date of grant. No SARs have been granted under the Incentive Plans. Information regarding the Company's Incentive Plans is summarized below: <TABLE> <CAPTION> December 31, 1995 1994 1993 - --------------------------------------------------------------------------------- <S> <C> <C> <C> Shares Under Option at Beginning of Period 953,775 684,525 639,200 Granted 565,750 301,900 197,300 Exercised 2,400 12,050 126,835 Surrendered or Expired 206,807 20,600 25,140 ------------------------------------------ Shares Under Option at End of Period 1,310,318 953,775 684,525 ========================================== Option Price Range per Share at End of Period $ 13.25 - $ 13.25 - $ 13.25 - $ 26.00 $ 26.00 $ 26.00 Options Exercisable at End of Period 852,692 447,907 236,120 ========================================== </TABLE> Management is reviewing the newly issued Statement of Financial Accounting Standards ("SFAS") No. 123, "Accounting for Stock-Based Compensation", which will be effective for the Company's 1996 calendar year. The new pronouncement outlines a fair value based method of accounting for stock options or similar equity instruments. While the adoption of this fair value method is encouraged, it allows the Company to continue using the in intrinsic value based method, as prescribed by Accounting Principles Board ("APB") Opinion No. 25, to measure compensation cost for its stock option plans. Should the Company elect to remain with the intrinsic value method, pro forma disclosures of net income and earnings per share, using the fair value based method, must be presented. The Company is currently evaluating the impact, if any, of SFAS 123 on its future earnings and financial position and, accordingly, has not yet determined if it will adopt the new accounting method. 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 credit agreements restrict certain payments ("Restricted Payments," as defined in the credit agreements) 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 aggregate of such Restricted Payments exceeds 15% of cash flows available for debt service, as defined in the Credit Facility, or an event of default has occurred under the credit agreements. Furthermore, the Credit Facility specifies a minimum cash flow to debt service coverage ratio. As of December 31, 1995, 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 42
45 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, 1995, 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, 1995 and 1994, 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 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, 1995 and 1994 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 at any time by the holder into Common Stock at a conversion price of $28.75 per share, subject to adjustment. Starting on the fourth anniversary of the date of issuance, the 6% preferred stock is redeemable, in whole or in part, at the Company's option price of $50 per share. During the period between the fourth and fifth anniversary dates, the Company may opt to redeem the 6% preferred stock in shares of 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 the fifth anniversary date, 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 $207.8 million, comprised of cash and stock consideration of $167.6 million (net of an $8.4 million post-closing adjustment in 1995) and a $40.2 million non-cash component relating to 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. 43
46 The Company issued 2,133,000 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. The pro forma results of operations in 1994, had the WERCO acquisition occurred at the beginning of 1994, were total revenue of $259.1 million, net loss applicable to common shareholders of $7.3 million and net loss per common share of $0.32. These pro forma results do not purport to be indicative of the results of future operations, nor the results of historical operations had the acquisition occurred as of the assumed date. 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 workforce 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 workforce, including 24 employees who elected early retirement. The employee terminations were made in virtually all departments both at the Company's corporate headquarters and each of the operating region/area offices. The termination benefits included $3.8 million for severance and related costs, which were paid out by year end and a $3.0 million non-cash charge for curtailments to the Company's pension ($0.4 million) and postretirement ($2.6 million) benefits plans. 13. FINANCIAL INSTRUMENTS The following disclosures on the estimated fair value of financial instruments are presented in accordance with SFAS 107, "Disclosures about Fair Value of Financial Instruments". Fair value, as defined in SFAS 107, is the amount at which the instrument could be exchanged currently between willing parties. The Company uses available marketing data and valuation methodologies to estimate fair value of debt. <TABLE> <CAPTION> December 31, 1995 December 31, 1994 Carrying Estimated Carrying Estimated (In thousands) Amount Fair Value Amount Fair Value - ---------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> DEBT: 10.18% Notes $ 80,000 $ 89,258 $ 80,000 $ 84,700 Credit Facility 169,000 169,000 188,000 188,000 Other Note Payable - - 363 386 ------------------------------------------------------------ $ 249,000 $ 258,258 $ 268,363 $ 273,086 ============================================================ OTHER FINANCIAL INSTRUMENTS: Interest Rate Swaps $ - $ - $ - $ (5,296) Gas Price Swaps - (4,176) - (1,010) </TABLE> 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. 44
47 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 (see "Risk Management Activities" under Note 1). 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 six 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 1995, the fixed prices received on closed contracts ranged from $1.61 to $2.27 per MMbtu on total notional quantities of 3,565,000 MMbtu. Eight fixed price swap contracts were open at December 31, 1995 with fixed prices from $1.82 to $2.54 per MMbtu, contract periods extending to April 1996 and open notional quantities totaling 16,085,000 MMbtu. In the other natural gas price swap contract closed in 1995, the Company received the variable price and paid a fixed price ("variable price swap contract") of $1.60 per MMbtu on total notional quantities of 5,475,000 MMbtu. The Company used this variable price swap contract to partially hedge the price of third-party purchased gas used to supply a long-term, fixed price contract. 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 totalling 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 and will continue to mark these 'uncovered' hedge contracts to market until they are closed. Excluding the 'uncovered' hedge contracts, the estimated fair value of price swaps in the table above are for hedged transactions in which gains or losses are recognized in results of operations over the periods that production or purchased gas is hedged (see "Risk Management Activities" under Note 1). 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 1995, these agreements had total notional quantities of 1,925,000 MMbtu in closed contracts and another 1,260,000 MMbtu in open contracts at December 31, 1995. The Company is exposed to market risk on these open contracts to the extent of changes in market prices for natural gas. However, the market risk exposure on these hedged contracts is generally offset by the gain or loss recognized upon the ultimate sale of the natural gas that is hedged. CREDIT RISK Although notional contract amounts are used to express the volume of gas price and interest rate swap agreements, the amounts potentially subject to credit risk, in the event of non-performance by third parties, are substantially smaller. The Company does not anticipate any material impact to its financial results due to non-performance by the third parties. 45
48 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 Western Region, obtaining proceeds of $7.6 million. 17. OTHER REVENUE The Company recorded $4.6 million ($4.3 million net of severance taxes) 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 In September and November 1995, the Company completed two transactions 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 which was recorded as a reduction to the net book value of natural gas properties, and will generate additional revenues through 2002 estimated at $20 million ($3.0 million projected 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. 46
49 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, 1995, 1994 and 1993 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 8, 1996 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 1995 were reasonable in the aggregate. No major discovery or other favorable or adverse event subsequent to December 31, 1995 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. <TABLE> <CAPTION> Natural Gas ------------------------------------ December 31, (Millions of cubic feet) 1995 1994 1993 - ---------------------------------------------------------------------------------------- <S> <C> <C> <C> PROVED RESERVES Beginning of Year 953,083 808,280 724,666 Revisions of Prior Estimates 14,032 (24,627) (18,270) Extensions, Discoveries and Other Additions 34,408 64,829 58,265 Production (57,721) (58,319) (46,050) Purchases of Reserves in Place 1,416 168,957 93,131 Sales of Reserves in Place (55,368) (6,037) (3,462) ------------------------------------ End of Year 889,850 953,083 808,280 ==================================== PROVED DEVELOPED RESERVES 747,235 805,913 669,672 ==================================== </TABLE> 47
50 <TABLE> <CAPTION> Liquids ------------------------------------ December 31, (Thousands of barrels) 1995 1994 1993 - ----------------------------------------------------------------------------------------- <S> <C> <C> <C> PROVED RESERVES Beginning of Year 8,036 2,826 1,799 Revisions of Prior Estimates (648) (98) (355) Extensions, Discoveries and Other Additions 174 181 437 Production (740) (824) (345) Purchases of Reserves in Place 15 5,992 1,331 Sales of Reserves in Place (1,527) (41) (41) ------------------------------------ End of Year 5,310 8,036 2,826 ==================================== PROVED DEVELOPED RESERVES 4,970 7,704 2,346 ==================================== </TABLE> 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. <TABLE> <CAPTION> Year Ended December 31, (In thousands) 1995 1994 1993 - ---------------------------------------------------------------------------------------- <S> <C> <C> <C> Aggregate Capitalized Costs Relating to Oil and Gas Producing Activities $ 977,885 $ 980,676 $ 696,520 ========================================== Aggregate Accumulated Depreciation, Depletion and Amortization $ 503,757 $ 346,080 $ 296,764 ========================================== </TABLE> COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES AND FINDING AND DEVELOPMENT COSTS OF PROVED RESERVES Costs incurred in property acquisition, exploration and development activities were as follows: <TABLE> <CAPTION> Year Ended December 31, (In thousands) 1995 1994 1993 - --------------------------------------------------------------------------------------- <S> <C> <C> <C> Property Acquisition Costs - Proved $ 33 $ 184,835 $ 82,364 Property Acquisition Costs - Unproved 2,006 4,685 3,893 Exploration and Extension Well Costs 8,670 9,402 7,487 Development Costs 18,610 46,463 34,183 ----------------------------------------- Total costs $ 29,319 $ 245,385 $ 127,927 ========================================= (A) Proved Reserves of Additions and Revisions, MMcfe 45,600 40,700 40,500 ----------------------------------------- (B) Proved Reserves of (A) Above, Plus Purchases of Reserves in Place, MMcfe 47,100 245,600 141,600 ----------------------------------------- Calculated Finding and Development Cost of Proved Reserves, (A) Above, $/Mcfe(1) $ 0.55 $ 1.04 $ 0.96 ----------------------------------------- Calculated Finding and Development Cost of Proved Reserves, (B) Above, $/Mcfe(1) $ 0.53 $ 0.98 $ 0.88 ----------------------------------------- </TABLE> - -------------------------------------------------------------------------------- (1) Exploration expenses that are administrative in nature are excluded from the finding and development cost calculation. 48
51 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: <TABLE> <CAPTION> Year Ended December 31, (In thousands) 1995 1994 1993 - --------------------------------------------------------------------------------------- <S> <C> <C> <C> Operating Revenues $ 110,418 $ 126,307 $ 105,247 Costs and Expenses Production 34,062 39,114 31,065 Other Operating 22,783 16,787 17,476 Exploration 8,031 8,014 6,943 Depreciation, Depletion and Amortization 161,886 48,075 31,648 ----------------------------------------- Total Cost and Expenses 226,762 111,990 87,132 ----------------------------------------- Income (Loss) Before Income Taxes (116,344) 14,317 18,115 Provision for Income Taxes Expense (Benefit) (40,720) 5,011 6,340 ----------------------------------------- Results of Operations $ (75,624) $ 9,306 $ 11,775 ========================================= </TABLE> 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, 1995, 1994 and 1993 were for oil ($/Bbl) $17.06, $18.34 and $16.20, respectively, and for natural gas ($/Mcf) $2.06, $1.88 and $2.40, 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. 49
52 Standardized Measure is as follows: <TABLE> <CAPTION> Year Ended December 31, (In thousands) 1995(1) 1994 1993 - ---------------------------------------------------------------------------------------- <S> <C> <C> <C> Future Cash Inflows $ 2,194,751 $ 2,219,559 $ 2,190,400 Future Production and Development Costs (644,586) (723,767) (670,390) ----------------------------------------------- Future Net Cash Flows Before Income Taxes 1,550,165 1,495,792 1,520,010 10% Annual Discount for Estimated Timing of Cash Flows (884,861) (880,130) (878,912) ----------------------------------------------- Standardized Measure of Discounted Future Net Cash Flows Before Income Taxes 665,304 615,662 641,098 Future Income Tax Expenses, Net of 10% Annual Discount(2) (152,356) (125,167) (173,198) ----------------------------------------------- Standardized Measure of Discounted Future Net Cash Flows $ 512,948 $ 490,495 $ 467,900 =============================================== - ---------------------------------------------------------------------------------------- </TABLE> (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 $462,058, $433,212 and $480,817 for the years ended December 31, 1995, 1994 and 1993, 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: <TABLE> <CAPTION> Year Ended December 31, (In thousands) 1995 1994 1993 - --------------------------------------------------------------------------------------- <S> <C> <C> <C> Beginning of Year $ 490,495 $ 467,900 $ 404,577 Discoveries and Extensions, Net of Related Future Costs 21,881 24,188 48,183 Net Changes in Prices and Production Costs 57,057 (133,750) (53,822) Accretion of Discount 61,566 64,110 57,989 Revisions of Previous Quantity Estimates, Timing and Other 1,707 (32,654) (33,731) Development Costs Incurred 5,665 16,631 18,617 Sales and Transfers, Net of Production Costs (76,356) (87,193) (74,182) Net Purchases (Sales) of Reserves in Place (21,878) 123,232 98,159 Net Change in Income Taxes (27,189) 48,031 2,110 ----------------------------------------------- End of Year $ 512,948 $ 490,495 $ 467,900 =============================================== </TABLE> 50
53 CABOT OIL & GAS CORPORATION SELECTED DATA (UNAUDITED) QUARTERLY FINANCIAL INFORMATION (UNAUDITED) <TABLE> <CAPTION> (In thousands except per share amounts) First Second Third Fourth Total - ------------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> 1995 Total Revenues $ 58,122 $ 51,352 $ 47,982 $ 56,467 $ 213,923 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) 1994 Total Revenues $ 65,840 $ 56,453 $ 55,758 $ 59,016 237,067 Operating Income 11,580 1,513 (423) 2,343 15,013 Net Income (Loss) 4,682 (2,480) (4,441) (3,205) (5,444) Earnings (Loss) Per Share $ 0.23 $ (0.11) $ (0.20) $ (0.14) $ (0.25) - ------------------------------------------------------------------------------------------------------------------- </TABLE> (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 1996 annual stockholders meeting is incorporated herein by reference. ITEM 11. EXECUTIVE COMPENSATION The information appearing under the captions "Executive Compensation" and "Severance Arrangements" 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. 51
54 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, SCHEDULES AND REPORTS ON FORM 8-K A. INDEX 1. CONSOLIDATED FINANCIAL STATEMENTS See Index on page 26 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. <TABLE> <CAPTION> Exhibit Number Description - -------------------------------------------------------------------------------- <S> <C> 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. 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. 10.2 Form of Change in Control Agreement between the Company and Certain Officers. 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). </TABLE> 52
55 <TABLE> <S> <C> 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). 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. 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. 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. 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 8, 1996. </TABLE> B. REPORTS ON FORM 8-K None 53
56 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 23rd day of February 1996. 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. <TABLE> <CAPTION> Signature Title Date - ------------------------------------------------------------------------------------------------------------------- <S> <C> <C> /s/ Charles P. Siess, Jr. Chairman of the Board, February 23, 1996 - ---------------------------------- Chief Executive Officer and President Charles P. Siess, Jr. (Principal Executive Officer) /s/ Ray R. Seegmiller Vice President, Chief Financial Officer February 23, 1996 - ---------------------------------- and Treasurer Ray R. Seegmiller /s/ Frank A. Pici Controller (Principal Accounting Officer) February 23, 1996 - ---------------------------------- Frank A. Pici /s/ Robert F. Bailey Director February 23, 1996 - ---------------------------------- Robert F. Bailey /s/ Samuel W. Bodman Director February 23, 1996 - ---------------------------------- Samuel W. Bodman /s/ Henry O. Boswell Director February 23, 1996 - ---------------------------------- Henry O. Boswell /s/ John G. L. Cabot Director February 23, 1996 - ---------------------------------- John G. L. Cabot /s/ William R. Esler Director February 23, 1996 - ---------------------------------- William R. Esler /s/ William H. Knoell Director February 23, 1996 - ---------------------------------- William H. Knoell /s/ Carl M. Mueller Director February 28, 1996 - ---------------------------------- Carl M. Mueller /s/ C. Wayne Nance Director February 23, 1996 - ---------------------------------- C. Wayne Nance /s/ William P. Vititoe Director February 23, 1996 - ---------------------------------- William P. Vititoe </TABLE> 54
57 EXHIBIT INDEX Exhibit Number Description - -------------------------------------------------------------------------------- 3.2 Amended and Restated Bylaws of the Company adopted August 5, 1994. 4.3 (a) Amendment No. 1 to the Rights Agreement dated February 24, 1994. 4.5 Amended and Restated Credit Agreement dated as of May 30, 1995 among the Company, Morgan Guaranty Trust Company, as agent and the banks named therein. (a) Amendment No. 1 to Credit Agreement dated September 15, 1995. 10.1 Supplemental Executive Retirement Agreement between the Company and Charles P. Siess, Jr. 10.2 Form of Change in Control Agreement between the Company and Certain Officers. 10.10 (c) First through Fifth Amendments to the Trust Agreement. 10.14 (b) Second Amendment to 1990 Nonemployee Director Stock Option Plan. 10.17 Employment Agreement between the Company and Ray R. Seegmiller dated September 25, 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 8, 1996.