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, 2000 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) 1200 Enclave Parkway, Houston, Texas 77077 (Address of principal executive offices including ZIP code) (281) 589-4600 (Registrant's telephone number) Securities registered pursuant to Section 12(b) of the Act: Name of each exchange Title of each class on which registered Class A Common Stock, par value $.10 per share New York Stock Exchange Rights to Purchase Preferred Stock New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. Yes X No _______ ----- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K [__]. This report contains 69 pages and four exhibits. 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 January 31, 2001), was approximately $815,000,000. As of January 31, 2001, there were 29,280,349 shares of Common Stock outstanding. DOCUMENTS INCORPORATED BY REFERENCE Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held May 3, 2001, are incorporated herein by reference in Items 10, 11, 12 and 13 of Part III of this report. TABLE OF CONTENTS PART I PAGE ITEMS 1 and 2 Business and Properties 3 ITEM 3 Legal Proceedings 17 ITEM 4 Submission of Matters to a Vote of Security Holders 18 Executive Officers of the Registrant 18 PART II ITEM 5 Market for Registrant's Common Equity and Related Stockholder Matters 19 ITEM 6 Selected Historical Financial Data 19 ITEM 7 Management's Discussion and Analysis of Financial Condition and Results of Operations 20 ITEM 7A Quantitative and Qualitative Disclosures about Market Risk 30 ITEM 8 Financial Statements and Supplementary Data 35 ITEM 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 65 PART III ITEM 10 Directors and Executive Officers of the Registrant 65 ITEM 11 Executive Compensation 65 ITEM 12 Security Ownership of Certain Beneficial Owners and Management 65 ITEM 13 Certain Relationships and Related Transactions 65 PART IV ITEM 14 Exhibits, Financial Statements, Schedules and Reports on Form 8-K 66 ___________________ The statements regarding future financial and operating performance and results, and market prices and future hedging activities, and other statements that are not historical facts contained in this report are forward-looking statements. The words "expect," "project," "estimate," "believe," "anticipate," "intend," "budget," "plan," "forecast," "predict" and similar expressions are also intended to identify forward-looking statements. These statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including regional basis differentials) of natural gas and oil, results for future drilling and marketing activity, future production and costs, and other factors detailed in this document and in our other Securities and Exchange Commission filings. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual outcomes may vary materially from those included in this document. 2 PART I ITEM 1. BUSINESS OVERVIEW Cabot Oil & Gas is an independent oil and gas company engaged in the exploration, development, acquisition and exploitation of oil and gas properties located in four principal areas of the United States: . The onshore Texas and Louisiana Gulf Coast . The Rocky Mountains . Appalachia . The Mid-Continent or Anadarko Basin Administratively, we operate in three regions - the Gulf Coast region, the Western region, which is comprised of the Rocky Mountains and Mid-Continent areas, and the Appalachian region. Until a few years ago, our core holdings were long-lived Appalachian natural gas reserves. We have used the cash flow from these properties, together with strategic acquisitions, to shift the focus of our exploration efforts to the Gulf Coast and Rocky Mountain areas. We believe these core producing areas offer more value, accretive reserve and production growth and higher rates of return on equity. Meanwhile, we have been rationalizing our Appalachian operations by selective divestitures. In 2001, 48% of our capital budget is allocated to the Gulf Coast, 18% to the Rocky Mountains, 26% to Appalachia and the remaining 8% to the Mid-Continent area. While about 40% of our proved reserves are located in Appalachia, reflecting the fact that we have operated there for more than a century, this proportion has declined as our production and reserves in the Gulf Coast and Rocky Mountains have grown. In 1998, we participated in a 300 square mile 3D seismic shoot with Union Pacific Resources Group, Inc. in south Louisiana and identified several deep, high-potential exploratory prospects. We have drilled five successful wells in five attempts with one additional well drilling at the end of 2000 on these prospects. These successes include Etouffee, Bon Ton and Augen. Our 2001 drilling plan for this acreage includes four high-growth, high-potential wells. Additional exploratory opportunities exist in this prospect area. Concurrent with this project, we acquired $70.1 million of developed and undeveloped properties from Oryx Energy Company also in south Louisiana. During 1999, we increased our Gulf Coast production significantly through the completion of several workover projects on wells acquired from Oryx. At the same time, we actively reprocessed 3D seismic data acquired from Oryx, the interpretation of which yielded five, high-potential exploratory prospects. One of these prospects was successfully drilled in 2000 with another in-progress at the end of 2000. Our 2001 capital spending program includes plans to drill two more of these prospects and we expect to drill another in 2002. The success of these projects in the Gulf Coast region has increased our daily production from 15 Mmcfe per day in October 1998 to over 70 Mmcfe per day in December 2000. We continue to acquire additional 3D seismic and leases in the Gulf Coast area. In addition, our 2001 drilling program includes plans to drill additional wells in south Louisiana, as we continue to focus our exploratory efforts on this high-growth, high-potential region. As of December 31, 2000, our proved reserves totaled just over 1.0 Tcfe, 94% of which was natural gas. We operate approximately 83% of the wells in which we hold an interest. Daily production averaged 180.5 Mmcfe per day during the first nine months of the year before increasing to approximately 185 Mmcfe per day in October and November. December was the first month in which we reached full production rates from our recent exploratory wells in south Louisiana, which brought the average for that month to approximately 197 Mmcfe per day. 3 The following table presents certain information as of December 31, 2000. West -------------------------------- Gulf Rocky Mid- Total Coast Mountains Continent West Appalachia Total -------- ---------- ---------- -------- ----------- ---------- Proved Reserves at Year End (Bcfe) Developed 110.9 192.1 188.9 381.0 313.7 805.6 Undeveloped 33.1 54.0 29.2 83.2 96.8 213.1 ------- ------- ------- ------- --------- --------- Total 144.0 246.1 218.1 464.2 410.5 1,018.7 Average Daily Production (Mmcfe per day) 49.5 51.2 32.8 84.0 49.2 182.7 Reserves Life Index (in years) /(1)/ 7.9 13.1 18.2 15.1 22.8 15.2 Gross Productive Wells 384 490 672 1,162 2,243 3,789 Net Productive Wells 292.6 228.2 447.2 675.4 2,079.2 3,047.2 Percent Wells Operated 59.4% 48.8% 74.1% 63.4% 97.1% 82.9% Net Acreage Developed 50,673 81,940 184,399 266,339 743,540 1,060,552 Undeveloped 60,757 117,828 13,242 131,070 300,985 492,812 ------- ------- ------- ------- --------- --------- Total 111,430 199,768 197,641 397,409 1,044,525 1,553,364 _______________________________________________________________________________ /(1)/ Reserve Life Index is equal to year-end reserves divided by annual production. GULF COAST REGION Our exploration, development and production activities in Gulf Coast region are concentrated in south Louisiana and south Texas. A regional office in Houston manages operations. Principal producing intervals are in the Wilcox and Vicksburg formations in Texas and the Miocene age formations in Louisiana at depths ranging from 3,000 to 20,500 feet. Capital and exploration expenditures were $66.0 million in 2000, or 54% of our total 2000 capital and exploration expenditures, and $36.8 million for 1999. Our drilling and acquisition program has increased average daily production in the region from 15.6 Mmcfe per day in 1994, when we acquired our first Gulf Coast properties from Washington Energy, to 71.3 Mmcfe per day in December 2000. For 2001, we have budgeted $79.3 million (48% of our total 2001 capital budget) for capital expenditures in the region. Our 2001 Gulf Coast drilling program emphasizes our exploration opportunities. We had 384 productive wells (292.6 net) in the Gulf Coast region as of December 31, 2000, of which 228 wells are operated by us. Average net daily production in 2000 was 49.5 Mmcfe, down from 52.0 Mmcfe in 1999 due to delays in bringing production on-line early in 2000 from new wells not operated by us. However, production from our drilling activity, which came on later in the year, brought the average daily production rate to 71.3 Mmcfe for the month of December 2000. At December 31, 2000, we had 144.0 Bcfe of proved reserves (74% natural gas) in the Gulf Coast region, which was 14% of our total proved reserves. In 2000, we drilled 23 wells (11.2 net) in the Gulf Coast region, of which 17 wells (8.0 net) were development wells. We did not begin to realize the full impact of our drilling successes in this region until late 2000. At year end, the south Louisiana Etouffee prospect along with our new discoveries in the Augen, Krescent and Bon Ton prospects in south Louisiana contributed to the significant growth in net proved reserves. In the Gulf Coast region, we plan to drill 29 wells in 2001. At December 31, 2000, we had 111,430 net acres in the region, including 50,673 net developed, and we had identified 13 proved undeveloped drilling locations. Our principal markets for Gulf Coast region natural gas are in the industrialized Gulf Coast area and the northeastern United States. Our marketing subsidiary, Cabot Oil & Gas Marketing Corporation, purchases all of our natural gas production in the Gulf Coast region. The marketing subsidiary sells the natural gas to intrastate pipelines, natural gas processors and marketing companies. 4 Currently, the majority of our natural gas sales volumes in the Gulf Coast region are sold at index-based prices under contracts with terms of one to three years. From time to time, we may also use hedges on a portion of our production to reduce the potential risk of falling prices when we believe market conditions are favorable. The Gulf Coast properties are connected to various processing plants in Texas and Louisiana with multiple interstate and intrastate deliveries, affording us access to multiple markets. We also produce and market approximately 2,000 barrels per day of crude oil/condensate in the Gulf Coast region at market-responsive prices. WESTERN REGION Our activities in the Western region are managed by a regional office in Denver. At December 31, 2000, we had 464.2 Bcfe of proved reserves (96% natural gas) in the Western region, constituting 46% of our total proved reserves. Rocky Mountains Our Rocky Mountains activities are concentrated in the Green River Basin and Washakie Basin of Wyoming. Since our initial acquisition in the area in 1994 from Washington Energy, we have increased reserves from 171.6 Bcfe at December 31, 1994, to 246.1 Bcfe at December 31, 2000. Capital and exploration expenditures were $23.9 million for 2000, or 20% of our total 2000 capital and exploration expenditures, and $29.5 million for 1999, including $17.4 million for property acquisitions. For 2001, we have budgeted $29.6 million (18% of our total 2001 capital budget) for capital expenditures in the area. The 2001 drilling program consists of several new exploration plays complemented by development drilling. We had 490 productive wells (228.2 net) in the Rocky Mountains area as of December 31, 2000, of which 239 wells are operated by us. Principal producing intervals in the Rocky Mountains area are in the Frontier and Dakota formations at depths ranging from 9,000 to 13,500 feet. Average net daily production in 2000 was 51.2 Mmcfe. In 2000, we drilled 26 wells (15.8 net) in the Rocky Mountains, of which 25 wells (15.3 net) were development and extension wells. In 2001, we plan to drill 46 wells. At December 31, 2000, we had 199,768 net acres in the area, including 81,940 net developed acres, and we had identified 81 proved undeveloped drilling locations. Mid-Continent Our Mid-Continent activities are concentrated in the Anadarko Basin in southwestern Kansas, Oklahoma and the panhandle of Texas. Capital and exploration expenditures were $7.6 million for 2000, or 6% of our total 2000 capital and exploration expenditures, and $4.1 million for 1999. For 2001, we have budgeted $13.5 million (8% of our total 2001 capital budget) for capital expenditures in the area. As of December 31, 2000, we had 672 productive wells (447.2 net) in the Mid-Continent area, of which 498 wells are operated by us. Principal producing intervals in the Mid-Continent are in the Chase, Morrow, Red Fork and Chester formations at depths ranging from 1,500 to 14,000 feet. Average net daily production in 2000 was 32.8 Mmcfe. At December 31, 2000, we had 218.1 Bcfe of proved reserves (97% natural gas) in the Mid-Continent area, 21% of our total proved reserves. In 2000, we drilled 19 wells (12.6 net) in the Mid-Continent, of which 18 wells (12.3 net) were development and extension wells. In 2001, we plan to drill 35 wells. At December 31, 2000, we had 197,641 net acres in the area, including 184,399 net developed acres, and we had identified 67 proved undeveloped drilling locations. 5 Western Region Marketing Our principal markets for Western region natural gas are in the northwestern, midwestern and northeastern United States. Cabot Oil & Gas Marketing purchases all of our natural gas production in the Western region. This marketing subsidiary sells the natural gas to power generators, natural gas processors, local distribution companies, industrial customers and marketing companies. Currently, the majority of our natural gas production in the Western region is sold primarily under contracts with a term of one to three years at index- based prices. From time to time, we may also use hedges on a portion of our production to reduce the potential risk of falling prices when we believe market conditions are favorable. The Western region properties are connected to the majority of the midwestern and northwestern interstate and intrastate pipelines, affording us access to multiple markets. In December 1999, we negotiated the buyout of a long-term, fixed price sales contract that covered approximately 20% of the Western region natural gas production and expired in June 2008. We received a payment of $12 million as part of this buyout agreement. This contract was then replaced with a fixed price sales contract that expires in April 2001. The fixed natural gas sales price in both the original natural gas sales contract and the replacement sales contract was below the market price at year end. After April 2001, we expect that this production will be sold at market responsive prices. We also produce and market approximately 700 barrels of crude oil/condensate per day in the Western region at market-responsive prices. APPALACHIAN REGION Our Appalachian activities are concentrated in Pennsylvania, Ohio, West Virginia and Virginia. We believe that our large undeveloped acreage position, high concentration of wells, natural gas gathering and pipeline systems, and storage capacity give us a competitive advantage in the region. We have achieved a drilling success rate of 89% in the region since 1991. Capital and exploration expenditures were $21.5 million for 2000, or 18% of our total 2000 capital spending, and $14.6 million for 1999. For 2001, we have budgeted $43.1 million (26% of our total 2001 capital budget) for capital expenditures in the region. At December 31, 2000, we had 2,243 productive wells (2,079.2 net), of which 2,177 wells are operated by us. There are multiple producing intervals that include the Devonian Shale, Oriskany, Berea and Big Lime formations at depths primarily ranging from 1,500 to 9,000 feet. Average net daily production in 2000 was 49.2 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. At December 31, 2000, we had 410.6 Bcfe of proved reserves (substantially all natural gas) in the Appalachian region, constituting 40% of our total proved reserves. A regional office in Pittsburgh managed operations in this region until its closure in mid 2000. Currently this region is managed from our office in Charleston, West Virginia. In 2000, we drilled 61 wells (52.0 net) in the Appalachian region, of which 52 wells (45.7 net) were development wells. In 2001, we plan to drill 130 wells. At December 31, 2000, we had 1,044,525 net acres in the region, including 743,540 net developed, and we had identified 271 proved undeveloped drilling locations. The principal markets for our Appalachian region natural gas are in the northeastern United States. Cabot Oil & Gas Marketing purchases our 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 and gas marketers both on and off our pipeline and gathering system. Most of our natural gas sales volume in the Appalachian region is sold at index-based 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 5% of Appalachian production is sold on fixed price contracts that typically renew annually. From time to time, we 6 may also use hedges on a portion of our production to reduce the potential risk of falling prices when we believe market conditions are favorable. Our Appalachian natural gas production has historically sold at a higher realized price, or premium, compared to production from other producing regions due to its proximity to northeastern markets. While year-to-year fluctuations in that premium are normal due to changes in market conditions, this premium has typically been in the range of $0.40 to $0.50 per Mmbtu above the Henry Hub cash price throughout the 1990s. In 1999, however, the average premium declined to $0.27 per Mmbtu due to increases in supply in the eastern market. This decline continued into early 2000. However, late in 2000 and into early 2001, the premium has begun to increase again due to strengthening of demand and perceived market shortages. The average 2000 premium was approximately $0.30 per Mmbtu. Due to this recent volatility, we are not able to predict the level of this premium for the future. Ancillary to our exploration and production operations, we operate a number of gas gathering and transmission pipeline systems, made up of approximately 2,450 miles of pipeline with interconnects to three interstate transmission systems, seven local distribution companies and numerous end users as of the end of 2000. The majority of our pipeline infrastructure in West Virginia is regulated by the Federal Energy Regulatory Commission (FERC). As such, the transportation rates and terms of service of our pipeline subsidiary, Cranberry Pipeline Corporation, are subject to the rules and regulations of the FERC. Our natural gas gathering and transmission pipeline systems enable us to connect new wells quickly and to transport natural gas from the wellhead directly to interstate pipelines, local distribution companies and industrial end users. Control of our gathering and transmission pipeline systems also enables us to purchase, transport and sell natural gas produced by third parties. In addition, we can take part in development drilling operations without relying upon third parties to transport our natural gas while incurring only the incremental costs of pipeline and compressor additions to our system. We have two natural gas storage fields located in West Virginia with a combined working capacity of approximately 4 Bcf. We use 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 us to periodically increase the volume of natural gas that we can deliver by more than 40% above the volume that we could deliver solely from our production in the Appalachian region. The pipeline systems and storage fields are fully integrated with our operations. In addition, we own and operate two brine treatment plants that process and treat waste fluid generated during the drilling, completion and production of oil and gas wells. The first plant, near Franklin, Pennsylvania, began operating in 1985. It provides services primarily to other oil and gas producers in southwestern New York, eastern Ohio and western Pennsylvania. In April 1998, we acquired a second brine treatment plant in Indiana, Pennsylvania that had been in existence since 1987. RISK MANAGEMENT From time to time, when we believe that market conditions are favorable, we use certain financial instruments called derivatives to manage price risks associated with our production and brokering activities. While there are many different types of derivatives available, in 2000, we primarily employed natural gas and oil price swap and costless collar agreements to attempt to manage price risk more effectively. The price swaps call for payments to, or receipts from, counterparties based on the differential between a fixed and a variable gas price. The costless collar arrangements are put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period. They provide for payments to counterparties if the index price exceeds the ceiling and payments from the counterparties if the index price is below the floor. In December 2000, we entered into certain costless collar arrangements on half of our natural gas production for the months of February through October 2001. We have not traditionally used derivatives to hedge a large portion of our natural gas production, hedging only 9% of our total natural gas production with derivatives in the last five years. We will continue to evaluate the benefit of employing derivatives in the future. Please read Management's Discussion and Analysis of Financial Condition and Results of Operations - Commodity Price Swaps and Options for further discussion concerning our use of derivatives. 7 RESERVES Current Reserves The following table presents our estimated proved reserves at December 31, 2000. Natural Gas (Mmcf) Liquids/(1)/ (Mbbl) Total/(2) /(Mmcfe) - -------------------------------------------------------------------------------------------------------------------- Developed Undeveloped Total Developed Undeveloped Total Developed Undeveloped Total - -------------------------------------------------------------------------------------------------------------------- Gulf Coast 77,721 28,074 105,795 5,525 837 6,362 110,871 33,093 143,964 Rocky Mountains 182,790 50,446 233,236 1,550 587 2,137 192,090 53,969 246,059 Mid-Continent 182,927 28,911 211,838 990 52 1,042 188,867 29,222 218,089 Appalachia 311,524 96,829 408,353 373 0 373 313,762 96,829 410,591 ----------------------------------------------------------------------------------------------- Total 754,962 204,260 959,222 8,438 1,476 9,914 805,590 213,113 1,018,703 =============================================================================================== ________________________________________________________________________________ /(1)/ Liquids include crude oil, condensate and natural gas liquids (Ngl). /(2)/ Natural gas equivalents are determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil, condensate or natural gas liquids. The proved reserve estimates presented here were prepared by our petroleum engineering staff and reviewed by Miller and Lents, Ltd., independent petroleum engineers. For additional information regarding estimates of proved reserves, the review of such estimates by Miller and Lents, Ltd., and other information about our oil and gas reserves, see the Supplemental Oil and Gas Information to the Consolidated Financial Statements included in Item 8. A copy of the review letter by Miller and Lents, Ltd. has been filed as an exhibit to this Form 10-K. Our estimates of proved reserves in the table above are consistent with those filed by us with other federal agencies. Our reserves are sensitive to natural gas and crude oil sales prices and their effect on economic producing rates. Our reserves are based on oil and gas index prices in effect on the last day of December 2000. While the high year-end natural gas price had a significant impact on the present value of proved reserves as presented in the Supplemental Oil and Gas Information discussion beginning on page 61, our reserve volumes did not change appreciably due to the higher prices. There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control. Therefore, the reserve information 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 can not be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revising the original 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 depends primarily on the accuracy of the assumptions upon which they were based. In general, the volume of production from oil and gas properties declines as reserves are depleted. Except to the extent we acquire additional properties containing proved reserves or conduct successful exploration and development activities or both, our proved reserves will decline as reserves are produced. 8 Historical Reserves The following table presents our estimated proved reserves for the periods indicated. Natural Gas Oil & Liquids Total (Mmcf) (Mbbl) (Mmcfe) /(1)/ ------------------------------------------------------------------- December 31, 1997 903,428 5,869 938,643 ------------------------------------------------------------------- Revision of Prior Estimates (13,097) (1,644) (22,963) Extensions, Discoveries and Other Additions 94,892 835 99,904 Production (64,167) (736) (68,584) Purchases of Reserves in Place 76,234 3,353 96,353 Sales of Reserves in Place (534) -- (534) ------------------------------------------------------------------- December 31, 1998 996,756 7,677 1,042,819 ------------------------------------------------------------------- Revision of Prior Estimates (1,555) 128 (787) Extensions, Discoveries and Other Additions 52,781 1,292 60,535 Production (65,502) (963) (71,279) Purchases of Reserves in Place 26,515 361 28,685 Sales of Reserves in Place (79,393) (306) (81,232) ------------------------------------------------------------------- December 31, 1999 929,602 8,189 978,741 ------------------------------------------------------------------- Revision of Prior Estimates (14,796) 562 (11,423) Extensions, Discoveries and Other Additions 103,600 2,032 115,792 Production (60,934) (988) (66,872) Purchases of Reserves in Place 5,118 120 5,838 Sales of Reserves in Place (3,368) (1) (3,373) ------------------------------------------------------------------- December 31, 2000 959,222 9,914 1,018,703 =================================================================== Proved Developed Reserves December 31, 1997 738,764 4,859 767,919 December 31, 1998 788,390 5,822 823,321 December 31, 1999 720,670 5,546 753,944 December 31, 2000 754,962 8,438 805,590 ________________________________________________________________________________ /(1)/ Includes natural gas and natural gas equivalents determined by using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil, condensate or natural gas liquids. 9 Volumes and Prices; Production Costs The following table presents regional historical information about our net wellhead sales volume for natural gas and oil (including condensate and natural gas liquids), produced natural gas and oil sales prices, and production costs per equivalent. Year Ended December 31, 2000 1999 1998 ------ ------ ------ Net Wellhead Sales Volume Natural Gas (Bcf) Gulf Coast 14.1 15.5 10.6 West 29.0 29.3 30.9 Appalachia 17.8 20.7 22.7 Crude/Condensate/Ngl (Mbbl) Gulf Coast 669 579 215 West 289 341 482 Appalachia 32 43 39 Produced Natural Gas Sales Price ($/Mcf)/(1)/ Gulf Coast $ 3.79 $ 2.29 $ 2.15 West 2.86 1.96 1.90 Appalachia 3.24 2.53 2.53 Weighted Average 3.19 2.22 2.16 Crude/Condensate Sales Price ($/Bbl)/(1)/ $26.81 $17.22 $13.06 Production Costs ($/Mcfe)/(2)/ $ 0.70 $ 0.59 $ 0.57 ______________________________________________________________________________ /(1)/ Represents the average sales prices (net of hedge activity) for all production volumes (including royalty volumes) sold by Cabot Oil & Gas during the periods shown net of related costs (principally purchased gas royalty, transportation and storage). /(2)/ 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. 10 Acreage The following tables summarize our gross and net developed and undeveloped leasehold and mineral acreage at December 31, 2000. Acreage in which our interest is limited to royalty and overriding royalty interests is excluded. Leasehold Acreage Developed Undeveloped Total ------------------------------------------------------------------------------------------ Gross Net Gross Net Gross Net ------------------------------------------------------------------------------------------ State Alabama 0 0 312 312 312 312 Arkansas 0 0 240 6 240 6 Colorado 13,972 13,192 0 0 13,972 13,192 Kansas 29,067 27,765 0 0 29,067 27,765 Kentucky 2,266 901 0 0 2,266 901 Louisiana 44,587 35,446 114,154 41,972 158,741 77,418 Michigan 759 205 0 0 759 205 Montana 397 210 27,135 15,245 27,532 15,455 New York 2,956 1,117 7,641 4,382 10,597 5,499 North Dakota 0 0 870 96 870 96 Ohio 6,659 2,541 15,947 13,001 22,606 15,542 Oklahoma 165,037 115,150 13,646 8,596 178,683 123,746 Pennsylvania 127,972 77,918 48,077 42,051 176,049 119,969 Texas 61,192 42,301 72,831 22,711 134,023 65,012 Utah 1,740 530 20,034 16,862 21,774 17,392 Virginia 22,151 20,034 7,986 5,264 30,137 25,298 West Virginia 576,561 543,537 239,809 184,390 816,370 727,927 Wyoming 139,801 68,008 119,188 85,544 258,989 153,552 -------------------------------------------------------------------- Total 1,195,117 948,855 687,870 440,432 1,882,987 1,389,287 ==================================================================== Mineral Fee Acreage Developed Undeveloped Total ------------------------------------------------------------------------------------------ Gross Net Gross Net Gross Net ------------------------------------------------------------------------------------------ State Colorado 0 0 160 6 160 6 Kansas 160 128 0 0 160 128 Louisiana 628 276 0 0 628 276 Montana 0 0 589 75 589 75 New York 0 0 4,281 1,070 4,281 1,070 Oklahoma 16,580 13,979 400 76 16,980 14,055 Pennsylvania 86 86 2,367 1,296 2,453 1,382 Texas 27 27 652 326 679 353 Virginia 17,817 17,817 100 34 17,917 17,851 West Virginia 97,455 79,384 50,458 49,497 147,913 128,881 -------------------------------------------------------------------- Total 132,753 111,697 59,007 52,380 191,760 164,077 ==================================================================== Aggregate Total 1,327,870 1,060,552 746,877 492,812 2,074,747 1,553,364 ==================================================================== 11 Total Net Acreage by Region of Operation Developed Undeveloped Total ----------------------------------------------------------------------- Gulf Coast 50,673 60,757 111,430 West 266,339 131,070 397,409 Appalachia 743,540 300,985 1,044,525 ---------------------------------------------- Total 1,060,552 492,812 1,553,364 ============================================== Productive Well Summary The following table presents our ownership at December 31, 2000, in natural gas and oil wells in the Gulf Coast region (consisting of various fields located in Louisiana and Texas), in the Western region (consisting of various fields located in Oklahoma, Kansas, Colorado and Wyoming) and in the Appalachian region (consisting of various fields located in West Virginia, Pennsylvania, Virginia, and Ohio). We consider productive wells to be producing wells and wells capable of production in which we have a working interest or a reversionary interest as in the case of certain Section 29 tight sands and Devonian shale wells. Natural Gas Oil Total Gross Net Gross Net Gross Net --------------------------------------------------------------------- Gulf Coast 282 213.4 102 79.2 384 292.6 West 1,093 636.4 69 39.0 1,162 675.4 Appalachia 2,223 2,069.6 20 9.6 2,243 2,079.2 -------------------------------------------- Total 3,598 2,919.4 191 127.8 3,789 3,047.2 ============================================ Drilling Activity We drilled, participated in the drilling of, or acquired wells presented by region in the table below for the periods indicated. Year Ended December 31, 2000 1999 1998 ----------------------------------------------------------------------------- Gross Net Gross Net Gross Net ----------------------------------------------------------------------------- Gulf Coast Development Wells Successful 14 6.3 10 6.2 9 4.0 Dry 3 1.7 3 3.0 0 0.0 Extension Wells Successful 0 0.0 0 0.0 0 0.0 Dry 0 0.0 0 0.0 0 0.0 Exploratory Wells Successful 4 2.2 2 0.6 7 4.6 Dry 2 1.0 1 0.5 1 1.0 ---------------------------------------------- Total 23 11.2 16 10.3 17 9.6 ============================================== Wells Acquired/(1)/ 1 0.6 2 0.6 219 204.2 Wells in Progress at End of Period 2 1.1 1 0.3 5 4.2 12 Year Ended December 31, 2000 1999 1998 -------------------------------------------------------------------- Gross Net Gross Net Gross Net -------------------------------------------------------------------- West Development Wells Successful 33 22.7 19 9.0 64 36.2 Dry 3 1.0 1 1.0 4 1.9 Extension Wells Successful 7 3.9 1 0.3 5 2.2 Dry 0 0.0 0 0.0 1 0.9 Exploratory Wells Successful 1 0.3 0 0.0 2 0.7 Dry 1 0.5 2 1.3 3 2.0 ------------------------------------------- Total 45 28.4 23 11.6 79 43.9 =========================================== Wells Acquired/(1)/ 1 0.4 27 10.7 13 3.9 Wells in Progress at End of Period 4 2.7 5 2.3 4 1.8 Year Ended December 31, 2000 1999 1998 --------------------------------------------------------------------- Gross Net Gross Net Gross Net --------------------------------------------------------------------- Appalachia Development Wells Successful 47 41.5 26 19.0 77 69.4 Dry 5 4.2 1 0.5 6 4.8 Extension Wells Successful 0 0.0 0 0.0 0 0.0 Dry 0 0.0 0 0.0 0 0.0 Exploratory Wells Successful 5 3.8 3 2.0 18 11.0 Dry 4 2.5 4 2.0 8 5.0 ---- ---- -- ---- --- ---- Total 61 52.0 34 23.5 109 90.2 ==== ==== == ==== === ==== Wells Acquired/(1)/ 0 0.0 0 0.0 5 4.2 Wells in Progress at End of Period 3 3.0 1 0.3 1 0.5 --------------------------------------------------------------------- /(1)/ Includes the acquisition of net interest in certain wells in which we already held an ownership interest. Does not include certain interests in Section 29 tight sands and Devonian shale wells purchased and then resold during 1999. Competition Competition in our primary producing areas is intense. Price, contract terms and quality of service, including pipeline connection times, distribution efficiencies and reliable delivery records, affect competition. We believe that our extensive acreage position and existing natural gas gathering and pipeline systems and storage fields give us a competitive advantage over other producers in the Appalachian region who do not have similar systems or facilities in place. We believe that our competitive position in the Appalachian region is enhanced by the lack of significant competition from major oil and gas companies. We also actively compete against other companies with substantially larger financial and other resources, particularly in the Western and Gulf Coast regions. 13 OTHER BUSINESS MATTERS Major Customer We had no sales to any customer that exceeded 10% of our total gross revenues in 2000 or 1999. Seasonality Demand for natural gas has historically been seasonal, with peak demand and typically higher prices occurring during the colder winter months. Regulation of Oil and Natural Gas Exploration and Production Exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits to drill wells, maintaining bonding requirements 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 on which wells are drilled, and the plugging and abandoning of wells. Our 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, the density of wells which may be drilled in a given field, and the unitization or pooling of oil and natural gas properties. Some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibiting the venting or flaring of natural gas, and imposing certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of oil and natural gas we can produce from our wells, and to limit the number of wells or the locations where we can drill. Because these statutes, rules and regulations undergo constant review and often are amended, expanded and reinterpreted, we are unable to predict the future cost or impact of regulatory compliance. The regulatory burden on the oil and gas industry increases its cost of doing business and, consequently, affects its profitability. We do not believe, however, we are affected materially differently by these regulations than others in the industry. Natural Gas Marketing, Gathering and Transportation Federal legislation and regulatory controls have historically affected the price of the natural gas produced and the manner in which such production is transported and marketed. Under the Natural Gas Act of 1938, the FERC regulates the interstate sale and transportation of natural gas for resale. The FERC's jurisdiction over interstate natural gas sales was substantially modified by the Natural Gas Policy Act of 1978 (NGPA), under which the FERC continued to regulate the maximum selling prices of certain categories of gas sold in "first sales" in interstate and intrastate commerce. Effective January 1, 1993, however, the Natural Gas Wellhead Decontrol Act (Decontrol Act) deregulated natural gas prices for all "first sales" of natural gas, including all sales of our own production. As a result, all of our produced natural gas may now be sold at market prices, subject to the terms of any private contracts that may be in effect. The FERC's jurisdiction over natural gas transportation and the sale for resale of natural gas in interstate commerce was not affected by the Decontrol Act. Natural gas sales are affected by intrastate and interstate gas transportation regulation. Beginning with Order No. 436 in 1985 and continuing through Order No. 636 in 1992, the FERC adopted regulatory changes that have significantly altered the transportation and marketing of natural gas. These changes were intended by the FERC to foster competition by, among other things, transforming the role of interstate pipeline companies from wholesaler marketers of gas to the primary role of gas transporters. Order No. 636 required that interstate pipelines generally cease making sales of natural gas. At the same time, FERC retained its statutory jurisdiction over the sale for resale of natural gas in interstate commerce, but issued to all entities (except interstate pipelines) a blanket certificate to make sales for resale of natural gas in interstate commerce at market based prices. As a result, pipelines divested their gas sales functions to marketing affiliates, which operate separately from the transporter and in direct competition with all other merchants. As a result of the various omnibus rulemaking proceedings in the late 1980s and early 1990s, and the individual pipeline restructuring proceedings of the early to mid-1990s, the interstate pipelines are now required to provide open and nondiscriminatory transportation and transportation-related services to all producers, gas marketing companies, local distribution companies, industrial end users and other customers seeking service. The FERC expanded the impact of open access regulations to intrastate commerce through its 14 implementation of the NGPA provisions allowing intrastate pipelines to provide service in intrastate commerce on behalf of interstate pipelines. More recently, the FERC has pursued other policy initiatives that have affected natural gas marketing. Most notable are (1) the large-scale divestiture of interstate pipeline-owned gas gathering facilities to affiliated or non-affiliated companies, which is a result of the FERC's requirement in Order No. 636 that interstate pipelines unbundle gathering services from transportation services, (2) further development of rules governing the relationship of the pipelines with their marketing affiliates, (3) the publication of standards relating to the use of electronic bulletin boards and electronic data exchange by the pipelines to make available transportation information on a timely basis and to enable transactions to occur on a purely electronic basis, (4) further refinement of transactions permitted in the secondary market for released pipeline capacity and its relationship to open access service in the primary market, and (5) development of policy and promulgation of orders pertaining to its authorization of market-based rates (rather than traditional cost-of-service based rates) for transportation or transportation-related services upon a showing of lack of market control in the relevant service market. It remains to be seen what effect the FERC's other activities will have on access to markets, the fostering of competition and the cost of doing business. As a result of these changes, sellers and buyers of gas have gained direct access to the particular pipeline services they need and are better able to conduct business with a larger number of counterparties. We believe these changes generally have improved our access to markets while, at the same time, substantially increasing competition in the natural gas marketplace. We can not predict what new or different regulations the FERC and other regulatory agencies may adopt, or what effect subsequent regulations may have on our activities. Similarly, it is impossible to predict what proposals, if any, that affect the oil and natural gas industry might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on us. Similarly, and despite the trend toward federal deregulation of the natural gas industry, whether or to what extent that trend will continue, or what the ultimate effect will be on our sales of gas, can not be predicted. Our pipeline systems and storage fields in West Virginia are regulated for safety compliance by the U.S. Department of Transportation and the West Virginia Public Service Commission. Federal Regulation of Petroleum Our sales of oil and natural gas liquids are not regulated and are at market prices. The price received from the sale of these products is affected by the cost of transporting the products to market. Much of that transportation is through interstate common carrier pipelines. Effective January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may tend to increase the cost of transporting oil and natural gas liquids by interstate pipeline, although the annual adjustments may result in decreased rates in a given year. These regulations have generally been approved on judicial review. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. The first such review has been completed and on December 14, 2000, the FERC reaffirmed the current index. We are not able to predict with certainty the effect upon us of these relatively new federal regulations or of the periodic review by the FERC of the index. Environmental Regulations General. Our 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 our various facilities. These permits can be revoked, modified or renewed by issuing authorities. Governmental authorities enforce compliance with their regulations through fines, injunctions or both. Government regulations can increase the cost of planning, designing, installing and operating oil and gas facilities. Although we believe that compliance with environmental regulations will not have a material adverse effect on us, risks of substantial costs and liabilities related to environmental compliance issues are part of oil and gas production operations. No assurance can be given that significant costs and liabilities will not be incurred. 15 Also, it is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from oil and gas production could result in substantial costs and liabilities to us. Solid and Hazardous Waste. We currently own or lease, and have in the past owned or leased, numerous properties that were used for the production of oil and gas for many years. Although operating and disposal practices that were standard in the industry at the time may have been utilized, it is possible that hydrocarbons or other solid wastes may have been disposed of or released on or under the properties currently owned or leased by us. State and federal laws applicable to oil and gas wastes and properties have become more strict over time. Under these increasingly stringent requirements, we could be required to remove or remediate previously disposed wastes (including wastes disposed or released by prior owners and operators) or clean up property contamination (including groundwater contamination by prior owners or operators) or to perform plugging operations to prevent future contamination. We generate some hazardous wastes that are already subject to the Federal Resource Conservation and Recovery Act (RCRA) and comparable state statutes. The Environmental Protection Agency (EPA) has limited the disposal options for certain hazardous wastes. It is possible that certain wastes currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes under RCRA or other applicable statutes. We could, therefore, be subject to more rigorous and costly disposal requirements in the future than we encounter today. Superfund. The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), also known as the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain persons with respect to the release of hazardous substances into the environment. These persons include the owner and operator of a site and any party that disposed of or arranged for the disposal of hazardous substances found at a site. CERCLA also authorizes the EPA, and in some cases, private parties, to undertake actions to clean up such hazardous substances, or to recover the costs of such actions from the responsible parties. In the course of business, we have generated and will continue to generate wastes that may fall within CERCLA's definition of hazardous substances. We may also be an owner or operator of sites on which hazardous substances have been released. As a result, we may be responsible under CERCLA for all or part of the costs to clean up sites where such wastes have been disposed. See Item 3 Legal Proceedings for a discussion of the Casmalia Superfund Site. Oil Pollution Act. The federal Oil Pollution Act of 1990 (OPA) and resulting regulations impose a variety of obligations on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. The term "waters of the United States" has been broadly defined to include inland water bodies, including wetlands and intermittent streams. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. Clean Water Act. The Federal Water Pollution Control Act (FWPCA or Clean Water Act) and resulting regulations, which are implemented through a system of permits, also govern the discharge of certain contaminants into waters of the United States. Sanctions for failure to comply strictly with the Clean Water Act are generally resolved by payment of fines and correction of any identified deficiencies. However, regulatory agencies could require us to cease construction or operation of certain facilities that are the source of water discharges. We believe that we comply with the Clean Water Act and related federal and state regulations in all material respects. Clean Air Act. Our operations are subject to local, state and federal laws and regulations to control emissions from sources of air pollution. Payment of fines and correction of any identified deficiencies generally resolve penalties for failure to comply strictly with air regulations or permits. Regulatory agencies could also require us to cease construction or operation of certain facilities that are air emission sources. We believe that we substantially comply with the emission standards under local, state, and federal laws and regulations. Employees As of December 31, 2000, Cabot Oil & Gas had 323 active employees. We recognize that our success is significantly influenced by the relationship we maintain with our employees. Overall, we believe that our relations with our employees are satisfactory. The Company and its employees are not represented by a collective bargaining agreement. 16 In May 2000, we announced the closure of our regional office in Pittsburgh, Pennsylvania. Approximately 15 jobs were eliminated as a result of this action, while the remaining positions were either transferred to existing offices in Charleston, West Virginia and Houston, Texas or remained in smaller facilities in Pittsburgh. In January 1999, we instituted a reorganization plan that resulted in a 6% reduction in the number of active employees. In September 1999, we completed the divestiture of certain properties in the Appalachian region that effectively transferred 19 active employees to the acquiring company. Other Our profitability depends on certain factors that are beyond our control, such as natural gas and crude oil prices. Please see Item 7. We face a variety of hazards and risks that could cause substantial financial losses. Our business involves a variety of operating risks, including blowouts, cratering, explosions and fires, mechanical problems, uncontrolled flows of oil, natural gas or well fluids, formations with abnormal pressures, pollution and other environmental risks, and natural disasters. We conduct operations in shallow offshore areas, which are subject to additional hazards of marine operations, such as capsizing, collision and damage from severe weather. Our operation of natural gas gathering and pipeline systems also involves various risks, including the risk of explosions and environmental hazards caused by pipeline leaks and ruptures. The location of pipelines near populated areas, including residential areas, commercial business centers and industrial sites, could increase these risks. At December 31, 2000, we owned or operated approximately 2,650 miles of natural gas gathering and transmission pipeline systems throughout the United States. As part of our normal maintenance program, we have identified certain segments of our pipelines that we believe may require repair, replacement or additional maintenance. Any of these events could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations. The sale of our oil and gas production depends on a number of factors beyond our control. The factors include the availability and capacity of transportation and processing facilities. Our failure to access these facilities and obtain these services on acceptable terms could materially harm our business. ITEM 2. PROPERTIES See Item 1. Business. ITEM 3. LEGAL PROCEEDINGS We are a party to various legal proceedings arising in the normal course of our business, none of which, in management's opinion, should result in judgments which would have a material adverse effect on us. Environmental Liability The EPA notified us in February 2000 that we might have potential liability for waste material disposed of at the Casmalia Superfund Site ("Site"), located on a 252-acre parcel in Santa Barbara County, California. Over 10,000 separate parties disposed of waste at the Site while it was operational from 1973 to 1989. The EPA stated that federal, state and local governmental agencies along with the numerous private entities that used the Site for waste disposal will be expected to pay the clean-up costs which could total as much as several hundred million dollars. The EPA is also pursuing the owners/operators of the Site to pay for remediation. Documents received with the notification from the EPA indicate that we used the Site principally to dispose of salt water from two wells over a period from 1976 to 1979. There is no allegation that we violated any laws in the disposal of material at the Site. The EPA's actions stemmed from the fact that the owners/operators of the Site do not have the financial means to implement a closure plan for the Site. A group of potentially responsible parties, including the Company, have had extensive settlement discussions with the EPA. However, the parties have yet to 17 reach an agreement. We have established a reserve that we believe to be adequate to cover this potential environmental liability based on our estimate of the probable outcome of this matter. While the potential impact of this claim may materially affect quarterly or annual financial results, management does not believe it would materially impact our financial position or cash flows. We will continue to monitor the facts and our assessment of our liability related to this claim. Wyoming Royalty Litigation In June 2000, two overriding royalty owners sued us in Wyoming State court. The plaintiffs have requested class certification under the Wyoming Rules of Civil Procedure and allege that we have deducted impermissible costs of production from royalty payments to the plaintiffs and other similarly situated persons. Additionally, the suit claims that we have failed to properly inform the plaintiffs and other similarly situated persons of the deductions taken from royalties. While we believe that we have substantial defenses to this claim and intend to vigorously assert such defenses, the investigation into this claim has only just begun and, accordingly, we can not presently determine the likelihood or range of any potential loss. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to a vote of security holders during the period from October 1, 2000 to December 31, 2000. EXECUTIVE OFFICERS OF THE REGISTRANT The following table shows certain information about our executive officers as of February 22, 2001, as such term is defined in Rule 3b-7 of the Securities Exchange Act of 1934, and certain of our other officers. Name Age Position Officer Since ---------------------------------------------------------------------------------------------- Ray R. Seegmiller 65 Chairman of the Board, Chief Executive Officer 1995 and President Michael B. Walen 52 Senior Vice President 1998 J. Scott Arnold 47 Vice President, Land and Associate General Counsel 1998 Robert G. Drake 53 Vice President, Management Information Systems 1998 Abraham D. Garza 54 Vice President, Human Resources 1998 Jeffrey W. Hutton 45 Vice President, Marketing 1995 Lisa A. Machesney 45 Vice President, Managing Counsel and Corporate Secretary 1995 Scott C. Schroeder 38 Vice President, Chief Financial Officer and 1997 Treasurer Henry C. Smyth 54 Vice President and Controller 1998 All officers are elected annually by our Board of Directors. All of the executive officers have been employed by Cabot Oil & Gas Corporation for at least the last five years. 18 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The Common Stock is listed and principally traded on the New York Stock Exchange under the ticker symbol "COG." The following table presents the high and low closing sales prices per share of the Common Stock during certain periods, as reported in the consolidated transaction reporting system. Cash dividends paid per share of the Common Stock are also shown. Cash High Low Dividends ------------------------------------------------ 2000 First Quarter $18.06 $14.19 $0.04 Second Quarter 24.94 16.75 0.04 Third Quarter 21.25 17.38 0.04 Fourth Quarter 31.75 19.00 0.04 1999 First Quarter $15.81 $10.94 $0.04 Second Quarter 19.94 14.00 0.04 Third Quarter 19.50 16.44 0.04 Fourth Quarter 18.00 13.38 0.04 As of January 31, 2001, there were 942 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 summarizes selected consolidated financial data for Cabot Oil & Gas 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. Year Ended December 31, (In thousands, except per share amounts) 2000 1999 1998 1997 1996 - -------------------------------------------------------------------------------------------- Income Statement Data Operating Revenues $368,651 $294,037 $251,340 $269,771 $248,930 Income from Operations 64,817 39,498 27,403 63,852 48,787 Net Income Available to Common Stockholders 29,221 5,117 1,902 23,231 15,258 Basic Earnings per Share Available to Common Stockholders/(1)/ $ 1.07 $ 0.21 $ 0.08 $ 1.00 $ 0.67 Dividends per Common Share $ 0.16 $ 0.16 $ 0.16 $ 0.16 $ 0.16 Balance Sheet Data Properties and Equipment, Net $623,174 $590,301 $629,908 $469,399 $480,511 Total Assets 735,634 659,480 704,160 541,805 561,341 Long-Term Debt 253,000 277,000 327,000 183,000 248,000 Stockholders' Equity 242,505 186,496 182,668 184,062 160,704 - -------------------------------------------------------------------------------- /(1)/ See Earnings per Common Share under Note 15 of the Notes to the Consolidated Financial Statements. 19 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion is intended to assist you in understanding our results of operations and our present financial condition. Our Consolidated Financial Statements and the accompanying notes included elsewhere in this Form 10-K contain additional information that should be referred to when reviewing this material. Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed. Please read Forward-Looking Information on page 25. We operate in one segment, natural gas and oil exploration and development. OVERVIEW Our financial results depend upon many factors, particularly the price of natural gas and our ability to market our production on economically attractive terms. Price volatility in the natural gas market has remained prevalent in the last few years. From the third quarter of 1998 through the first quarter of 1999, we experienced a decline in energy commodity prices, resulting in lower revenues and net income during this period. However, in the summer of 1999 and continuing into early 2000, prices improved. For the months of April through October 2000, we had certain natural gas hedges in place that prevented us from realizing the full impact of this price environment. (See the Commodity Price Swaps and Options discussion on page 31.) Despite this limitation, our realized natural gas price for each month in the year 2000 was higher than the same month of any previous year. In the final months of 2000, the NYMEX futures market reported unprecedented natural gas contract prices. We benefited from this market with our realized natural gas price reaching $5.66 per Mcf in December. We reported earnings of $1.07 per share, or $29.2 million, for 2000. This is up from the $0.21 per share, or $5.1 million, reported in 1999. The improvement is a result of the stronger commodity price environment during the year 2000, with our realized natural gas price up 44% to $3.19 per Mcf and our crude oil price up 56% to $26.81 per Bbl. A discussion of our results from recurring operations can be found in the Results of Operations section, beginning on page 26. Before taking into account selected non-recurring items, net income for 2000 was $30.2 million, or $1.10 per share, and $0.4 million, or $0.02 per share for 1999. We drilled 129 gross wells with a success rate of 86% in 2000 compared to 73 gross wells and an 84% success rate in 1999. Total capital expenditures were $122.6 million for 2000 compared to $88.1 million in 1999. Most of the $34.5 million increase was spent on drilling, with the largest activity increase coming in the Gulf Coast region, where we continued to develop the Etouffee, Bon Ton, Augen and Krescent prospects in south Louisiana. We increased our spending for seismic data, both 2-D and 3-D, in order to evaluate our drilling opportunities for 2000 and beyond. Additionally, a portion of our capital budget in 2000 was spent to construct production facilities for use with several wells in south Louisiana. Total equivalent production for 2000 was 66.9 Bcfe, a decrease of 6% over 1999. Production delays on non-operated properties in the Gulf Coast region combined with the sale of non-strategic properties in Appalachia in the fourth quarter of 1999 accounted for much of this decline. By the fourth quarter, this Gulf Coast production was on-line and we exited the year producing approximately 197 Mmcfe per day. Due to the increased demand for drilling rigs and crews, some short drilling delays are anticipated in early 2001. However, whenever possible, we have contracted rigs and crews to begin working on our 2001 drilling program. During 2000, we improved our debt-to-equity ratio from 61.1% at the end of 1999 to 52.6% at the close of 2000. This improvement was a result of several significant accomplishments. We sold 3.4 million shares of common stock in May 2000 for net proceeds of $71.5 million, of which $51.6 million was used to repurchase all of our preferred stock. The remaining proceeds, along with another $14.8 million from employee stock option exercises, were used to reduce debt and pay dividends. From year end 1999 to year end 2000, we reduced debt by $24 million. 20 We remain focused on our strategies to grow through the drill bit, concentrating on the highest expected return opportunities, and from synergistic acquisitions. We believe these strategies are appropriate in the current industry environment, enabling us to add shareholder value over the long-term. The preceding paragraphs, discussing our strategic pursuits and goals, contain forward-looking information. Please read Forward-Looking Information on page 25. FINANCIAL CONDITION Capital Resources and Liquidity Our capital resources consist primarily of cash flows from our oil and gas properties and asset-based borrowing supported by oil and gas reserves. Our level of earnings and cash flows depends on many factors, including the price of oil and natural gas and our ability to control and reduce costs. Demand for natural gas has historically been subject to seasonal influences characterized by peak demand and higher prices in the winter heating season. However, in the summer of 2000, our realized gas prices began to climb and by the fourth quarter of 2000, we were realizing the highest prices in the Company's history. The primary sources of cash for us during 2000 were funds generated from operations and proceeds from the sale of stock. Funds were used primarily for exploration and development expenditures, the repurchase of the preferred stock, dividend payments and the repayment of borrowings under the credit facility. We had net cash inflows of $5.9 million during 2000. The net cash inflow from operating activities of $119.0 million substantially offsets the $119.2 million of cash used for capital and exploration expenditures. The cash proceeds from sale of common stock of $85.1 million effectively funded the repurchase of the preferred stock, debt reduction and dividend payments. (In millions) 2000 1999 1998 ----------------------------------------------------------------------- Cash Flows Provided by Operating Activities $119.0 $92.5 $87.2 ------------------------- Cash flows provided by operating activities in 2000 were $26.5 million higher than in 1999. This improvement was primarily a result of increased revenues from higher realized commodity prices. Cash flows provided by operating activities in 1999 were $5.3 million higher than in 1998. This improvement was a result of increased revenues from higher realized commodity prices and the proceeds from the buyout of the long- term gas sales contract. Partially offsetting this benefit was the less favorable change in the balance sheet as we reduced the balance in accounts payable between year ends. (In millions) 2000 1999 1998 ----------------------------------------------------------------------- Cash Flows Used by Investing Activities $(116.1) $(37.4) $(222.1) ----------------------------- Cash flows used by investing activities in 2000 were attributable to capital and exploration expenditures of $119.2 million, offset by the receipt of $3.1 million in proceeds received from the sale of non-strategic oil and gas properties. Cash flows used by investing activities in 1999 were attributable to capital and exploration expenditures of $93.7 million, offset by the receipt of $56.3 million in proceeds received from the sale of non-strategic oil and gas properties. Cash flows used by investing activities in 1998 were substantially attributable to capital and exploration expenditures of $223.2 million, offset by the receipt of $1.1 million in proceeds from the sale of certain oil and gas properties. These 1998 expenditures included: . $70.1 million used to purchase south Louisiana properties from Oryx in December. . $6.6 million spent as part of the joint exploration agreement with Union Pacific Resources. . $12 million used to acquire 21.8 Bcfe of proved reserves in the Western region. 21 (In millions) 2000 1999 1998 -------------------------------------------------------------------------- Cash Flows Provided (Used) by Financing Activities $3.0 $(55.6) $135.3 ---------------------- Cash flows provided by financing activities in 2000 included $85.1 million in proceeds received from the sale of common stock, both in a block trade and through the exercise of employee stock options. Of the proceeds, $51.6 million was used to repurchase all of the outstanding shares of preferred stock. Additional cash used in financing activities included $24 million used to reduce the year-end debt balance to $269 million from $293 million in 1999 and cash used to pay dividends to stockholders. Cash flows used by financing activities in 1999 included $50 million used to reduce the year-end debt balance to $293 million from $343 million in 1998 and cash used to pay cash dividends to stockholders. Cash flows provided by financing activities in 1998 were increases in borrowings on the revolving credit facility used to fund investing activities such as the 1998 drilling program and the $83.6 million in property acquisitions. Financing activities in 1998 also included the payment of dividends and the purchase of shares in the open market under our share repurchase program. The purchased shares are held as treasury shares. We have a revolving credit facility with a group of banks, the revolving term of which runs to December 2003. The available credit line under this facility, currently $250 million, is subject to adjustment on the basis of the present value of estimated future net cash flows from proved oil and gas reserves (as determined by the banks' petroleum engineer) and other assets. Accordingly, oil and gas prices are an important part of this computation. While the current price environment is quite strong, management can not predict how future price levels may change the banks' long-term price outlook. To reduce the impact of any redetermination, we strive to manage our debt at a level below the available credit line in order to maintain excess borrowing capacity. At year end, this excess capacity totaled $113 million, or 45% of the total available credit line. Management believes it has the ability to finance, if necessary, our capital requirements, including acquisitions. Oil and gas prices also affect the calculation of the financial ratios for debt covenant compliance. Please read Note 5 of the Notes to the Consolidated Financial Statements for a more detailed discussion of our revolving credit facility. In the event that the available credit line is adjusted below the outstanding level of borrowings, we have a period of 180 days to reduce our outstanding debt to the adjusted credit line. The revolving credit agreement also includes a requirement to pay down half of the debt in excess of the adjusted credit line within the first 90 days of any adjustment. Our interest expense for 2001 is projected to be $17.3 million. In May 2001, a $16.0 million principal payment is due on our 10.18% Notes. The amount is reflected as Current Portion of Long-Term Debt on our balance sheet. The payment is expected to be made with cash from operations and, if necessary, from increased borrowings under our revolving credit facility. Capitalization Our capitalization information is as follows: As of December 31, (In millions) 2000 1999 1998 -------------------------------------------------------------------------------- Long-Term Debt $253.0 $277.0 $327.0 Current Portion of Long-Term Debt 16.0 16.0 16.0 ------------------------------------ Total Debt $269.0 $293.0 $343.0 ==================================== Stockholders' Equity Common Stock (net of Treasury Stock) $242.5 $129.8 $126.0 Preferred Stock 0.0 56.7 56.7 ------------------------------------ Total Equity 242.5 186.5 182.7 ------------------------------------ Total Capitalization $511.5 $479.5 $525.7 ==================================== Debt to Capitalization 52.6% 61.1% 65.2% ------------------------------------ 22 During 2000, dividends were paid on our common stock totaling $4.4 million and on our 6% convertible redeemable preferred stock totaling $2.2 million. We have paid quarterly common stock dividends of $0.04 per share since becoming publicly traded in 1990. The amount of future dividends is determined by our Board of Directors and is dependent upon a number of factors, including future earnings, financial condition and capital requirements. In May 2000, we bought back all of the shares of preferred stock from the holder for $51.6 million. Since this stock had been recorded at a stated value of $56.7 million on our balance sheet, we realized a negative dividend to preferred stockholders of $5.1 million. We received net proceeds of $71.5 million from the sale of 3.4 million shares of common stock in a public offering primarily to fund this transaction. After repurchasing the preferred stock, the excess proceeds were used to reduce debt. Capital and Exploration Expenditures On an annual basis, we generally fund most of our capital and exploration activities, excluding major oil and gas property acquisitions, with cash generated from operations. We budget these capital expenditures based on our projected cash flows for the year. The following table presents major components of our capital and exploration expenditures for the three years ended December 31, 2000. (In millions) 2000 1999 1998 ----------------------------------------------------------- Capital Expenditures Drilling and Facilities $ 80.0 $ 43.9 $ 99.0 Leasehold Acquisitions 10.9 7.2 15.6 Pipeline and Gathering 3.2 3.8 5.3 Other 2.6 3.3 2.8 ------------------------- 96.7 58.2 122.7 ------------------------- Proved Property Acquisitions 6.0 18.4 83.6/(1)/ Exploration Expenses 19.9 11.5 19.6 ------------------------- Total $122.6 $ 88.1 $225.9 ========================= ----------------------------------------------------------- /(1)/ Includes $70.1 million in oil and gas properties acquired from Oryx Energy Company in December 1998. Total capital and exploration expenditures for 2000 increased $34.5 million compared to 1999, primarily as a result of the increased drilling program in 2000. The 2000 drilling program included an over 100% increase in net wells drilled and a $3.5 million increase in geological and geophysical expenses, including costs of obtaining seismic data. During the last half of 1999, we acquired $17.4 million of oil and gas properties in the Moxa Arch in the Rocky Mountains area, including 27 gross wells, approximately 16 Bcfe of proved reserves and approximately 43,000 net undeveloped acres that complement our existing Moxa Arch development. We plan to drill 240 gross wells in 2001 compared with 129 gross wells drilled in 2000. This 2001 drilling program includes $167.1 million in total capital and exploration expenditures, up from $122.6 million in 2000, and is our largest capital program to date. Expected spending in 2001 includes $93.0 million for drilling and facilities, and $48.6 million in exploration expenses. In addition to the drilling and exploration program, other 2001 capital expenditures are planned primarily for lease acquisitions and for gathering and pipeline infrastructure maintenance and construction. We will continue to assess the natural gas price environment and may increase or decrease the capital and exploration expenditures accordingly. OTHER ISSUES AND CONTINGENCIES Corporate Income Tax. We generate tax credits for the production of certain qualified fuels, including natural gas produced from tight sands formations and Devonian Shale. The credit for natural gas from a tight sand 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 estimated to be $1.06 per 23 Mmbtu in 2000. In 1995 and 1996, we completed three transactions to monetize the value of these tax credits, resulting in revenues of $2.2 million in 2000 and approximately $4.1 million over the remaining two years. See Note 13 of the Notes to the Consolidated Financial Statements for further discussion. We have benefited in the past and may benefit in the future from the alternative minimum tax (AMT) relief granted under the Comprehensive National Energy Policy Act of 1992 (the Act). The Act repealed provisions of the AMT requiring a taxpayer's alternative minimum taxable income to be increased on account of certain intangible drilling costs (IDC) and percentage depletion deductions. The repeal of these provisions generally applies to taxable years beginning after 1992. The repeal of the excess IDC preference can not reduce a taxpayer's alternative minimum taxable income by more than 40% of the amount of such income determined without regard to the repeal of such preference. Regulations. Our 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. Our ability to incur debt, to pay dividends, and to make certain types of investments is subject to certain restrictive covenants in the Company's various debt instruments. Among other requirements, our Revolving Credit Agreement and 7.19% Notes specify a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0. At December 31, 2000, the calculated ratio for 2000 was 6.3 to 1.0. In the unforeseen event that we fail to comply with these covenants, the Company may apply for a temporary waiver with the bank, which, if granted, would allow us a period of time to remedy the situation. See further discussion in Capital Resources and Liquidity and Note 5 of the Notes to the Consolidated Financial Statements for further discussion. CONCLUSION Our financial results depend upon many factors, particularly the price of natural gas and oil and our ability to market gas on economically attractive terms. The average produced natural gas sales price received in 2000 was 44% higher than in 1999. However, 1999 prices were up only 3% over 1998, after declining 15% from 1997 to 1998. The volatility of natural gas prices in recent years remains prevalent in 2001 with wide price swings in day-to-day trading on the NYMEX futures market. Given this continued price volatility, we can not predict with certainty what pricing levels will be in the future. Because future cash flows are subject to these variables, there is no assurance that our operations will provide cash sufficient to fully fund our planned capital expenditures. While our 2001 plan now includes $167.1 million in capital and exploration spending, we will periodically assess industry conditions and adjust our 2001 spending plan to ensure the adequate funding of our capital requirements, including, if necessary, reductions in capital and exploration expenditures or common stock dividends. We believe our capital resources, supplemented with external financing if necessary, are adequate to meet our capital requirements. The preceding paragraphs contain forward-looking information. See Forward- Looking Information in the following paragraph. * * * 24 Forward-Looking Information The statements regarding future financial and operating performance and results, and market prices and future hedging activities, and other statements that are not historical facts contained in this report are forward-looking statements. The words "expect," "project," "estimate," "believe," "anticipate," "intend," "budget," "plan," "forecast," "predict" and similar expressions are also intended to identify forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including regional basis differentials) of natural gas and oil, results for future drilling and marketing activity, future production and costs and other factors detailed herein and in our other Securities and Exchange Commission filings. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. 25 RESULTS OF OPERATIONS For the purpose of reviewing our results of operations, "Net Income" is defined as net income available to common stockholders. Selected Financial and Operating Data (In millions except where specified) 2000 1999 1998 --------------------------------------------------------------------- Operating Revenues $368.7 $294.0 $251.3 Operating Expenses 303.8 258.5 224.4 Operating Income 64.8 39.5 27.4 Interest Expense 22.9 25.8 18.6 Net Income 29.2 5.1 1.9 Earnings Per Share - Basic $ 1.07 $ 0.21 $ 0.08 Earnings Per Share - Diluted 1.06 0.21 0.08 Natural Gas Production (Bcf) Gulf Coast 14.1 15.5 10.6 West 29.0 29.3 30.9 Appalachia 17.8 20.7 22.7 ------------------------- Total Company 60.9 65.5 64.2 Produced Natural Gas Sales Price ($/Mcf) Gulf Coast $ 3.79 $ 2.29 $ 2.15 West 2.86 1.96 1.90 Appalachia 3.24 2.53 2.53 Total Company 3.19 2.22 2.16 Crude/Condensate Volume (Mbbl) 953 929 650 Price ($/Bbl) $26.81 $17.22 $13.06 The table below presents the after-tax effects of certain selected items on our results of operations for the three years ended December 31, 2000. (In millions) 2000 1999 1998 ---------------------------------------------------------------- Net Income Before Selected Items $30.2 $ 0.4 $ 1.9 Buyout of Gas Sales Contract 7.3 Impairment of Long-Lived Assets (5.6) (4.3) Gain on Sale of Assets 2.4 Section 29 Tax Credit Provision (0.7) Negative Preferred Stock Dividend 5.1 Contract Settlements 1.4 Bad Debt Expense (1.3) Severance Costs (0.6) ----------------------- Net Income $29.2 $ 5.1 $ 1.9 ======================= These selected items impacted our financial results. Because they are not a part of our normal business, we have isolated their effects in the table above. These selected items for 2000 were as follows: . A $9.1 million impairment ($5.6 million after tax) was recorded on the Beaurline field in south Texas as a result of a casing collapse in two of the field's wells. . As a result of repurchasing all of the preferred stock at less than the book value, we recorded a $5.1 million negative stock dividend in May 2000. . Miscellaneous net revenue, primarily from the settlement of a natural gas sales contract, was recorded in the first quarter ($1.4 million after tax). 26 . As a result of bankruptcy proceedings of two of our customers, we recorded $2.1 million in bad debt expense in the fourth quarter ($1.3 million after tax). . We announced the closure of the regional office in Pittsburgh in May 2000 and recorded costs of $1.0 million ($0.6 million after tax). These costs were recorded in the income statement categories that will receive the future savings benefit ($0.6 million in operations, $0.1 million in exploration and $0.3 million in administration). These selected items for 1999 were as follows: . We had a 15-year cogeneration contract under which we sold approximately 20% of our Western region natural gas per year. The contract was due to expire in 2008, but during 1999 we reached an agreement with the counterparty under which the counterparty bought out the remainder of the contract for $12 million. This transaction, completed in December 1999, accelerated the realization of any future price premium that may have been associated with the contract and added $12 million of pre-tax other revenue ($7.3 million after tax). We simultaneously sold forward a similar quantity of Western region gas production through April 2001 at similar prices to those in the old contract. The natural gas sales price stated in this new contract was significantly below year-end market prices in the region. If market prices remain above the fixed contract price beyond April 2001, we could expect to realize notably higher natural gas sales prices on this production. . In the fourth quarter of 1999, we recorded impairments totaling $7 million on two of our producing fields in the Gulf Coast region ($4.3 million after tax). The Chimney Bayou field was impaired by $6.6 million due to a significant reserve revision on the Broussard-Middleton 1R well in connection with a decline in its natural gas production accompanied by a marked increase in water production. The Broussard-Middleton 1R was the only producing well in this field. The Lawson field was impaired by $0.4 million due to an unsuccessful workover on one of its wells. . We recorded a $4 million gain on the sale of certain non-strategic oil and gas assets, most notably the Clarksburg properties in the Appalachian region sold to EnerVest effective October 1999 ($2.4 million after tax). . We recorded a $1.2 million reserve against other revenue for certain wells no longer deemed to be eligible for the Section 29 tight gas sands credit following an industry tax court ruling ($0.7 million after tax). Late in 1999, the FERC issued a rule proposal that may ultimately restore the eligibility for some or all of the wells in question. For an update on the FERC's actions, please read Note 13 of the Notes to the Consolidated Financial Statements. 2000 and 1999 Compared The following discussion is based on our results before taking into account the selected items discussed above. Net Income and Revenues. We reported net income in 2000 of $30.2 million, or $1.10 per share. During 1999, we reported net income of $0.4 million, or $0.02 per share. Operating income increased $42.9 million, or 135%, and operating revenues increased $83.1 million, or 29%, in 2000. The improvement in operating revenues was mainly a result of the $48.7 million rise in natural gas sales due to the increase in gas prices, and the $24.5 million increase in brokered natural gas sales revenue. Operating revenues were reduced by a $10 million loss on natural gas price collar arrangements used during 2000. See further discussion in Item 7A. Price and production volume increases in crude oil also contributed to the higher operating revenues. Operating income was similarly impacted by these revenue changes. The average Gulf Coast natural gas production sales price rose $1.50 per Mcf, or 66%, to $3.79, increasing operating revenues by approximately $21.2 million. In the Western region, the average natural gas production sales price increased $0.90 per Mcf, or 46%, to $2.86, increasing operating revenues by approximately $24.9 million. The average Appalachian natural gas production sales price increased $0.71 per Mcf, or 28%, to $3.24, increasing operating revenues by approximately $12.7 million. The overall weighted average natural gas production sales price increased $0.97 per Mcf, or 44%, to $3.19, increasing revenues by $58.8 million. Natural gas production volume in the Gulf Coast region was down 1.4 Bcf, or 9%, to 14.1 Bcf primarily 27 due to production difficulties in the Beaurline field and delays in bringing new production on-line in south Louisiana. Natural gas production volume in the Western region was down 0.3 Bcf to 29.0 Bcf due primarily to lower levels of drilling activity in the Mid-Continent area during 1999 and 2000. Natural gas production volume in the Appalachian region was down 2.9 Bcf to 17.8 Bcf, as a result of the sale of certain non-strategic assets in the Appalachian region effective October 1, 1999, and a decrease in drilling activity in the region. Total natural gas production was down 4.6 Bcf, or 7%, generating a revenue decrease of $10.1 million in 2000. Crude oil prices rose $9.59 per Bbl, or 56%, to $26.81, resulting in an increase to operating revenues of approximately $9.2 million. The volume of crude oil sold in the year increased slightly to 953 Mbbls, increasing operating revenues by $0.4 million. Brokered natural gas revenue increased $24.5 million, or 21%, over the prior year. The sales price of brokered natural gas rose 52%, resulting in an increase in revenue of $48.5 million. The volume of natural gas brokered this year declined by 21%, reducing revenues by $24.0 million. After including the related brokered natural gas costs, we realized a net margin of $5.4 million in 2000. Excluding the selected items regarding the contract settlements in 2000, and the sales contract buyout and the Section 29 tax credit provision in 1999, other operating revenues increased $0.2 million to $5.5 million. Costs and Expenses. Total costs and expenses from operations, excluding the selected items related to the impairment of long-lived assets in each year and the costs associated with closing the regional office in Pittsburgh during 2000, increased $40.2 million, or 16%, from 1999 due primarily to the following: . Brokered natural gas cost increased $23.5 million, or 21%, primarily due to the $46.5 million impact of higher purchased natural gas prices. This was partially offset by a $23.0 million reduction to purchased natural cost, the result of fewer brokered sales this year compared to the prior year. . Production and pipeline expense increased $1.9 million, or 6%, primarily as a result of costs associated with the expansion of the Gulf Coast regional office, both in staffing and office facilities. Additionally, operational costs for surface equipment and compressor maintenance were up in the Rocky Mountains area where we drilled 50% more net wells in 2000 compared to 1999. On a units-of-production basis, our company-wide production and pipeline expense was $0.53 per Mcfe in 2000 versus $0.47 per Mcfe in 1999. . Exploration expense increased $8.3 million, or 72%, primarily as a result of the following: . A $3.5 million increase in geological and geophysical expenses over last year due to increased drilling activity in all regions. . A $1.3 million increase in delay rental costs over last year largely due to delays in scheduled drilling projects in the Gulf Coast region. . A $2.1 million increase for salaries, wages and incentive compensation largely attributable to increased staffing in the Gulf Coast region to support the expanded drilling program. . A $0.5 million increase in dry hole costs. Although the drilling success rate improved from 84% in 1999 to 86% in 2000, we recorded two exploratory dry holes in the higher cost Gulf Coast region versus only one in 1999. . Depreciation, depletion, amortization and impairment expense, excluding the selected item related to the SFAS 121 impairment in each year, increased $0.5 million, or 1%, over 1999. A 6% decrease in total natural gas equivalent production caused the expense to remain just slightly above last year's level, despite the 7% increase in the per unit expense to $0.86 per Mcfe. . General and administrative expenses remained at the same level as in 1999. . Taxes other than income increased $6.1 million as a result of higher natural gas and oil revenues. Interest expense decreased $2.9 million primarily due to lower average levels of borrowing on the revolving credit facility. Income tax expense was up $18.1 million due to the comparable increase in earnings before income tax. No significant asset sale activity occurred in 2000. Gain on the sale of assets was $4 million for 1999. 28 These gains are the result of the non-strategic asset divestitures, primarily the sale of the Clarksburg properties in the Appalachian region to EnerVest effective October 1999. 1999 and 1998 Compared The following discussion is based on our results before taking into account the selected items discussed above. Net Income and Revenues. We reported net income in 1999 of $0.4 million, or $0.02 per share. During 1998, we reported net income of $1.9 million, or $0.08 per share. Operating income increased $4.4 million, or 16%, and operating revenues increased $31.9 million, or 13%, in 1999. The improvement in operating revenues was mainly a result of the $19.3 million increase in brokered natural gas revenue and the $7.4 million rise in crude oil and condensate sales, due to both price improvements and production volume increases. Price and production volume increases in natural gas also contributed to the higher operating revenues. Operating income was similarly impacted by these revenue changes. Net income was reduced by a $7.2 million increase in interest expense. Natural gas production volume in the Gulf Coast region was up 4.9 Bcf, or 46%, to 15.5 Bcf primarily due to production from the Oryx acquisition, recent discoveries and development in the Kacee field in south Texas, and the redrilling of certain wells in the Beaurline field. Natural gas production volume in the Western region was down 1.6 Bcf to 29.3 Bcf due primarily to lower levels of drilling activity in the Mid-Continent area during 1998 and 1999. Natural gas production volume in the Appalachian region was down 2.0 Bcf to 20.7 Bcf, as a result of the sale of certain non-strategic assets in the Appalachian region effective October 1, 1999, and a decrease in drilling activity in the region in 1999. Total natural gas production was up 1.3 Bcf, or 2%, yielding a revenue increase of $2.7 million in 1999. The average Gulf Coast natural gas production sales price rose $0.14 per Mcf, or 7%, to $2.29, increasing operating revenues by approximately $2.2 million. In the Western region, the average natural gas production sales price increased $0.06 per Mcf, or 3%, to $1.96, increasing operating revenues by approximately $1.8 million. The average Appalachian natural gas production sales price remained flat to last year at $2.53 per Mcf. The overall weighted average natural gas production sales price increased $0.06 per Mcf, or 3%, to $2.22, increasing revenues by $3.9 million. The volume of crude oil sold in the year increased by 279 Mbbls, or 43%, to 929 Mbbls, increasing operating revenues by $3.6 million. The volume increase was largely due to production from the Oryx acquisition. Crude oil prices rose $4.16 per Bbl, or 32%, to $17.22, resulting in an increase to operating revenues of approximately $3.8 million. Brokered natural gas revenue increased $19.3 million or 20% over the prior year. The sales price of brokered natural gas rose 5% resulting in an increase in revenue of $4.9 million. Additionally, the volume of natural gas brokered this year increased by 15%, increasing revenues by $14.4 million. After including the related brokered natural gas costs, we realized a net margin of $4.4 million in 1999. Excluding the selected items regarding the sales contract buyout and the Section 29 tax credit provision, other operating revenues decreased $1.3 million to $5.4 million. The decline was a result of decreases in activity in the following areas: . Transportation revenue declined $0.6 million. . Revenue from our brine treatment plants declined $0.3 million. . Natural gas liquid sales declined $0.2 million due to lower activity levels during 1999. . Section 29 revenues decreased slightly due to normal production decline. Costs and Expenses. Total costs and expenses from operations, excluding the selected item related to the impairment of long-lived assets, increased $27.0 million, or 12%, from 1998 due primarily to the following: . Brokered natural gas cost increased $20.4 million, or 22%, primarily due to 15% increase in volume which added $13.5 million of cost. Additionally, the purchase cost of natural gas rose 7% resulting in an increase 29 in brokered natural gas cost of $6.9 million. . Production and pipeline expense increased $3.1 million, or 10%, primarily as a result of the incremental cost of operating the Oryx properties acquired in December 1998. On a units-of-production basis, production and pipeline expense was $0.47 per Mcfe in 1999 versus $0.44 per Mcfe in 1998. . Exploration expense decreased $8.1 million, or 41%, primarily as a result of: . A $5.5 million reduction in dry hole costs from 1998, largely due to a smaller drilling program in 1999 that resulted in seven dry holes compared to 12 dry holes in 1998. . A $2.2 million decrease in geological and geophysical costs over last year largely due to a decline in seismic acquisition costs in the Appalachian region. . Depreciation, depletion, amortization and impairment expense, excluding the select item related to the SFAS 121 impairment, increased $11.7 million, or 26%, over 1998. This increase was due to costs associated with the Oryx properties, as well as higher finding costs in 1998 on certain fields in the Gulf Coast region that were largely related to mechanical difficulties associated with drilling. A 4% increase in total natural gas equivalent production, including a 59% production increase in the higher finding cost Gulf Coast region, is the other major component of the DD&A increase. . General and administrative expenses decreased $1.8 million, or 8%, due to: . Lower non-cash stock compensation expense for stock awards ($1.2 million). . Lower outside consulting services ($0.6 million). Interest expense increased $7.2 million primarily due to the debt increase for the Oryx acquisition in December 1998 and to partially fund the 1998 drilling program. Income tax expense was up $1.7 million due to the comparable increase in earnings before income tax. Gain on the sale of assets totaled $4 million for 1999 compared to $0.5 million in 1998. These gains are the result of the non-strategic asset divestitures, primarily the sale of the Clarksburg properties in the Appalachian region to EnerVest effective October 1999. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Oil and gas prices fluctuate widely, and low prices for an extended period of time are likely to have a material adverse impact on our business. Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and, to a lesser extent, oil. Declines in oil and natural gas prices may materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower oil and gas prices also may reduce the amount of oil and gas that we can produce economically. Historically, oil and gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Oil and gas prices declined substantially in 1998 and, despite recent improvement, could decline again. Because our reserves are predominantly natural gas, changes in natural gas prices may have a particularly significant impact on our financial results. Prices for oil and natural gas are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors that are beyond our control. These factors include: . The domestic and foreign supply of oil and natural gas. . The level of consumer product demand. . Weather conditions. . Political conditions in oil producing regions, including the Middle East. . The ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls. . The price of foreign imports. . Actions of governmental authorities. 30 . Domestic and foreign governmental regulations. . The price, availability and acceptance of alternative fuels. . Overall economic conditions. These factors make it impossible to predict with any certainty the future prices of oil and gas. In order to reduce our exposure to short-term fluctuations in the price of oil and natural gas, we sometimes enter into hedging arrangements. Our hedging arrangements apply to only a portion of our production and provide only partial price protection against declines in oil and gas prices. These hedging arrangements may expose us to risk of financial loss and limit the benefit to us of increases in prices. Please read the discussion below related to commodity price swaps and Note 11 of the Notes to the Consolidated Financial Statements for a more detailed discussion of our hedging arrangements. Commodity Price Swaps and Options Hedges on our Production From time to time, we enter into natural gas and crude oil swap agreements with counterparties to hedge price risk associated with a portion of our production. These derivatives are not held for trading purposes. Under these price swaps, we receive a fixed price on a notional quantity of natural gas and crude oil in exchange for paying a variable price based on a market-based index, such as the NYMEX gas and crude oil futures. During 2000, we fixed the price at an average of $4.54 per Mcf on quantities totaling 315 Mmcf, representing less than 1% of the Company's 2000 natural gas production. The notional volume of the crude oil swap transactions was 364 Mbbls at a price of $22.67 per Bbl, which represents approximately 38% of our total oil production for 2000. During 1999, we fixed the price at an average of $2.88 per Mcf on quantities totaling 3,237 Mmcf, representing 5% of the Company's 1999 natural gas production. The notional volume of the crude oil swap transactions was 306 Mbbls at a price of $20.65 per Bbl, which represents approximately one-third of our total oil production for 1999. During 1998, we did not enter into any fixed price swaps to hedge oil or natural gas production. As of the years ending December 31, 2000, and 1999, we had open natural gas price swap contracts on our production as follows: Natural Gas Price Swaps ---------------------------------------------------- Volume Weighted Unrealized in Average Gain/(Loss) Contract Period Mmcf Contract Price (in $ millions) ----------------------------------------------------------------------------------------------------------- As of December 31, 2000 ---------------------- Natural Gas Price Swaps on Our Production in: --------------------------------------------- Full Year 2001 918 $3.75 $(2.8) Full Year 2002 678 3.11 (1.0) Full Year 2003 423 2.81 (0.5) As of December 31, 1999 ----------------------- None Financial derivatives related to natural gas production reduced revenues by $0.3 million in 2000 and $0.3 million in 1999. 31 We had open oil price swap contracts on our production as follows: Oil Price Swaps ------------------------------------------ Volume Weighted Unrealized in Average Gain/(Loss) Contract Period Bbls Contract Price (in $ millions) -------------------------------------------------------------------------------------------- As of December 31, 2000 ----------------------- None As of December 31, 1999 ----------------------- Oil Price Swaps on Our Production in: ------------------------------------- First Quarter 2000 182,000 $22.25 $(0.5) Second Quarter 2000 182,000 23.08 (0.1) Financial derivatives related to crude oil reduced revenue by $2.2 million during 2000 and by $0.8 million during 1999. There were no crude oil price swaps outstanding at December 31, 1998. During 2000, we used several costless collar arrangements to hedge a portion of our natural gas production. There were seven collar arrangements based on separate regional price indexes with a weighted average price floor of $2.74/Mcf and a weighted average price ceiling of $3.38/Mcf. These collars were in place during the months of April through October 2000. During this period, if the index rose above the ceiling price, we paid the counterparty. If the applicable index fell below the floor price, the counterparty paid us. These collars covered a total quantity of 9,909 Mmcf, or 16% of our annual production. In April and May 2000, the index prices all fell within the price collar and no settlements were made. In June 2000, all of the indexes rose above the ceiling prices and remained above the ceiling for the duration of the transaction resulting in a $10 million reduction to our realized revenue for the year. If these hedges had not been in place, our average realized natural gas price for 2000 would have been $0.17 per Mcf higher. There were no commodity price collars in place during 1999. In December 2000, we believed that the pricing environment provided a strategic opportunity to significantly reduce the price risk on a portion of our production through the use of costless collars. As of December 31, 2000, we had open natural gas costless price collar arrangements to hedge our 2001 production as follows: Natural Gas Price Collars ------------------------------------------------- Volume Weighted Unrealized in Average Gain/(Loss) Contract Period Mmcf Ceiling / Floor (in $ millions) ------------------------------------------------------------------------------------------------------- As of December 31, 2000 ------------------------------- Natural Gas Costless Collars on Our Production in: -------------------------------------------------- First Quarter of 2001 5,274 $9.68/$5.59 -- Second Quarter of 2001 8,135 $9.68/$5.59 -- Third Quarter of 2001 8,224 $9.68/$5.59 -- Fourth Quarter of 2001 2,771 $9.68/$5.59 -- The natural gas price hedges, noted above, include several costless collar arrangements based on eight price indexes at which we sell a portion of our production. These hedges are in place for the months of February through October 2001 and cover approximately half of our natural gas production during this period. Hedges on Brokered Transactions We use price swaps to hedge the natural gas price risk on brokered transactions. Typically, we enter into contracts to broker natural gas at a variable price based on the market index price. However, in some circumstances, some of our customers or suppliers request that a fixed price be stated in the contract. After entering into these fixed price contracts to meet the needs of our customers or suppliers, we may use price swaps to effectively convert these fixed price contracts to market-sensitive price contracts. These price swaps are held by us to their maturity and are not held for trading purposes. 32 We entered into price swaps with total notional quantities of 1,295 Mmcf in 2000, 3,572 Mmcf in 1999, and 1,971 Mmcf in 1998, related to our brokered activities, representing 3%, 7%, and 5%, respectively, of our total volume of brokered natural gas sold. As of the years ending December 31, 2000, and 1999, we had open natural gas price swap contracts on brokered transactions as follows: Natural Gas Price Swaps --------------------------------------------- Volume Weighted Unrealized in Average Gain/(Loss) Contract Period Mmcf Contract Price (in $ millions) ------------------------------------------------------------------------------------------------- As of December 31, 2000 ----------------------- None As of December 31, 1999 ----------------------- Natural Gas Price Swaps on Brokered Transactions in: ---------------------------------------------------- First Quarter 2000 1,010 $2.26 $(0.2) Financial derivatives related to natural gas reduced revenues by less than $0.1 million in 2000 and increased revenues by $0.1 million in 1999. We are exposed to market risk on these open contracts, to the extent of changes in market prices of natural gas and oil. However, the market risk exposure on these hedged contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity that is hedged. Since its issuance, we have been modeling the impact of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133). We had two types of hedges in place as of January 1, 2001 when SFAS 133 and SFAS 138 became effective. The first type is a cash flow hedge that fixes the price of a certain monthly quantity of natural gas sold in the Gulf Coast region through September 2003. Based on the current index price strip, the impact of this hedge on January 1, 2001 was to record a Hedge Loss of $0.1 million and a charge to Other Comprehensive Income of $4.2 million. Correspondingly, a Hedge Liability for $4.3 million was established. The second type of hedge is a natural gas price costless collar agreement. We entered into eight of these collars for a portion of our production at regional indexes for the months of February through October 2001. The collars have two components of value: intrinsic value and time value. Under SFAS 133, both components will be valued at the end of each reporting period. Intrinsic value arises when the index price is either above the ceiling or below the floor for any period covered by the collar. If the index is above the ceiling for any month covered by the collar, the intrinsic value would be the difference between the index and the ceiling prices multiplied by the notional volume. Similar to the current accounting treatment, intrinsic value related to the current month would be recorded as a hedge loss (if the index is above the ceiling) or gain (if the index is below the floor). Starting in 2001 under SFAS 133, any changes in the intrinsic value component related to future months will be recorded in Other Comprehensive Income, a component of stockholders' equity on the balance sheet, rather than to the income statement to the extent that the hedge is proven to be effective. In the case of these natural gas price collars, full effectiveness with respect to the intrinsic value calculation is anticipated as they are tied to the same indexes at which our natural gas is sold. Also new under SFAS 133, the time value component, a market premium/discount, is marked- to-market through the income statement each period. Since these collar arrangements were executed on the last business day of 2000, the net premium value at adoption on January 1, 2001 is zero. 33 Fair Market Value of Financial Instruments The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the consolidated balance sheet for cash and cash equivalents, accounts receivable and accounts payable approximate fair value. We use available marketing data and valuation methodologies to estimate the fair value of debt. December 31, 2000 December 31, 1999 Carrying Estimated Carrying Estimated (In thousands) Amount Fair Value Amount Fair Value ---------------------------------------------------------------------- Debt 10.18% Notes $ 32,000 $ 33,162 $ 48,000 $ 50,020 7.19% Notes 100,000 97,033 100,000 91,237 Credit Facility 137,000 137,000 145,000 145,000 -------------------------------------------- $269,000 $267,195 $293,000 $286,257 ============================================ 34 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Page -------------------------------------------------------- Report of Independent Accountants 36 Consolidated Statement of Operations 37 Consolidated Balance Sheet 38 Consolidated Statement of Cash Flows 39 Consolidated Statement of Stockholders' Equity 40 Notes to the Consolidated Financial Statements 41 Supplemental Oil and Gas Information (Unaudited) 61 Quarterly Financial Information (Unaudited) 65 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 are prepared in conformity with generally accepted accounting principles and, accordingly, include certain informed judgments and estimates of management. Management maintains a system of internal accounting and managerial controls and engages internal audit representatives who monitor and test the operation of these controls. Although no system can ensure the elimination of all errors and irregularities, the system is designed to provide reasonable assurance that assets are safeguarded, transactions are executed in accordance with management's authorization, and accounting records are reliable for financial statement preparation. An Audit Committee of the Board of Directors, consisting of directors who are not employees of the Company, meets periodically with management, the independent accountants and internal audit representatives to obtain assurances to the integrity of the Company's accounting and financial reporting and to affirm the adequacy of the system of accounting and managerial controls in place. The independent accountants and internal audit representatives have full and free access to the Audit Committee to discuss all appropriate matters. We believe that the Company's policies and system of accounting and managerial controls reasonably assure the integrity of the information in the consolidated financial statements and in the other sections of the annual report. Ray Seegmiller Chairman of the Board, Chief Executive Officer and President February 22, 2001 35 REPORT OF INDEPENDENT ACCOUNTANTS To the Stockholders and Board of Directors of Cabot Oil & Gas Corporation: In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Cabot Oil & Gas Corporation and its subsidiaries at December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America. 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 of these statements in accordance with auditing standards generally accepted in the United States of America, which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. PricewaterhouseCoopers LLP Houston, Texas February 16, 2001 36 CABOT OIL & GAS CORPORATION CONSOLIDATED STATEMENT OF OPERATIONS Year Ended December 31, (In thousands, except per share amounts) 2000 1999 1998 --------------------------------------------------------------------------- OPERATING REVENUES Natural Gas Production $194,185 $145,495 $138,903 Brokered Natural Gas 141,085 116,554 97,281 Crude Oil and Condensate 25,544 15,909 8,486 Other (Note 13) 7,837 16,079 6,670 ----------------------------- 368,651 294,037 251,340 OPERATING EXPENSES Brokered Natural Gas Cost 135,700 112,164 91,734 Production and Pipeline Operations 35,727 33,357 30,250 Exploration 19,858 11,490 19,564 Depreciation, Depletion and Amortization 53,441 53,357 41,186 Impairment of Unproved Properties 4,368 3,950 4,402 Impairment of Long-Lived Assets 9,143 7,047 -- General and Administrative 20,421 20,136 21,950 Bad Debt Expense (Note 3) 2,096 -- -- Taxes Other Than Income 23,041 16,988 15,324 ----------------------------- 303,795 258,489 224,410 Gain (Loss) on Sale of Assets (39) 3,950 473 ----------------------------- INCOME FROM OPERATIONS 64,817 39,498 27,403 Interest Expense 22,878 25,818 18,598 ----------------------------- Income Before Income Tax Expense 41,939 13,680 8,805 Income Tax Expense 16,467 5,161 3,501 ----------------------------- NET INCOME 25,472 8,519 5,304 Preferred Stock Dividend (Note 10) (3,749) 3,402 3,402 ----------------------------- Net Income Available to Common Stockholders $ 29,221 $ 5,117 $ 1,902 ============================= Basic Earnings per Share Available to Common Stockholders $ 1.07 $ 0.21 $ 0.08 Diluted Earnings per Share Available to Common Stockholders $ 1.06 $ 0.21 $ 0.08 Average Common Shares Outstanding 27,384 24,726 24,733 The accompanying notes are an integral part of these consolidated financial statements. 37 CABOT OIL & GAS CORPORATION CONSOLIDATED BALANCE SHEET December 31, (In thousands, except share amounts) 2000 1999 --------------------------------------------------------------------------- ASSETS CURRENT ASSETS Cash and Cash Equivalents $ 7,574 $ 1,679 Accounts Receivable 85,677 50,391 Inventories 11,037 10,929 Other 5,981 3,641 ------------------- Total Current Assets 110,269 66,640 PROPERTIES AND EQUIPMENT (Successful Efforts Method) 623,174 590,301 OTHER ASSETS 2,191 2,539 ------------------- $735,634 $659,480 =================== LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES Current Portion of Long-Term Debt $ 16,000 $ 16,000 Accounts Payable 81,566 56,551 Accrued Liabilities 20,542 17,387 ------------------- Total Current Liabilities 118,108 89,938 LONG-TERM DEBT 253,000 277,000 DEFERRED INCOME TAXES 108,174 95,012 OTHER LIABILITIES 13,847 11,034 COMMITMENTS AND CONTINGENCIES (Note 8) STOCKHOLDERS' EQUITY Preferred Stock Authorized - 5,000,000 Shares of $0.10 Par Value -6% Convertible Redeemable Preferred; $50 Stated Value; No Shares Outstanding in 2000 and 1,134,000 Shares Outstanding in 1999 (Note 10) 0 113 Common Stock Authorized - 40,000,000 Shares of $0.10 Par Value Issued and Outstanding - 29,494,411 Shares in 2000 and 25,073,660 Shares in 1999 2,949 2,507 Class B Common Stock Authorized - 800,000 Shares of $0.10 Par Value No Shares Issued -- -- Additional Paid-in Capital 285,572 254,763 Accumulated Deficit (41,632) (66,503) Less Treasury Stock, at Cost 302,600 Shares in 2000 and 1999 (4,384) (4,384) ------------------- Total Stockholders' Equity 242,505 186,496 ------------------- $735,634 $659,480 =================== The accompanying notes are an integral part of these consolidated financial statements. 38 CABOT OIL & GAS CORPORATION CONSOLIDATED STATEMENT OF CASH FLOWS Year Ended December 31, (In thousands) 2000 1999 1998 --------------------------------------------------------------------------------- CASH FLOWS FROM OPERATING ACTIVITIES Net Income $ 25,472 $ 8,519 $ 5,304 Adjustments to Reconcile Net Income to Cash Provided by Operations Depletion, Depreciation and Amortization 53,441 53,357 41,186 Impairment of Unproved Properties 4,368 3,950 4,402 Impairment of Long-Lived Assets 9,143 7,047 -- Deferred Income Tax Expense 13,162 9,060 5,844 (Gain) Loss on Sale of Assets 39 (3,950) (473) Exploration Expense 19,858 11,490 19,564 Other 1,141 2,439 1,834 Changes in Assets and Liabilities Accounts Receivable (35,286) 5,408 3,873 Inventories (108) (1,617) (2,437) Other Current Assets (2,357) 164 (1,602) Other Assets 348 598 (1,264) Accounts Payable and Accrued Liabilities 26,976 (5,505) 10,263 Other Liabilities 2,813 1,528 743 --------------------------------- Net Cash Provided by Operations 119,010 92,488 87,237 --------------------------------- CASH FLOWS FROM INVESTING ACTIVITIES Capital Expenditures (99,359) (82,191) (203,632) Proceeds from Sale of Assets 3,150 56,328 1,054 Exploration Expense (19,858) (11,490) (19,564) --------------------------------- Net Cash Used by Investing (116,067) (37,353) (222,142) --------------------------------- CASH FLOWS FROM FINANCING ACTIVITIES Increase in Debt 135,000 125,000 217,000 Decrease in Debt (159,000) (175,000) (73,000) Sale of Common Stock 85,104 1,738 3,589 Retirement of Preferred Stock (51,600) -- -- Treasury Stock Purchases -- -- (4,384) Preferred Dividends Paid (2,202) (3,402) (3,402) Common Dividends Paid (4,350) (3,992) (3,974) Increase in Debt Issuance Cost and Other -- -- (508) --------------------------------- Net Cash Provided (Used) by Financing 2,952 (55,656) 135,321 --------------------------------- Net Increase (Decrease) in Cash and Cash Equivalents 5,895 (521) 416 Cash and Cash Equivalents, Beginning of Year 1,679 2,200 1,784 --------------------------------- Cash and Cash Equivalents, End of Year $ 7,574 $ 1,679 $ 2,200 ================================= The accompanying notes are an integral part of these consolidated financial statements. 39 CABOT OIL & GAS CORPORATION CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY Retained Common Preferred Treasury Paid-In Earning (In thousands) Stock Stock Stock Capital (Deficit) Total --------------------------------------------------------------------------------------------- Balance at December 31, 1997 $2,467 $ 113 $247,033 $(65,551) $184,062 ============================================================ Net Income 5,304 5,304 Exercise of Stock Options 21 3,568 3,589 Preferred Stock Dividends (3,402) (3,402) Common Stock Dividends at $0.16 per Share (3,974) (3,974) Stock Grant Vesting 8 1,472 1,480 Treasury Stock Repurchase $(4,384) (4,384) Other (7) (7) ------------------------------------------------------------ Balance at December 31, 1998 $2,496 $ 113 $(4,384) $252,073 $(67,630) $182,668 ============================================================ Net Income 8,519 8,519 Exercise of Stock Options 7 1,492 1,499 Preferred Stock Dividends (3,402) (3,402) Common Stock Dividends at $0.16 per Share (3,992) (3,992) Stock Grant Vesting 4 1,198 1,202 Other 2 2 ------------------------------------------------------------ Balance at December 31, 1999 $2,507 $ 113 $(4,384) $254,763 $(66,503) $186,496 ============================================================ Net Income 25,472 25,472 Exercise of Stock Options 77 14,764 14,841 Preferred Stock Dividends 3,749 3,749 Common Stock Dividends at $0.16 per Share (4,350) (4,350) Stock Grant Vesting 25 1,412 1,437 Issuance of Common Stock 340 71,219 71,559 Retirement of Preferred Stock (113) (56,586) (56,699) ------------------------------------------------------------ Balance at December 31, 2000 $2,949 $ 0 $(4,384) $285,572 $(41,632) $242,505 ============================================================ The accompanying notes are an integral part of these consolidated financial statements. 40 CABOT OIL & GAS CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 1. Summary of Significant Accounting Policies Basis of Presentation and Principles of Consolidation Cabot Oil & Gas Corporation and its subsidiaries 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 Company operates in one segment, natural gas and oil exploration and exploitation within the continental United States. The consolidated financial statements contain the accounts of the Company after eliminating all significant intercompany balances and transactions. Pipeline Exchanges Natural gas gathering and pipeline operations normally include exchange arrangements with customers and suppliers. The volumes of natural gas due to or from the Company under exchange agreements are recorded at average selling or purchase prices, as the case may be, and are adjusted monthly to reflect market changes. The net value of exchanged natural gas is included in inventories in the consolidated balance sheet. Properties and Equipment The Company uses the successful efforts method of accounting for oil and gas producing activities. Under this method, acquisition costs for proved and unproved properties are capitalized when incurred. Exploration costs, including geological and geophysical costs, the costs of carrying and retaining unproved properties and exploratory dry hole drilling costs, are expensed. Development costs, including the costs to drill and equip development wells, and successful exploratory drilling costs to locate proved reserves are capitalized. The impairment of unamortized capital costs is measured at a lease level and is reduced to fair value if it is determined that the sum of expected future net cash flows is less than the net book value. The Company determines if an impairment has occurred through either adverse changes or as a result of the annual review of all fields. During 2000, two wells in the Beaurline field in south Texas experienced casing collapses. This situation resulted in an impairment to this field of $9.1 million, recorded in the second quarter financial results. During the fourth quarter of 1999, the Company experienced a significant production decline from the Chimney Bayou field located in the Texas Gulf Coast. This decline along with an unsuccessful workover in the Lawson field in Louisiana resulted in a $7 million impairment of long-lived assets during 1999. These impairments were measured based on discounted cash flows utilizing a discount rate appropriate for risks associated with the related properties. 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 units-of- production method using proved developed reserves. The costs of unproved oil and gas properties are generally combined 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 costs are accrued over the productive life of the oil and gas properties on a units-of-production basis. The accrued liability for plug and abandonment costs is included in accumulated depreciation, depletion and amortization. Costs of retired, sold or abandoned properties that make up a part of an amortization base (partial field) are charged to accumulated depreciation, depletion and amortization if the units-of-production rate is not significantly affected. Accordingly, a gain or loss, if any, is recognized only when a group of proved properties (entire field) that make up the amortization base has been retired, abandoned or sold. 41 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. Production volume 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 proved reserves for these properties. Brokered Natural Gas Margin In prior years, the revenues and expenses related to brokering natural gas were reported net on the Consolidated Statement of Operations as Brokered Natural Gas Margin. Beginning in 2000, these amounts are reported gross as part of Operating Revenues and Operating Expenses. Prior year amounts have been reclassified to conform to the current year presentation. The Company realizes brokered margin as a result of buying and selling natural gas in back-to-back transactions. The Company realized $5.4 million, $4.4 million and $5.5 million of brokered natural gas margin in 2000, 1999 and 1998, respectively. Income Taxes The Company follows the asset and liability method of 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 $12.7 million at December 31, 2000, and $5.9 million at December 31, 1999. Risk Management Activities From time to time, the Company enters into derivative contracts, such as natural gas price swaps or costless price collars, as a hedging strategy to manage commodity price risk associated with its inventories, production or other contractual commitments. These transactions are executed for purposes other than trading. Gains or losses on these hedging activities are generally recognized over the period that the inventory, production or other underlying commitment is hedged as an offset to the specific hedged item. Cash flows related to any recognized gains or losses associated with these hedges are reported as cash flows from operations. If a hedge is terminated prior to expected maturity, gains or losses are deferred and included in income in the same period that the underlying production or other contractual commitment is delivered. Unrealized gains or losses associated with any derivative contract not considered a hedge would be recognized currently in the results of operations. 42 A derivative instrument qualifies as a hedge if all of the following tests are met: . The item to be hedged exposes the Company to price risk. . The derivative reduces the risk exposure and is designated as a hedge at the time the Company enters into the contract. . At the inception of the hedge and throughout the hedge period there is a high correlation between changes in the market value of the derivative instrument and the fair value of the underlying item being hedged. When the designated item associated with a derivative instrument matures, is sold, extinguished or terminated, derivative gains or losses are recognized as part of the gain or loss on the sale or settlement of the underlying item. For example, in the case of natural gas price hedges, the gain or loss is reflected in natural gas revenue. When a derivative instrument is associated with an anticipated transaction that is no longer expected to occur or if correlation no longer exists, the gain or loss on the derivative is recognized currently in the results of operations to the extent the market value changes in the derivative have not been offset by the effects of the price changes on the hedged item since the inception of the hedge. See Note 11 Financial Instruments for further discussion. In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133). SFAS 133 requires all derivatives to be recognized in the statement of financial position as either assets or liabilities and measured at fair value. In addition, all hedging relationships must be designated, reassessed and documented according to the provisions of SFAS 133. This statement was initially effective for financial statements for fiscal years beginning after June 15, 1999. However, in June 1999, the FASB issued SFAS 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of Effective Date of SFAS 133," which delayed the effective date of SFAS 133 to fiscal years beginning after June 15, 2000. In June 2000, the FASB issued SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities". This pronouncement amended portions of SFAS 133 and was adopted with SFAS 133 effective January 1, 2001. Since the issuance of SFAS 133 and SFAS 138, the Company has been modeling the proforma impact on our financial statements. The Company has certain cash flow hedges (a price swap and eight costless collar arrangements) in place, which were open as of January 1, 2001 when SFAS 133 and SFAS 138 became effective. Based on the first of the year index price strip, the combined impact of these hedges at adoption was a Hedge Loss of $0.1 million and a charge to Other Comprehensive Income of $4.2 million. Correspondingly, a Hedge Liability for $4.3 million was established. Cash Equivalents The Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. At December 31, 2000, and 1999, the majority of cash and cash equivalents is concentrated in one financial institution. The Company periodically assesses the financial condition of the institution and believes that any possible credit risk is minimal. Use of Estimates In preparing financial statements, the Company follows generally accepted accounting principles. These principles require management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. The Company's most significant financial estimates are based on the remaining proved oil and gas reserves (see Supplemental Oil and Gas Information). Actual results could differ from those estimates. 43 2. Properties and Equipment Properties and equipment are comprised of the following: December 31, (In thousands) 2000 1999 ------------------------------------------------------------------- Proved Oil and Gas Properties $ 993,397 $ 906,852 Unproved Oil and Gas Properties 31,780 32,262 Gathering and Pipeline Systems 128,257 124,708 Land, Building and Improvements 4,538 4,359 Other 25,601 23,206 ----------------------- 1,183,573 1,091,387 Accumulated Depreciation, Depletion, Amortization and Impairments (560,399) (501,086) ----------------------- $ 623,174 $ 590,301 ======================= As a component of accumulated depreciation, depletion and amortization, total future plug and abandonment costs were $12.4 million at December 31, 2000, and $11.5 million at December 31, 1999. The Company believes that this accrual method adequately provides for its estimated future plug and abandonment costs over the reserve life of the oil and gas properties. 3. Additional Balance Sheet Information Certain balance sheet amounts are comprised of the following: December 31, (In thousands) 2000 1999 ------------------------------------------------------------ Accounts Receivable Trade Accounts $79,773 $44,739 Joint Interest Accounts 4,074 4,395 Insurance Recoveries 0 1,177 Current Income Tax Receivable 37 111 Other Accounts 4,347 263 ----------------- 88,231 50,685 Allowance for Doubtful Accounts /(1)/ (2,554) (294) ----------------- $85,677 $50,391 ================= Accounts Payable Trade Accounts $20,855 $12,195 Natural Gas Purchases 12,525 14,918 Wellhead Gas Imbalances 2,185 2,177 Royalty and Other Owners 22,858 11,316 Capital Costs 13,486 10,103 Dividends Payable 0 851 Taxes Other than Income 2,654 1,279 Drilling Advances 456 614 Other Accounts 6,547 3,098 ----------------- $81,566 $56,551 ================= ------------------------------------------------------------ /(1)/ Includes a $2.1 million addition in 2000 in connection with two trade receivable accounts determined not to be collectible due to recent bankruptcy filings of the customers. 44 December 31, (In thousands) 2000 1999 --------------------------------------------------------------------- Accrued Liabilities Employee Benefits $ 5,441 $ 5,203 Taxes Other than Income 11,363 8,471 Interest Payable 2,478 2,780 Other Accrued 1,260 933 ----------------- $20,542 $17,387 ================= Other Liabilities Postretirement Benefits Other than Pension $ 1,497 $ 799 Accrued Pension Cost 6,743 6,290 Taxes Other than Income and Other 5,607 3,945 ----------------- $13,847 $11,034 ================= 4. Inventories Inventories are comprised of the following: December 31, (In thousands) 2000 1999 --------------------------------------------------------------------- Natural Gas and Oil in Storage $10,277 $ 8,702 Tubular Goods and Well Equipment 2,122 2,052 Pipeline Exchange Balances (1,362) 175 ----------------- $11,037 $10,929 ================= 5. Debt and Credit Agreements 10.18% Notes In May 1990, the Company issued an aggregate principal amount of $80 million of its 12-year 10.18% Notes (10.18% Notes) to a group of nine institutional investors in a private placement offering. The 10.18% Notes require five annual $16 million principal payments each May starting in 1998. The fourth payment due in May 2001, classified as Current Portion of Long-Term Debt, is a current liability on the Company's Consolidated Balance Sheet. The Company may prepay all or any portion of the remaining $32 million of debt at any time with a prepayment penalty. The 10.18% Notes contain restrictions on the merger of the Company or any subsidiary with a third party except under certain limited conditions. There are also various other restrictive covenants customarily found in such debt instruments, including a restriction on the payment of dividends and a required asset coverage ratio (present value of proved reserves to debt and other liabilities) that must be at least 1.5 to 1.0. 7.19% Notes In November 1997, the Company issued an aggregate principal amount of $100 million of its 12-year 7.19% Notes (7.19% Notes) to a group of six institutional investors in a private placement offering. The 7.19% Notes require five annual $20 million principal payments starting in November 2005. The Company may prepay all or any portion of the indebtedness on any date with a prepayment penalty. The 7.19% Notes contain restrictions on the merger of the Company or any subsidiary with a third party other than under certain limited conditions. There are also various other restrictive covenants customarily found in such debt instruments. These covenants include a required asset coverage ratio (present value of proved reserves to debt and other liabilities) that must be at least 1.5 to 1.0, and a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0. Revolving Credit Agreement In November 1998, the Company replaced its $135 million Revolving Credit Agreement that utilized five banks with a new $250 million Revolving Credit Agreement (Credit Facility) with 9 banks. The term of the Credit Facility expires on December 17, 2003. The available credit line is subject to adjustment from time-to-time on the 45 basis of the projected present value (as determined by the banks' petroleum engineer) of estimated future net cash flows from certain proved oil and gas reserves and other assets of the Company. While the Company does not expect a change in the available credit line, in the event that it is adjusted below the outstanding level of borrowings, the Company has a period of 180 days to reduce its outstanding debt to the adjusted credit line. The Credit Facility also includes a requirement to pay down half of the debt in excess of the adjusted credit line within the first 90 days of such an adjustment. 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. For CD rate and LIBOR borrowings, interest rates are subject to increase if the total indebtedness is either greater than 60% or 80% of the Company's debt limit of $400 million, as shown below. Debt Percentage ----------------------------------------------- Lower than 60% 60% - 80% Higher than 80% =============================================== LIBOR margin 0.750% 1.000% 1.250% CD margin 0.875% 1.125% 1.375% Commitment fee rate 0.250% 0.375% 0.375% The Credit Facility provides for a commitment fee on the unused avaible balance at an annual rate one-fourth of 1% or three-eighths of 1% depending on the level of indebtedness as indicated above. The Company's effective interest rates for the Credit Facility in the years ended December 31, 2000, 1999 and 1998 were 7.8%, 6.7%, and 6.8%, respectively. The Credit Facility contains various customary restrictions, which include the following: (a) Prohibition of the merger of the Company or any subsidiary with a third party except under certain limited conditions. (b) Prohibition of the sale of all or substantially all of the Company's or any subsidiary's assets to a third party. (c) Maintenance of a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0. 6. Employee Benefit Plans Pension Plan The Company has a non-contributory, defined benefit pension plan for all full-time employees. Plan benefits are based primarily on years of service and salary level near retirement. Plan assets are mainly fixed income investments and equity securities. The Company complies with the Employee Retirement Income Security Act of 1974 and Internal Revenue Code limitations when funding the plan. 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, 2000, 1999 and 1998 are comprised of the following: (In thousands) 2000 1999 1998 --------------------------------------------------------------------- Qualified Current Year Service Cost $ 832 $1,012 $ 853 Interest Accrued on Pension Obligation 1,070 1,072 945 Expected Return on Plan Assets (1,123) (919) (1,434) Net Amortization and Deferral 88 88 706 Recognized Gain (282) -- (20) ------- ------ ------- Net Periodic Pension Cost $ 585 $1,253 $ 1,050 ======= ====== ======= 46 (In thousands) 2000 1999 1998 --------------------------------------------------------------- Non-Qualified Current Year Service Cost $ 60 $ 140 $ 81 Interest Accrued on Pension Obligation 42 67 45 Net Amortization 77 77 54 Recognized (Gain) Loss (5) 35 20 Settlement Charge -- -- 213 ----- ----- ----- Net Periodic Pension Cost $ 174 $ 319 $ 413 ===== ===== ===== The following table illustrates the funded status of the Company's pension plans at December 31, 2000, and 1999, respectively: 2000 1999 (In thousands) Qualified Non-Qualified Qualified Non-Qualified -------------------------------------------------------------------------------------------- Actuarial Present Value of Accumulated Benefit Obligation $12,188 $ 753 $10,474 $ 504 Projected Benefit Obligation $16,173 $ 978 $14,009 $ 537 Plan Assets at Fair Value 11,801 -- 12,092 -- ---------------------------------------------- Projected Benefit Obligation in Excess of Plan Assets 4,372 978 1,917 537 Unrecognized Net Gain (Loss) 1,956 (351) 4,964 114 Unrecognized Prior Service Cost (599) (630) (687) (707) Adjustment to Recognize Minimum Liability -- 756 -- 560 ---------------------------------------------- Accrued Pension Cost $ 5,729 $ 753 $ 6,194 $ 504 ============================================== The change in the combined projected benefit obligation of the Company's qualified and non-qualified pension plans during the last three years is explained as follows: (In thousands) 2000 1999 1998 -------------------------------------------------------------- Beginning of Year $14,546 $16,449 $13,441 Service Cost 892 1,152 935 Interest Cost 1,112 1,139 990 Plan Amendments -- -- 488 Actuarial Loss (Gain) 1,328 (3,657) 1,803 Benefits Paid (727) (537) (1,208) --------------------------------- End of Year $17,151 $14,546 $16,449 ================================= The change in the combined plan assets at fair value of the Company's qualified and non-qualified pension plans during the last three years is explained as follows: (In thousands) 2000 1999 1998 -------------------------------------------------------------- Beginning of Year $12,092 $10,344 $ 8,890 Actual Return on Plan Assets (440) 2,428 1,608 Employer Contribution 1,172 101 1,227 Benefits Paid (727) (537) (1,208) Expenses Paid (296) (244) (173) --------------------------------- End of Year $11,801 $12,092 $10,344 ================================= 47 The reconciliation of the combined funded status of the Company's qualified and non-qualified pension plans at the end of the last three years is explained as follows: (In thousands) 2000 1999 1998 ----------------------------------------------------------------------------- Funded Status $ 5,350 $ 2,454 $ 6,105 Unrecognized Gain 1,605 5,078 121 Unrecognized Prior Service Cost (1,229) (1,394) (1,558) --------------------------- Net Amount Recognized $ 5,726 $ 6,138 $ 4,668 =========================== Accrued Benefit Liability - Qualified Plan $ 5,729 $ 6,194 $ 5,030 Accrued Benefit Liability - Non-Qualified Plan 753 504 439 Intangible Asset (756) (560) (801) --------------------------- Net Amount Recognized $ 5,726 $ 6,138 $ 4,668 =========================== Assumptions used to determine post-retirement benefit obligations and pension costs are as follows: 2000 1999 1998 ----------------------------------------------------------------- Discount Rate /(1)/ 7.50% 7.75% 7.00% Rate of Increase in Compensation Levels 4.00% 4.00% 4.00% Long-Term Rate of Return on Plan Assets 9.00% 9.00% 9.00% ----------------------------------------------------------------- /(1)/ Represents the rate used to determine the benefit obligation. A 7.75% discount rate was used to compute pension costs in 2000, a rate of 7.0% was used in 1999, and a rate of 7.5% was used in 1998. Savings Investment Plan The Company has a Savings Investment Plan (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 $0.7 million, $0.7 million, and $0.8 million in 2000, 1999, and 1998, respectively. The Company's Common Stock is an investment option within the SIP. Deferred Compensation Plan In 1998, the Company established a Deferred Compensation Plan. This plan is available to officers of the Company and acts as a supplement to the Savings Investment Plan. The Company matches a portion of the employee's contribution and those assets are invested in instruments selected by the employee. Unlike the SIP, the Deferred Compensation Plan does not have dollar limits on tax deferred contributions. However, the assets of this plan are held in a rabbi trust and are subject to additional risk of loss in the event of bankruptcy or insolvency of the Company. At December 31, 2000, the balance in the Deferred Compensation Plan's rabbi trust was $1.2 million. Postretirement Benefits Other Than Pensions In addition to providing pension benefits, the Company provides certain health care and life insurance benefits for retired employees, including their spouses, eligible dependents and surviving spouses (retirees). These benefits are commonly called postretirement benefits. Most employees become eligible for these benefits if they meet certain age and service requirements at retirement. The Company was providing postretirement benefits to 241 retirees at the end of 2000 and 250 retirees at the end of 1999. When the Company adopted SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," in 1992, it began amortizing the $16.9 million accumulated postretirement benefit, known as the Transition Obligation, over a period of 20 years. The amortization benefit of the unrecognized Transition Obligation in 1998, 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 was amortized over a 5.75 year period 48 beginning in 1993 and ending in 1998. Postretirement benefit costs recognized during the last three years are as follows: (In thousands) 2000 1999 1998 -------------------------------------------------------------------------- Service Cost of Benefits Earned During the Year $ 187 $ 225 $ 190 Interest Cost on the Accumulated Postretirement Benefit Obligation 534 515 525 Amortization Benefit of the Unrecognized Gain (132) (131) (165) Amortization Benefit of the Unrecognized Transition Obligation 662 690 (435) ----------------------- Total Postretirement Benefit Cost (Benefit) $1,251 $1,299 $ 115 ======================= The health care cost trend rate used to measure the expected cost in 2000 for medical benefits to retirees was 8%. Provisions of the plan should prevent further increases in employer cost after 2000. A one-percentage-point increase or decrease in health care cost trend rates for future periods would not impact the accumulated net postretirement benefit obligation or the total postretirement benefit cost recognized. Company costs are capped at 2000 levels, and the retirees assume any future increases in costs. The funded status of the Company's postretirement benefit obligation at December 31, 2000, and 1999 is comprised of the following: (In thousands) 2000 1999 -------------------------------------------------------------------------- Plan Assets at Fair Value $ -- $ -- Accumulated Postretirement Benefits Other Than Pensions 5,429 7,243 Unrecognized Cumulative Net Gain 3,847 2,056 Unrecognized Transition Obligation (7,279) (7,940) ---------------- Accrued Postretirement Benefit Liability $ 1,997 $ 1,359 ================ The change in the accumulated postretirement benefit obligation during the last three years is presented as follows: (In thousands) 2000 1999 1998 --------------------------------------------------------------- Beginning of Year $ 7,243 $ 7,693 $ 7,303 Service Cost 187 225 190 Interest Cost 534 515 526 Amendments 0 (253) 0 Actuarial Loss/(Gain) (1,923) (102) 230 Benefits Paid (612) (835) (556) --------------------------- End of Year $ 5,429 $ 7,243 $ 7,693 =========================== 49 7. Income Taxes Income tax expense is summarized as follows: Year Ended December 31, (In thousands) 2000 1999 1998 - ---------------------------------------------------------------- Current Federal $ 3,089 /(1)/ $(3,899) $(1,696) State 216 -- 65 ------------------------------- Total 3,305 (3,899) (1,631) ------------------------------- Deferred Federal 11,804 8,910 4,869 State 1,358 150 263 ------------------------------- Total 13,162 9,060 5,132 ------------------------------- Total Income Tax Expense $ 16,467 $ 5,161 $ 3,501 =============================== - ---------------------------------------------------------------- /(1)/ The Federal Income Taxes Payable is zero at December 31, 2000 primarily as a result of tax payments made during the year and a $1.8 million tax benefit related to stock option exercises during 2000. In the table above, the $4.5 million refund received in 1999 that applied to a net operating loss carryback to 1997 is reflected in "Current - Federal". The 1998 "Current - Federal" amount includes the effect of a $2.0 million income tax refund received in 1998 that applied to a net operating loss carryback to 1992. Total income taxes were different than the amounts computed by applying the statutory federal income tax rate as follows: Year Ended December 31, (In thousands) 2000 1999 1998 - ------------------------------------------------------------------------------ Statutory Federal Income Tax Rate 35% 35% 35% Computed "Expected" Federal Income Tax $14,679 $4,788 $3,081 State Income Tax, Net of Federal Income Tax 1,552 506 352 Other, Net 236 (133) 68 ------------------------- Total Income Tax Expense $16,467 $5,161 $3,501 ========================= The tax effects of temporary differences that resulted in significant portions of the deferred tax liabilities and deferred tax assets as of December 31, 2000, and 1999 were as follows: (In thousands) 2000 1999 - ---------------------------------------------------------------------------- Deferred Tax Liabilities Property, Plant and Equipment $142,935 $133,982 ------------------ Deferred Tax Assets Alternative Minimum Tax Credit Carryforwards 5,817 3,044 Net Operating Loss Carryforwards 13,904 20,165 Note Receivable on Section 29 Monetization/(1)/ 6,397 11,228 Items Accrued for Financial Reporting Purposes 8,643 4,533 ------------------ 34,761 38,970 ------------------ Net Deferred Tax Liabilities $108,174 $ 95,012 ================== - ----------------------------------------------------------------------------- /(1)/ As a result of the monetization of Section 29 tax credits in 1996 and 1995, the Company recorded an asset sale for tax purposes in exchange for a long-term note receivable which will be repaid through 100% working and royalty interest in the production from the sold properties. At December 31, 2000, the Company has a net operating loss carryforward for regular income tax reporting purposes of $33.9 million that will begin expiring in 2011. In addition, the Company has an alternative minimum tax credit carryforward of $5.8 million which does not expire and can be used to offset regular income taxes in future years to the extent that regular income taxes exceed the alternative minimum tax in any year. 50 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. Leases for the Company's offices in Houston and Denver each run for approximately nine more years. Most of the other leases expire within five years and may be renewed. Rent expense under such arrangements totaled $6.3 million, $5.0 million, and $4.3 million for the years ended December 31, 2000, 1999, and 1998, respectively. Future minimum rental commitments under non-cancelable leases in effect at December 31, 2000 are as follows: (In thousands) --------------------------- 2001 $ 4,580 2002 4,455 2003 3,859 2004 3,663 2005 3,568 Thereafter 11,941 ------- $32,066 ======= Minimum rental commitments are not reduced by minimum sublease rental income of $0.6 million due in the future under non-cancelable subleases. Contingencies The Company is a defendant in various lawsuits and is involved in other gas contract issues. In the Company's opinion, final judgments or settlements, if any, which may be awarded in connection with any one or more of these suits and claims could have a significant impact on the results of operations and cash flows of any period. However, there would not be a material adverse effect on the Company's financial position. Environmental Liability The EPA notified the Company in February 2000 that it might have potential liability for waste material disposed of at the Casmalia Superfund Site ("Site"), located on a 252-acre parcel in Santa Barbara County, California. Over 10,000 separate parties disposed of waste at the Site while it was operational from 1973 to 1989. The EPA stated that federal, state and local governmental agencies along with the numerous private entities that used the Site for waste disposal will be expected to pay the clean-up costs which could total as much as several hundred million dollars. The EPA is also pursuing the owners/operators of the Site to pay for remediation. Documents received with the notification from the EPA indicate that the Company used the Site principally to dispose of salt water from two wells over a period from 1976 to 1979. There is no allegation that the Company violated any laws in the disposal of material at the Site. The EPA's actions stemmed from the fact that the owners/operators of the Site do not have the financial means to implement a closure plan for the Site. A group of potentially responsible parties, including the Company, have had extensive settlement discussions with the EPA. However, the parties have yet to reach an agreement. The Company has a reserve that it believes to be adequate to cover this potential environmental liability based on its estimate of the probable outcome of this matter. While the potential impact to the Company may materially affect quarterly or annual financial results, management does not believe it would materially impact the Company's financial position or cash flows. The Company will continue to monitor the facts and its assessment of its liability related to this claim. 51 Wyoming Royalty Litigation In June 2000, two overriding royalty owners sued the Company in Wyoming State court. The plaintiffs have requested class certification under the Wyoming Rules of Civil Procedure and allege that the Company has deducted impermissible costs of production from royalty payments to the plaintiffs and other similarly situated persons. Additionally, the suit claims that the Company has failed to properly inform the plaintiffs and other similarly situated persons of the deductions taken from royalties. While the Company believes that it has substantial defenses to this claim and intends to vigorously assert such defenses, the investigation into this claim has only just begun and, accordingly, the Company can not presently determine the likelihood or range of any potential loss. 9. Cash Flow Information Cash paid for interest and income taxes is as follows: Year Ended December 31, (In thousands) 2000 1999 1998 ---------------------------------------------- Interest $23,180 $25,445 $18,341 Income Taxes $ 1,419 $ 652 $ 827 At December 31, 2000, and 1999, the Accounts Payable balance on the Consolidated Balance Sheet included payables for capital expenditures of $13.5 million and $10.1 million, respectively. 10. Capital Stock Incentive Plans On May 12, 1998, the Amended and Restated 1994 Long-Term Incentive Plan and the Amended and Restated 1994 Non-Employee Director Stock Option Plan were approved by the shareholders. The Company has two other stock option plans: the 1990 Incentive Stock Option Plan and the 1990 Non-Employee Director Stock Option Plan. Under these four plans (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 3,860,000 shares of Common Stock, par value $0.10 per share, may be issued under the Incentive Plans. All stock options have a maximum term of five or 10 years from the date of grant, with most vesting over time. The options are issued at market value on the date of grant. The minimum exercise period for stock options is six months from the date of grant. No SARs have been granted under the Incentive Plans. Information regarding the Company's Incentive Plans is summarized below: December 31, 2000 1999 1998 ----------------------------------------------------------------------------- Shares Under Option at Beginning of Period 1,773,389 1,557,936 1,404,877 Granted 299,250 454,100 355,000 Exercised 896,081 55,032 152,917 Surrendered or Expired 52,410 183,615 49,024 ------------------------------- Shares Under Option at End of Period 1,124,148 1,773,389 1,557,936 =============================== Options Exercisable at End of Period 474,599 1,108,637 1,092,295 =============================== 52 For each of the three most recent years, the price range for outstanding options was $13.25 to $22.75 per share. The following tables provide more information about the options by exercise price and year. Options with exercise prices between $13.25 and $20.00 per share: December 31, 2000 1999 1998 ----------------------------------------------------------------------------------------------------- Options Outstanding ------------------- Number of Options 866,498 1,412,072 1,051,936 Weighted Average Exercise Price $ 17.63 $ 16.07 $ 15.53 Weighted Average Contractual Term (in years) 2.60 2.40 2.46 Options Exercisable ------------------- Number of Options 372,418 953,640 927,795 Weighted Average Exercise Price $ 16.27 $ 15.44 $ 15.32 Options with exercise prices between $20.01 and $22.75 per share: December 31, 2000 1999 1998 ------------------------------------------------------------------------------------------------------------ Options Outstanding -------------------- Number of Options 257,650 361,317 506,000 Weighted Average Exercise Price $ 22.46 $ 22.50 $ 22.04 Weighted Average Contractual Term (in years) 1.90 3.37 3.47 Options Exercisable -------------------- Number of Options 102,181 154,997 164,500 Weighted Average Exercise Price $ 22.51 $ 22.55 $ 21.17 Under the Amended and Restated 1994 Long-Term Incentive Plan, the Compensation Sub-Committee of the Board of Directors may grant awards of performance shares of stock to members of the executive management group. Each grant of performance shares has a three-year performance period, measured as the change from July 1 of the initial year of the performance period to June 30 of the third year. The number of shares of Common Stock received at the end of the performance period is based mainly on the relative stock price growth between the two measurement dates of Common Stock compared to that of a group of peer companies. The performance shares that were granted on July 1, 1994, expired on June 30, 1997, without issuing any Common Stock of the Company. The performance shares granted in July 1995 were converted to 21,692 shares of the Company's Common Stock in 1998, and the performance shares granted in July 1996 were converted to 19,090 shares of the Company's Common Stock in 1999. The Board of Directors has not issued performance shares since July 1996, and currently, there are no performance shares outstanding. Statement of Financial Accounting Standards (SFAS) No. 123, "Accounting for Stock-Based Compensation," outlines a fair value based method of accounting for stock options or similar equity instruments. The Company has opted to continue using the intrinsic value based method, as recommended by Accounting Principles Board (APB) Opinion No. 25, to measure compensation cost for its stock option plans. If the Company had adopted SFAS 123, the pro forma results of operations would be as follows: 2000 1999 1998 - ------------------------------------------------------------------------------------------------------------------------- Net Income $28.2 million $4.3 million $1.3 million Net Income per Share $1.03 $0.20 $0.06 Weighted Average Value of Options Granted During the Year /(1)/ $6.63 $4.78 $6.21 Assumptions: Stock Price Volatility 34.5% 27.4% 26.1% Risk Free Rate of Return 5.21% 5.21% 5.63% Dividend Rate (per year) $0.16 $0.16 $0.16 Expected Term (in years) 4 4 4 - ------------------------------------------------------------------------------------------------------------------------- /(1)/ Calculated using the fair value based method. The fair value of stock options included in the pro forma results for each of the three years is not necessarily 53 indicative of future effects on net income and earnings per share. Dividend Restrictions The Board of Directors of the Company determines the amount of future cash dividends, if any, to be declared and paid on the Common Stock depending on, among other things, the Company's financial condition, funds from operations, the level of its capital and exploration expenditures, and its future business prospects. The Company's 10.18% Note Agreement restricts certain payments associated with the following: (a) Purchasing, redeeming, retiring or otherwise acquiring any capital stock of the Company or any option, warrant or other right to acquire such capital stock. (b) Declaring any dividend, if immediately prior to or after making payments, the dividend exceeds consolidated net cash flow (as defined) and the ratio of proved reserves to debt is less than 1.7 to 1, or there has been an event of default under the Note Agreement. As of December 31, 2000, these restrictions did not impact the Company's ability to pay regular dividends. Neither the 7.19% Note Agreement nor the Credit Facility Agreement has a restricted payment provision. Treasury Stock In August 1998, the Board of Directors authorized the Company to repurchase up to two million shares of outstanding Common Stock at market prices. The timing and amount of these stock purchases are determined at the discretion of management. The Company may use the repurchased shares to fund stock compensation programs presently in existence, or for other corporate purposes. As of December 31, 1998, the Company had repurchased 302,600 shares, or 15% of the total authorized number of shares, for a total cost of approximately $4.4 million. No additional shares were repurchased during 1999 or 2000. The stock repurchase plan was funded from increased borrowings on the revolving credit facility. No treasury shares were delivered or sold by the Company during the year. 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. On December 8, 2000, the rights agreement for the plan was amended and restated to extend the term of the plan to 2010 and to make other changes. Each right becomes exercisable, at a price of $55, when any person or group has acquired or made a tender or exchange offer for beneficial ownership of 15 percent or more of the Company's outstanding Common Stock. 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). After a person or group acquires beneficial ownership of 15% of the Common Stock, each right entitles the holder to purchase Common Stock or other property having a market value (as defined in the plan) of twice the exercise price of the right. An exception to this triggering event applies in the case of a tender or exchange offer for all outstanding shares of Common Stock determined to be fair and in the best interests of the Company and its stockholders by a majority of the independent directors. Under certain circumstances, the Board of Directors may opt to exchange one share of Common Stock for each exercisable right. If there is a 15% holder and 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, 2000, and 1999, there were no shares of Junior Preferred Stock issued or outstanding. The rights expire on January 21, 2010, and may be redeemed by the Company for $0.01 per right at any time before a person or group acquires beneficial ownership of 15% of the Common Stock. Preferred Stock At December 31, 1999, and 1998, 1,134,000 shares of 6% convertible redeemable preferred stock (6% preferred stock) were issued and outstanding. In May 2000, the Company repurchased all of the then-outstanding 54 shares of preferred stock from the holder for $51.6 million. Since this stock had been recorded at a stated value of $56.7 million on the Company's balance sheet, the benefit from a $5.1 million negative dividend to preferred stockholders was included in net income available to common shareholders. After this repurchase transaction, the Company retired all shares of preferred stock. This transaction was funded by the sale of common stock in a public offering. The Company sold 3.4 million shares to the public at $21.50 per share. After deducting the costs of this transaction, the Company received net proceeds of $71.5 million. After repurchasing the preferred stock, the excess proceeds from this transaction were used to reduce debt on the Company's revolving credit facility. 11. Financial Instruments The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the consolidated balance sheet for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value. The Company uses available marketing data and valuation methodologies to estimate fair value of debt. December 31, 2000 December 31, 1999 Carrying Estimated Carrying Estimated (In thousands) Amount Fair Value Amount Fair Value --------------------------------------------------------------------- Debt 10.18% Notes $ 32,000 $ 33,162 $ 48,000 $ 50,020 7.19% Notes 100,000 97,033 100,000 91,237 Credit Facility 137,000 137,000 145,000 145,000 ------------------------------------------- $269,000 $267,195 $293,000 $286,257 =========================================== 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 difference between the issue rate and the year-end market rate. The fair value of the 10.18% Notes and the 7.19% Notes is based on interest rates currently available to the Company. The Credit Facility approximates fair value because this instrument bears interest at rates based on current market rates. Commodity Price Swaps and Options Hedges on our Production From time to time, the Company enters into natural gas and crude oil swap agreements with counterparties to hedge price risk associated with a portion of our production. These derivatives are not held for trading purposes. Under these price swaps, the Company receives a fixed price on a notional quantity of natural gas and crude oil in exchange for paying a variable price based on a market-based index, such as the NYMEX gas and crude oil futures. During 2000, the Company fixed the price at an average of $4.54 per Mcf on quantities totaling 315 Mmcf, representing less than 1% of the Company's 2000 natural gas production. The notional volume of the crude oil swap transactions was 364 Mbbls at a price of $22.67 per Bbl, which represents approximately 38% of the Company's total oil production for 2000. During 1999, the Company fixed the price at an average of $2.88 per Mcf on quantities totaling 3,237 Mmcf, representing 5% of the Company's 1999 natural gas production. The notional volume of the crude oil swap transactions was 306 Mbbls at a price of $20.65 per Bbl, which represents approximately one-third of the Company's total oil production for 1999. During 1998, the Company did not enter into any fixed price swaps to hedge oil or natural gas production. 55 As of the years ending December 31, 2000, and 1999, the Company had open natural gas price swap contracts on its production as follows: Natural Gas Price Swaps ------------------------------------- Volume Weighted Unrealized in Average Gain/(Loss) Contract Period Mmcf Contract Price (in $ millions) -------------------------------------------------------------------------------------------- As of December 31, 2000 ----------------------- Natural Gas Price Swaps on Production in: ---------------------------------------- Full Year 2001 918 $3.75 $(2.8) Full Year 2002 678 3.11 (1.0) Full Year 2003 423 2.81 (0.5) As of December 31, 1999 --------------------------------------------- None Financial derivatives related to natural gas production reduced revenues by $0.3 million in 2000 and $0.3 million in 1999. The Company had open oil price swap contracts on its production as follows: Oil Price Swaps ----------------------------------------- Volume Weighted Unrealized in Average Gain/(Loss) Contract Period Bbls Contract Price (in $ millions) ---------------------------------------------------------------------------------------- As of December 31, 2000 ----------------------- None As of December 31, 1999 ----------------------- Oil Price Swaps on Production in: -------------------------------- First Quarter 2000 182,000 $22.25 $(0.5) Second Quarter 2000 182,000 23.08 (0.1) Financial derivatives related to crude oil reduced revenue by $2.2 million during 2000 and by $0.8 million during 1999. There were no crude oil price swaps outstanding at December 31, 1998. During 2000, the Company used several costless price collar agreements (put and call options) to hedge a portion of its natural gas production. There were seven collar arrangements based on separate regional price indexes with a weighted average price floor of $2.74/Mcf and a weighted average price ceiling of $3.38/Mcf. These collars were in place during the months of April through October 2000. During this period, if the index rose above the ceiling price, the Company paid the counterparty. If the applicable index fell below the floor price, the counterparty paid the Company. These collars covered a total quantity of 9,909 Mmcf, or 16% of our annual production. In April and May 2000, the index prices all fell within the price collar and no settlements were made. In June 2000, all of the indexes rose above the ceiling prices and remained above the ceiling for the duration of the transaction resulting in a $10 million reduction to the Company's realized revenue for the year. If these hedges had not been in place, the average realized natural gas price for 2000 would have been $0.17 per Mcf higher. There were no commodity price collar arrangements in place during 1999. 56 As of December 31, 2000, the Company had open natural gas costless price collar arrangements on its production as follows: Natural Gas Price Collars ------------------------------------------- Volume Weighted Unrealized in Average Gain/(Loss) Contract Period Mmcf Ceiling / Floor (in $ millions) --------------------------------------------------------------------------------------------- As of December 31, 2000 ----------------------- Natural Gas Costless Collar on Production in: -------------------------------------------- First Quarter of 2001 5,274 $9.68/$5.59 -- Second Quarter of 2001 8,135 $9.68/$5.59 -- Third Quarter of 2001 8,224 $9.68/$5.59 -- Fourth Quarter of 2001 2,771 $9.68/$5.59 -- The natural gas price hedges, noted above, include costless price collar agreements based on eight price indexes at which the Company sells a portion of its production. These hedges are in place for the months of February through October 2001 and cover approximately half of the Company's natural gas production during this period. Hedges on Brokered Transactions The Company uses price swaps to hedge the natural gas price risk on brokered transactions. Typically, the Company enters into contracts to broker natural gas at a variable price based on the market index price. However, in some circumstances, some customers or suppliers request that a fixed price be stated in the contract. After entering into these fixed price contracts to meet the needs of the customers or suppliers, the Company may use price swaps to effectively convert these fixed price contracts to market-sensitive price contracts. These price swaps are held by the Company to their maturity and are not held for trading purposes. During 2000, 1999, and 1998, the Company entered into price swaps with total notional quantities of 1,295, 3,572, and 1,971 Mmcf, respectively, related to its brokered activities, representing 3%, 7%, and 5%, respectively, of its total volume of brokered natural gas sold. As of the years ending December 31, 2000, and 1999, the Company had open natural gas price swap contracts on brokered transactions as follows: Natural Gas Price Swaps -------------------------------------------- Volume Weighted Unrealized in Average Gain/(Loss) Contract Period Mmcf Contract Price (in $ millions) ------------------------------------------------------------------------------------------------------- As of December 31, 2000 ----------------------- None As of December 31, 1999 ----------------------- Natural Gas Price Swap on Brokered Transactions in: -------------------------------------------------- First Quarter 2000 1,010 $2.26 $(0.2) Financial derivatives related to natural gas reduced revenues by less than $0.1 million in 2000 and increased revenues by $0.1 million in 1999. The Company is exposed to market risk on these open contracts, to the extent of changes in market prices of natural gas and oil. However, the market risk exposure on these hedged contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity that is hedged. Since its issuance, the Company has been modeling the impact of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133). The Company had two types of hedges in place as of January 1, 2001 when SFAS 133 and SFAS 138 became effective. The first type is a cash flow hedge that fixes the price of a certain monthly quantity of natural gas sold in the Gulf Coast region through September 2003. Based on the current index price strip, the impact of this hedge on January 1, 2001 57 was to record a Hedge Loss of $0.1 million and a charge to Other Comprehensive Income of $4.2 million. Correspondingly, a Hedge Liability for $4.3 million was established. The second type of hedge is a natural gas costless price collar. The Company entered into eight of these collars for a portion of our production at regional indexes for the months of February through October 2001. The collars have two components of value: intrinsic value and time value. Under SFAS 133, both components will be valued at the end of each reporting period. Intrinsic value arises when the index price is either above the ceiling or below the floor for any period covered by the collar. If the index is above the ceiling for any month covered by the collar, the intrinsic value would be the difference between the index and the ceiling prices multiplied by the notional volume. Similar to the current accounting treatment, intrinsic value related to the current month would be recorded as a hedge loss (if the index is above the ceiling) or gain (if the index is below the floor). Starting in 2001 under SFAS 133, any changes in the intrinsic value component related to future months will be recorded in Other Comprehensive Income, a component of equity, rather than to the income statement to the extent that the hedge is proven to be effective. In the case of these natural gas price collars, full effectiveness is anticipated as they are tied to the same indexes at which our natural gas is sold. Also new under SFAS 133, the time value component, a market premium/discount, is marked-to- market through the income statement each period. Since these collar arrangements were executed on the last business day of 2000, the net premium value at adoption on January 1, 2001 is zero. Credit Risk Although notional contract amounts are used to express the volume of natural gas price agreements, the amounts that can be subject to credit risk in the event of non-performance by third parties are substantially smaller. The Company does not anticipate any material impact on its financial results due to non-performance by the third parties. The Company had no sales to any customer that exceeded 10% of total gross revenues in 2000 or 1999. 12. Oil and Gas Property Transactions In September and December 1999, the Company purchased oil and gas producing properties in the Moxa Arch of the Green River Basin in southwest Wyoming for $8.9 and $8.5 million, respectively. The assets included approximately 16 Bcfe of proved reserves, approximately 43,000 undeveloped net acres, and 27 wells producing a net 3.8 Mmcfe per day at the time of the acquisition. Also in September 1999, the Company sold non-strategic oil and gas properties located in Pennsylvania and West Virginia to EnerVest for approximately $46 million. These properties represented 716 wells and 62.2 Bcfe of proved reserves. A portion of this transaction and the two previously mentioned were completed as a tax-deferred exchange deferring a taxable gain of $8.9 million. In the second quarter of 1999, the Company sold certain non-strategic properties in the Gulf Coast region's Provident City field. These properties were producing 3.5 Mmcfe per day from eight wells. The sales price was $9 million, and the transaction contributed to a gain of approximately $1.0 million on the Company's second quarter income statement. Effective December 1, 1998, the Company purchased onshore southern Louisiana properties and 3-D seismic inventory from Oryx Energy Company for approximately $70.1 million. The purchased assets included 10 fields covering over 34,000 net acres with 68 producing wells. Total proved reserves are approximately 72 Bcfe. This transaction was funded by the Company's revolving line of credit. See discussion in Note 5 Debt and Credit Agreements. In the fourth quarter of 1998, the Company purchased oil and gas producing properties in the Lookout Wash Unit of Wyoming from Oxy USA, Inc. for $5.2 million. The properties acquired included 11.2 Bcfe of proved reserves and more than 10 potential drilling locations. Additionally in 1998, the Company acquired oil and gas producing properties in Oklahoma during the second quarter for $6.6 million. Included in the purchase were 9.3 Bcfe of proved reserves, 10 wells and undeveloped acreage. 58 13. Other Revenue During 2000, the Company reached settlements on certain natural gas contract disputes with various counterparties. As a result, the Company recorded net revenue of approximately $2.3 million to Other Revenue during 2000. The Company had a 15-year cogeneration contract under which approximately 20% of the Western region natural gas was sold per year. The contract was due to expire in 2008, but during 1999 the Company reached an agreement with the counterparty under which the counterparty bought out the remainder of the contract for $12 million. This transaction was completed in December 1999, adding $12 million of pre-tax other revenue. Simultaneously, the Company sold forward a similar monthly volume of Western region gas through April 2001 at prices similar to those in the monetized contract. Other revenue includes income generated from the monetization of the value of Section 29 tax credits (monetized credits) from most of our qualifying Appalachian and Rocky Mountains properties. Revenue from these monetized credits was $2.2 million in 2000, $1.3 million in 1999, and $2.7 million in 1998. These monetized credits are expected to generate future revenues through 2002 of $4.1 million. The production, revenues, expenses and proved reserves for these properties will continue to be reported by the Company as Other Revenue until the production payment is satisfied. During 1999, an industry tax court ruling concluded that the Section 29 tight sands tax credits (Section 29 credits) would not be available on wells not certified by the FERC. Because the FERC discontinued the certification process for qualifying wells in 1992, there was no avenue to obtain the well certifications. Accordingly, the Company stopped recording revenue on non- certified wells and established a reserve related to previously recorded amounts on these wells. This resulted in a $1.2 million reduction to other revenue in 1999. Subsequent to 1999, the certification process has been reinstated by FERC, and the Company has begun applying for the well certificates and accruing Section 29 credit revenues related to these wells. 14. Supplemental Full Cost Accounting Information U.S. oil and gas producing entities may utilize one of two methods of financial accounting: successful efforts or full cost. Given the current composition of the Company's properties, management considers the successful efforts method to be more appropriate than the full cost method primarily because the successful efforts method results in moderately better matching of costs and revenues. It has come to management's attention that certain users of the Company's financial statements believe that information about the Company prepared under the full cost method would also be useful. As a result, the following supplemental full cost information is also included. Successful efforts methodology is explained in Note 1 Summary of Significant Accounting Policies. Under the full cost method of accounting, all costs incurred in the acquisition, exploration and development of oil and gas properties are capitalized. These capitalized costs and estimated future development and dismantlement costs are amortized on a units-of-production method based on proved reserves. Net capitalized costs of oil and gas properties are limited to the lower of unamortized cost or the cost center ceiling, defined as the following: . The present value (10% discount rate) of estimated unescalated future net revenues from proved reserves, plus . The cost of properties not being amortized, plus . The lower of cost or estimated fair value of unproved properties included in the costs being amortized, minus . The deferred tax liabilities for the temporary differences between the book and tax basis of oil and gas properties. Proceeds from the sale of oil and gas properties are applied to reduce the costs in the cost center unless the sale involves a significant quantity of reserves in relation to the cost center. In this case, a gain or loss is recognized. Unevaluated properties and associated costs not currently being amortized and included in oil and gas properties 59 totaled $31.8 million, $32.3 million, and $42.4 million at December 31, 2000, 1999, and 1998, respectively. Because of the capital cost limitations described above, full cost entities are not subject to the impairment test prescribed by SFAS 121. The full cost method of accounting allows for the capitalization of certain general and administrative, region office and interest expense. Pre-tax capitalizable administrative expenses were $5.0 million in 2000, $4.6 million in 1999, and $4.6 million in 1998. Pre-tax capitalizable interest expense was $2.4 million in 2000, $2.7 million in 1999, and $2.0 million in 1998. 2000 1999 1998 --------------------------------------------------------------------- Successful Full Successful Full Successful Full (In thousands, except per share amounts) Efforts Cost Efforts Cost Efforts Cost - ----------------------------------------------------------------------------------------------------------------- Balance Sheet Properties and Equipment, Net $623,174 $834,877 $590,301 $782,156 $629,907 $816,759 Stockholders' Equity 242,505 372,702 186,496 304,487 182,668 297,583 Debt to Capitalization Ratio 52.6% 41.9% 61.1% 49.0% 65.2% 53.5% Income Statement Depreciation, Depletion, Amortization and Unproved Property Impairment $ 66,952 $ 67,002 $ 64,354 $ 66,891 $ 45,588 $ 60,165 Net Income Available to Common Stockholders 29,221 41,427 5,117 8,194 1,902 4,676 Basic Earnings Per Share $ 1.07 $ 1.51 $ 0.21 $ 0.33 $ 0.08 $ 0.19 15. Earnings per Common Share Full year basic earnings per share for the Company were $1.07, $0.21, and $0.08 in 2000, 1999, and 1998, respectively, and were based on the weighted average shares outstanding of 27,383,848 in 2000, 24,726,030 in 1999, and 24,733,465 in 1998. Diluted earnings per share for the Company were $1.06, $0.21, and $0.08 in 2000, 1999, and 1998, respectively. The diluted earnings per share amounts are based on weighted average shares outstanding plus common stock equivalents. Common stock equivalents include stock awards and stock options, and totaled 281,210 in 2000, 225,177 in 1999, and 372,937 in 1998. Both the $3.125 cumulative convertible preferred stock and the 6% convertible redeemable 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 when it was issued. As such, no adjustments were made to net income in the computation of earnings per share for 1999 or 1998. No preferred stock was outstanding at the end of 2000. See Note 10 Capital Stock for further discussion. 60 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. As a result, 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 subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the 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 in effect when the estimates were made. Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made. Estimates of proved and proved developed reserves at December 31, 2000, 1999, and 1998 were based on studies performed by the Company's petroleum engineering staff. The estimates were reviewed by Miller and Lents, Ltd., who indicated in their letter dated February 8, 2001, that based on their investigation and subject to the limitations described in their letter, they believe the results of those estimates and projections were reasonable in the aggregate. No major discovery or other favorable or unfavorable event after December 31, 2000, is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date. The following table illustrates the Company's net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by the Company's engineering staff. All reserves are located in the United States. Natural Gas --------------------------- December 31, (Millions of cubic feet) 2000 1999 1998 - --------------------------------------------------------------------------- Proved Reserves Beginning of Year 929,602 996,756 903,429 Revisions of Prior Estimates (14,796) (1,555) (13,097) Extensions, Discoveries and Other Additions 103,600 52,781 94,891 Production (60,934) (65,502) (64,167) Purchases of Reserves in Place 5,118 26,515 76,234 Sales of Reserves in Place (3,368) (79,393) (534) --------------------------- End of Year 959,222 929,602 996,756 =========================== Proved Developed Reserves 754,962 720,670 788,390 =========================== Percentage of Reserves Developed 78.7% 77.5% 79.1% =========================== 61 Liquids ---------------------- December 31, (Thousands of barrels) 2000 1999 1998 ------------------------------------------------------------------------ Proved Reserves Beginning of Year 8,189 7,677 5,869 Revisions of Prior Estimates 562 128 (1,644) Extensions, Discoveries and Other Additions 2,032 1,292 835 Production (988) (963) (736) Purchases of Reserves in Place 120 362 3,353 Sales of Reserves in Place (1) (307) -- ---------------------- End of Year 9,914 8,189 7,677 ====================== Proved Developed Reserves 8,438 5,546 5,822 ====================== Percentage of Reserves Developed 85.1% 67.7% 75.8% ====================== Capitalized Costs Relating to Oil and Gas Producing Activities The following table illustrates the total amount of capitalized costs relating to natural gas and crude oil producing activities and the total amount of related accumulated depreciation, depletion and amortization. Year Ended December 31, (In thousands) 2000 1999 1998 -------------------------------------------------------------------------- Aggregate Capitalized Costs Relating to Oil and Gas Producing Activities $1,180,692 $1,088,640 $1,107,877 Aggregate Accumulated Depreciation, Depletion and Amortization $ 558,463 $ 499,201 $ 478,766 Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities Costs incurred in property acquisition, exploration and development activities were as follows: Year Ended December 31, (In thousands) 2000 1999 1998 ------------------------------------------------------------------- Property Acquisition Costs, Proved $ 5,954 $18,395 $ 83,584 Property Acquisition Costs, Unproved 10,869 7,163 15,587 Exploration and Extension Well Costs 40,008 16,117 36,310 Development Costs 59,879 39,239 82,235 --------------------------- Total Costs $116,710 $80,914 $217,716 =========================== 62 Historical Results of Operations from Oil and Gas Producing Activities The results of operations for the Company's oil and gas producing activities were as follows: Year Ended December 31, (In thousands) 2000 1999 1998 - ------------------------------------------------------------------------------ Operating Revenues $214,116 $156,018 $147,856 Costs and Expenses Production 46,721 41,942 38,802 Other Operating 17,249 17,009 20,070 Exploration /(1)/ 19,858 11,490 19,564 Depreciation, Depletion and Amortization 63,200 62,446 43,127 ---------------------------- Total Costs and Expenses 147,028 132,887 121,563 ---------------------------- Income Before Income Taxes 67,088 23,131 26,293 Provision for Income Taxes 23,481 8,096 9,203 ---------------------------- Results of Operations $ 43,607 $ 15,035 $ 17,090 ============================ --------------------------------------------------------------------------- /(1)/ Includes administrative exploration costs of $8,442, $5,633, and $6,223 for the years ended December 31, 2000, 1999, and 1998, respectively. These costs are excluded from the Company's calculation of finding costs. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves The following information has been developed utilizing SFAS 69 procedures and based on natural gas and crude oil reserve and production volumes estimated by the Company's engineering staff. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company. The Company believes that the following factors should be taken into account when reviewing the following information: . Future costs and selling prices will probably differ from those required to be used in these calculations. . Due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations. . Selection of a 10% discount rate is arbitrary and may not be a reasonable measure of the relative risk that is part of realizing future net oil and gas revenues. . Future net revenues may be subject to different rates of income taxation. Under the Standardized Measure, future cash inflows were estimated by applying year-end oil and gas prices adjusted for fixed and determinable escalations to the estimated future production of year-end proved reserves. The average prices related to proved reserves at December 31, 2000, 1999, and 1998 for natural gas ($ per Mcf) were $9.63, $2.36, and $2.26, respectively, and for oil ($ per Bbl) were $26.18, $24.15, and $10.23, respectively. Future cash inflows were reduced by estimated future development and production costs based on year-end costs to arrive at net cash flow before tax. Future income tax expense was computed by applying year-end statutory tax rates to future pretax net cash flows, less the tax basis of the properties involved. SFAS 69 requires the use of a 10% discount rate. 63 Management does not use only the following information when making investment and operating decisions. These decisions are based on a number of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions considered more representative of a range of anticipated economic conditions. Standardized Measure is as follows: Year Ended December 31, (In thousands) 2000 /(1)/ 1999 /(1)/ 1998 /(1)/ ------------------------------------------------------------------------------------ Future Cash Inflows $ 9,497,181 $ 2,401,349 $ 2,382,860 Future Production and Development Costs (1,628,382) (786,402) (780,705) --------------------------------------- Future Net Cash Flows Before Income Taxes 7,868,799 1,614,947 1,602,155 10% Annual Discount for Estimated Timing of Cash Flows (4,332,551) (877,129) (863,226) --------------------------------------- Standardized Measure of Discounted Future Net Cash Flows Before Income Taxes 3,536,248 737,818 738,929 Future Income Tax Expenses, Net of 10% Annual Discount /(2)/ (1,126,416) (150,261) (144,851) --------------------------------------- Standardized Measure of Discounted Future Net Cash Flows $ 2,409,832 $ 587,557 $ 594,078 ======================================= --------------------------------------------------------------------------- /(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 13 of the Notes to the Consolidated Financial Statements. /(2)/ Future income taxes before discount were $2,642,810, $457,256, and $446,980 for the years ended December 31, 2000, 1999, and 1998, respectively. Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves The following is an analysis of the changes in the Standardized Measure: Year Ended December 31, (In thousands) 2000 1999 1998 ------------------------------------------------------------------------------------- Beginning of Year $ 587,557 $ 594,078 $ 610,965 Discoveries and Extensions, Net of Related Future Costs 486,236 65,210 72,275 Net Changes in Prices and Production Costs /(1)/ 2,441,921 1,354 (195,529) Accretion of Discount 73,782 73,893 83,876 Revisions of Previous Quantity Estimates, Timing and Other (81,093) (20,162) (36,547) Development Costs Incurred 28,540 19,586 20,236 Sales and Transfers, Net of Production Costs (167,395) (114,076) (109,054) Net Purchases (Sales) of Reserves in Place 16,440 (26,916) 64,911 Net Change in Income Taxes (976,156) (5,410) 82,945 ---------------------------------- End of Year $2,409,832 $ 587,557 $ 594,078 ================================== /(1)/ For 2000, the prices for natural gas used in this calculation were regional cash price quotes on the last day of the year. These prices were higher than the Company actually realized in December 2000. Further, based on market conditions in February 2001, the prices are not indicative of those that the Company expects to realize consistently in the future. If reserves had been valued at a $4.00/Mcf price (which is close to the Henry Hub average for 2000) using the same year-end regional basis differentials, total proved reserves would still be above the 1 Tcfe mark with a resulting standardized measure of discounted future net cash flows before income taxes of $1.3 billion. 64 CABOT OIL & GAS CORPORATION SELECTED DATA (UNAUDITED) QUARTERLY FINANCIAL INFORMATION (UNAUDITED) (In thousands, except per share amounts) First Second Third Fourth Total - ------------------------------------------------------------------------------------------ 2000 Operating Revenues $85,120 $82,447 $86,237 $114,847 $368,651 Impairment of Long-Lived Assets -- 9,143 -- -- 9,143 Operating Income 14,773 420 15,799 33,825 64,817 Net Income 4,494 1,518 6,137 17,072 29,221 Basic Earnings Per Share $ 0.18 $ 0.05 $ 0.21 $ 0.59 $ 1.07 Diluted Earnings Per Share $ 0.18 $ 0.05 $ 0.21 $ 0.58 $ 1.06 1999 Operating Revenues $59,046 $61,634 $78,078 $ 95,279 $294,037 Impairment of Long-Lived Assets -- -- -- 7,047 7,047 Operating Income 2,844 8,155 14,061 14,438 39,498 Net Income (Loss) (3,293) 110 3,679 4,621 5,117 Basic Earnings (Loss) Per Share $ (0.13) $ -- $ 0.15 $ 0.19 $ 0.21 Diluted Earnings (Loss) Per Share $ (0.13) $ -- $ 0.15 $ 0.19 $ 0.21 - ------------------------------------------------------------------------------------------ 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 under the caption "Election of Directors" in the Company's definitive Proxy Statement in connection with the 2000 annual stockholders' meeting is incorporated by reference. ITEM 11. EXECUTIVE COMPENSATION The information under the caption "Executive Compensation" in the definitive Proxy Statement is incorporated by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information under the captions "Beneficial Ownership of Over Five Percent of Common Stock" and "Beneficial Ownership of Directors and Executive Officers" in the definitive Proxy Statement is incorporated by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS None. 65 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, SCHEDULES AND REPORTS ON FORM 8-K A. INDEX 1. Consolidated Financial Statements See Index on page 35. 2. Financial Statement Schedules None. 3. Exhibits The following instruments are included as exhibits to this report. Those exhibits below incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. If no parenthetical appears after an exhibit, copies of the instrument have been included herewith. Exhibit Number Description - -------------------------------------------------------------------------------- 3.1 Certificate of Incorporation of the Company (Registration Statement No. 33-32553). 3.2 Amended and Restated Bylaws of the Company adopted February 20, 1997 (Form S-3 July 1999). 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). (b) Amendment No. 2 to the Rights Agreement dated December 8, 2000 (Form 8-K for December 21, 2000). 4.4 Certificate of Designation for 6% Convertible Redeemable Preferred Stock (Form 10-K for 1994). 4.5 Amended and Restated Credit Agreement dated as of May 30, 1995, among the Company, Morgan Guaranty Trust Company, as agent and the banks named therein. (a) Amendment No. 1 to Credit Agreement dated September 15, 1995 (Form 10-K for 1995). (b) Amendment No. 2 to Credit Agreement dated December 24, 1996 (Form 10-K for 1996). 4.6 Note Purchase Agreement dated May 11, 1990, among the Company and certain insurance companies parties thereto (Form 10-Q for the quarter ended June 30, 1990). (a) First Amendment dated June 28, 1991 (Form 10-K for 1994). (b) Second Amendment dated July 6, 1994 (Form 10-K for 1994). 4.7 Note Purchase Agreement dated November 14, 1997, among the Company and the purchasers named therein (Form 10-K for 1997). 10.1 Supplemental Executive Retirement Agreement between the Company and Charles P. Siess, Jr. (Form 10-K for 1995). 10.2 Form of Change in Control Agreement between the Company and Certain Officers (Form 10-K for 1995). 10.3 Letter Agreement dated January 11, 1990, between Morgan Guaranty Trust Company of New York and the Company (Registration Statement No. 33- 32553). 10.4 Form of Annual Target Cash Incentive Plan of the Company (Registration Statement No. 33-32553). 10.5 Form of Incentive Stock Option Plan of the Company (Registration Statement No. 33-32553). (a) First Amendment to the Incentive Stock Option Plan (Post-Effective Amendment No. 1 to S-8 dated April 26, 1993). 10.6 Form of Stock Subscription Agreement between the Company and certain executive officers and directors of the Company (Registration Statement No. 33-32553). 66 Exhibit Number Description - -------------------------------------------------------------------------------- 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 (incorporated by reference from Cabot Corporation's Schedule 13E-4, Am. No. 6, File No. 5-30636). 10.10 Savings Investment Plan & Trust Agreement of the Company (Form 10-K for 1991). (a) First Amendment to the Savings Investment Plan dated May 21, 1993 (Form S-8 dated November 1, 1993). (b) Second Amendment to the Savings Investment Plan dated May 21, 1993 (Form S-8 dated November 1, 1993). (c) First through Fifth Amendments to the Trust Agreement (Form 10-K for 1995). (d) Third through Fifth Amendments to the Savings Investment Plan (Form 10-K for 1996). 10.11 Supplemental Executive Retirement Agreements of the Company (Form 10-K for 1991). 10.12 Settlement Agreement and Mutual Release (Tax Issues) between Cabot Corporation and the Company dated July 7, 1992 (Form 10-Q for the quarter ended June 30, 1992). 10.13 Agreement of Merger dated February 25, 1994, among Washington Energy Company, Washington Energy Resources Company, the Company and COG Acquisition Company (Form 10-K for 1993). 10.14 1990 Non-employee Director Stock Option Plan of the Company (Form S-8 dated June 23, 1990). (a) First Amendment to 1990 Non-employee Director Stock Option Plan (Post-Effective Amendment No. 2 to Form S-8 dated March 7, 1994). (b) Second Amendment to 1990 Non-employee Director Stock Option Plan (Form 10-K for 1995). 10.15 Amended and Restated 1994 Long-Term Incentive Plan of the Company (Form 10-K for 1998). 10.16 Amended and Restated 1994 Non-Employee Director Stock Option Plan (Form 10-K for 1998). 10.17 Employment Agreement between the Company and Ray R. Seegmiller dated September 25, 1995 (Form 10-K for 1995). 10.18 Form of Indemnity Agreement between the Company and Certain Officers (Form 10-K for 1997). 10.19 Deferred Compensation Plan of the Company (Form 10-K for 1998). 10.20 Trust Agreement dated August 1998 between Bankers Trust Company and the Company (Form 10-K for 1998). 10.21 Lease Agreement between the Company and DNA COG, Ltd. dated April 24, 1998 (Form 10-K for 1998). 10.22 Credit Agreement dated as of December 17, 1998, between the Company and the banks named therein (Form 10-K for 1998). 10.23 Letter Agreement with Puget Sound Energy Company dated September 21, 1999 (Form 10-K for 1999). 21.1 Subsidiaries of Cabot Oil & Gas Corporation. 23.1 Consent of PricewaterhouseCoopers LLP. 23.2 Consent of Miller and Lents, Ltd. 28.1 Miller and Lents, Ltd. Review Letter dated February 8, 2001. B. Reports on Form 8-K Form 8-K Item 5. Other Events filed on December 21, 2000. 67 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 22nd of February 2001. CABOT OIL & GAS CORPORATION By: /s/ Ray R. Seegmiller ---------------------------------------- Ray R. Seegmiller Chairman of the Board, Chief Executive Officer and President Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated. Signature Title Date - -------------------------------------------------------------------------------- /s/ Ray R. Seegmiller Chairman of the Board, Chief February 22, 2001 - ----------------------- Executive Officer and President Ray R. Seegmiller (Principal Executive Officer) /s/ Scott C. Schroeder Vice President, Chief Financial February 22, 2001 - ----------------------- Officer and Treasurer Scott C. Schroeder (Principal Financial Officer) /s/ Henry C. Smyth Vice President and Controller February 22, 2001 - ----------------------- (Principal Accounting Officer) Henry C. Smyth /s/ Robert F. Bailey Director February 22, 2001 - ----------------------- Robert F. Bailey /s/ Henry O. Boswell Director February 22, 2001 - ----------------------- Henry O. Boswell /s/ John G. L. Cabot Director February 22, 2001 - ----------------------- John G. L. Cabot /s/ William R. Esler Director February 22, 2001 - ----------------------- William R. Esler /s/ C. Wayne Nance Director February 22, 2001 - ----------------------- C. Wayne Nance /s/ P. Dexter Peacock Director February 22, 2001 - ----------------------- P. Dexter Peacock 68 /s/ Charles P. Siess, Jr. Director February 22, 2001 - --------------------------- Charles P. Siess, Jr. /s/ Arthur L. Smith Director February 22, 2001 - --------------------------- Arthur L. Smith /s/ William P. Vititoe Director February 22, 2001 - --------------------------- William P. Vititoe 69