================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ---------------------- FORM 10-K (Mark One) /X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000 OR / / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _____to_____ Commission file number: 0-7062 NOBLE AFFILIATES, INC. (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER) Delaware 73-0785597 (STATE OF INCORPORATION) (I.R.S. EMPLOYER IDENTIFICATION NUMBER) 350 Glenborough Drive, Suite 100 Houston, Texas 77067 (ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE) (Registrant's telephone number, including area code) (281) 872-3100 SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: Name of Each Exchange on Title of Each Class Which Registered ------------------- ---------------- Common Stock, $3.33-1/3 par value New York Stock Exchange, Inc. Preferred Stock Purchase Rights New York Stock Exchange, Inc. 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 (or for such shorter period that the registrant was required to file such reports), 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 the 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._____ Aggregate market value of Common Stock held by nonaffiliates as of February 14, 2001: $2,414,000,000. Number of shares of Common Stock outstanding as of February 14, 2001: 56,323,961. DOCUMENT INCORPORATED BY REFERENCE Portions of the Registrant's definitive proxy statement for the 2001 Annual Meeting of Stockholders to be held on April 24, 2001, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2000, are incorporated by reference into Part III. ================================================================================

TABLE OF CONTENTS PART I. Item 1. Business.................................................................................... 1 General..................................................................................... 3 Oil and Gas................................................................................. 3 Exploration Activities.................................................................. 4 Production Activities .................................................................. 5 Acquisitions of Oil and Gas Properties, Leases and Concessions.......................... 6 Marketing............................................................................... 6 Regulations and Risks................................................................... 7 Competition............................................................................. 8 Unconsolidated Subsidiary................................................................... 8 Employees................................................................................... 9 Item 2. Properties.................................................................................. 9 Offices..................................................................................... 9 Oil and Gas................................................................................. 9 Item 3. Legal Proceedings........................................................................... 17 Item 4. Submission of Matters to a Vote of Security Holders......................................... 17 Executive Officers of the Registrant........................................................ 17 PART II. Item 5. Market for Registrant's Common Equity and Related Stockholder Matters....................... 19 Item 6. Selected Financial Data..................................................................... 21 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations....... 22 Item 7a. Quantitative and Qualitative Disclosures About Market Risk.................................. 27 Item 8. Financial Statements and Supplementary Data................................................. 30 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure........ 56 PART III. Item 10. Directors and Executive Officers of the Registrant.......................................... 57 Item 11. Executive Compensation...................................................................... 57 Item 12. Security Ownership of Certain Beneficial Owners and Management.............................. 57 Item 13. Certain Relationships and Related Transactions.............................................. 57 PART IV. Item 14. Financial Statement Schedules, Exhibits and Reports on Form 8-K............................. 57 ii

PART I ITEM 1. BUSINESS. CAUTIONARY STATEMENT FOR PURPOSES OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995 AND OTHER FEDERAL SECURITIES LAWS GENERAL. We are including the following discussion to inform our existing and potential security holders generally of some of the risks and uncertainties that can affect the Company and to take advantage of the "safe harbor" protection for forward-looking statements afforded under federal securities laws. From time to time, the Company's management or persons acting on our behalf make forward-looking statements to inform existing and potential security holders about the Company. These statements may include projections and estimates concerning the timing and success of specific projects and the Company's future (1) income, (2) oil and gas production, (3) oil and gas reserves and reserve replacement and (4) capital spending. Forward-looking statements are generally accompanied by words such as "estimate," "project," "predict," "believe," "expect," "anticipate," "plan," "goal" or other words that convey the uncertainty of future events or outcomes. Sometimes we will specifically describe a statement as being a forward-looking statement. In addition, except for the historical information contained in this Form 10-K, the matters discussed in this Form 10-K are forward-looking statements. These statements by their nature are subject to certain risks, uncertainties and assumptions and will be influenced by various factors. Should any of the assumptions underlying a forward-looking statement prove incorrect, actual results could vary materially. We believe the factors discussed below are important factors that could cause actual results to differ materially from those expressed in a forward-looking statement made herein or elsewhere by us or on our behalf. The factors listed below are not necessarily all of the important factors. Unpredictable or unknown factors not discussed herein could also have material adverse effects on actual results of matters that are the subject of forward-looking statements. We do not intend to update our description of important factors each time a potential important factor arises. We advise our stockholders that they should (1) be aware that important factors not described below could affect the accuracy of our forward-looking statements and (2) use caution and common sense when analyzing our forward-looking statements in this document or elsewhere, and all of such forward-looking statements are qualified by this cautionary statement. VOLATILITY AND LEVEL OF HYDROCARBON COMMODITY PRICES. Historically, natural gas and crude oil prices have been volatile. These prices rise and fall based on changes in market demand and changes in the political, regulatory and economic climate and other factors that affect commodities markets generally and are outside of our control. Some of our projections and estimates are based on assumptions as to the future prices of natural gas and crude oil. These price assumptions are used for planning purposes. We expect our assumptions will change over time and that actual prices in the future may differ from our estimates. Any substantial or extended decline in the actual prices of natural gas and/or crude oil could have a material adverse effect on (1) the Company's financial position and results of operations (including reduced cash flow and borrowing capacity), (2) the quantities of natural gas and crude oil reserves that we can economically produce, (3) the quantity of estimated proved reserves that may be attributed to our properties and (4) our ability to fund our capital program. PRODUCTION RATES AND RESERVE REPLACEMENT. Projecting future rates of oil and gas production is inherently imprecise. Producing oil and gas reservoirs generally have declining production rates. Production rates depend on a number of factors, including geological, geophysical and engineering factors, weather, production curtailments or restrictions, prices for natural gas and crude oil, available transportation capacity, market demand and the political, economic and regulatory climate. Another factor affecting production rates is our ability to replace depleting reservoirs with new reserves through exploration success or acquisitions. Exploration success is difficult to predict, particularly over the short term, where results can vary widely from year to year. Moreover, our ability to replace reserves over an extended period depends not only on the total volumes found, but also on the cost of finding and developing such reserves. Depending on the general price environment for natural gas and crude oil, our finding and 1

development costs may not justify the use of resources to explore for and develop such reserves. There can be no assurances as to the level or timing of success, if any, that we will be able to achieve in finding and developing or acquiring additional reserves. Acquisitions that result in successful exploration or exploitation projects require assessment of numerous factors, many of which are beyond our control. There can be no assurance that any acquisition of property interests by us will be successful and, if unsuccessful, that such failure will not have an adverse effect on our financial condition, results of operations and cash flows. RESERVE ESTIMATES. Our forward-looking statements may be predicated on our estimates of our oil and gas reserves. All of the reserve data in this Form 10-K or otherwise made by or on behalf of the Company are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. There are numerous uncertainties inherent in estimating quantities of proved natural gas and oil reserves. Projecting future rates of production and timing of future development expenditures is also inexact. Many factors beyond our control affect these estimates. In addition, the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Therefore, it is common that estimates made by different engineers will vary. The results of drilling, testing and production after the date of an estimate may also require a revision of that estimate, and these revisions may be material. As a result, reserve estimates are generally different from the quantities of oil and gas that are ultimately recovered. LAWS AND REGULATIONS. Our forward-looking statements are generally based on the assumption that the legal and regulatory environment will remain stable. Changes in the legal and/or regulatory environment could have a material adverse effect on our future results of operations and financial condition. Our ability to economically produce and sell our oil and gas production is affected and could possibly be restrained by a number of legal and regulatory factors, including federal, state and local laws and regulations in the U.S. and laws and regulations of foreign nations, affecting (1) oil and gas production, including allowable rates of production by well or proration unit, (2) taxes applicable to the Company and/or our production, (3) the amount of oil and gas available for sale, (4) the availability of adequate pipeline and other transportation and processing facilities and (5) the marketing of competitive fuels. Our operations are also subject to extensive federal, state and local laws and regulations in the U.S. and laws and regulations of foreign nations relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. These environmental laws and regulations continue to change and may become more onerous or restrictive in the future. Our forward-looking statements are generally based upon the expectation that we will not be required in the near future to expend amounts to comply with environmental laws and regulations that are material in relation to our total capital expenditures program. However, inasmuch as such laws and regulations are frequently changed, we are unable to accurately predict the ultimate cost of such compliance. DRILLING AND OPERATING RISKS. Our drilling operations are subject to various risks common in the industry, including cratering, explosions, fires and uncontrollable flows of oil, gas or well fluids. In addition, a substantial amount of our operations are currently offshore, domestically and internationally, and subject to the additional hazards of marine operations, such as loop currents, capsizing, collision and damage or loss from severe weather. Our drilling operations are also subject to the risk that no commercially productive natural gas or oil reserves will be encountered. The cost of drilling, completing and operating wells is often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including drilling conditions, pressure or irregularities in formations, equipment failures or accidents and adverse weather conditions. COMPETITION. The Company's forward-looking statements are generally based on a stable competitive environment. Competition in the oil and gas industry is intense both domestically and internationally. We actively compete for reserve acquisitions and exploration leases and licenses, as well as in the gathering and marketing of natural gas and crude oil. Our competitors include the major oil companies, independent oil and gas concerns, individual producers, natural gas and crude oil marketers and major pipeline companies, as well as participants in other industries supplying energy and fuel to industrial, commercial and individual consumers. To the extent our competitors have greater financial resources than currently available to us, we may be disadvantaged in effectively competing for certain reserves, leases and licenses. Recently announced consolidations in the industry may enhance the financial 2

resources of certain of our competitors. From time to time, the level of industry activity may result in a tight supply of labor or equipment required to operate and develop oil and gas properties. The availability of drilling rigs and other equipment, as well as the level of rates charged, may have an effect on our ability to compete and achieve success in our exploration and production activities. In marketing our production, we compete with other producers and marketers on such factors as deliverability, price, contract terms and quality of product and service. Competition for the sale of energy commodities among competing suppliers is influenced by various factors, including price, availability, technological advancements, reliability and creditworthiness. In making projections with respect to natural gas and crude oil marketing, we assume no material decrease in the availability of natural gas and crude oil for purchase. We believe that the location of our properties, our expertise in exploration, drilling and production operations, the experience of our management and the efforts and expertise of our marketing units generally enable us to compete effectively. In making projections with respect to numerous aspects of our business, we generally assume that there will be no material change in competitive conditions that would adversely affect us. GENERAL Noble Affiliates, Inc. is a Delaware corporation organized in 1969, and is principally engaged, through its subsidiaries, in the exploration, production and marketing of oil and gas. In this report, unless otherwise indicated or the context otherwise requires, the "Company" or the "Registrant" refers to Noble Affiliates, Inc. and its subsidiaries, "Samedan" refers to Samedan Oil Corporation and its subsidiaries, "EDC" refers to Energy Development Corporation and its subsidiaries, "NGM" refers to Noble Gas Marketing, Inc. and its subsidiary, and "NTI" refers to Noble Trading, Inc. Samedan's subsidiaries include EDC. In this report, quantities of oil or natural gas liquids are expressed in barrels ("BBLS"); quantities of natural gas are expressed in thousands of cubic feet ("MCF"), millions of cubic feet ("MMCF"), billions of cubic feet ("BCF"), trillions of cubic feet ("TCF") and million British Thermal Units ("MMBTU"). Equivalent units are expressed in thousand cubic feet of gas equivalents ("MCFe"), million cubic feet of gas equivalents ("MMCFe"), billion cubic feet of gas equivalents ("BCFe"), trillion cubic feet of gas equivalents ("TCFe"), converting oil to gas at one barrel of oil equaling six thousand cubic feet of gas, or barrel of oil equivalents ("BOE") converting gas to oil at six thousand cubic feet of gas to one barrel of oil. The Company's wholly-owned subsidiary, NGM, markets the majority of the Company's natural gas as well as third-party gas. The Company's wholly-owned subsidiary, NTI, markets a portion of the Company's oil as well as third-party oil. For more information regarding NGM's operations and NTI's operations, see "Item 1. Business--Oil and Gas--Marketing" of this Form 10-K. The Company has an unconsolidated subsidiary, Atlantic Methanol Capital Company ("AMCCO"), a 50 percent owned joint venture that indirectly owns 90 percent of Atlantic Methanol Production Company ("AMPCO"), which is constructing a methanol plant in Equatorial Guinea. AMCCO is accounted for using the equity method within the Registrant's wholly-owned subsidiary, Samedan of North Africa, Inc. For more information, see "Item 1. Business--Unconsolidated Subsidiary" of this Form 10-K. OIL AND GAS The Company's wholly-owned subsidiary, Samedan, directly or through various arrangements with other companies, explores for, develops and produces oil and gas hydrocarbons. Exploration activities include geophysical and geological evaluation and exploratory drilling on properties for which the Company has exploration rights. Samedan has been engaged in the exploration, production and marketing of oil and gas since 1932. Samedan has exploration, exploitation and production operations domestically and internationally. The domestic areas consist of: offshore in the Gulf of Mexico and California; the Gulf Coast Region (Louisiana, New Mexico and Texas); the Mid-Continent Region (Oklahoma and Southern Kansas); and the Rocky Mountain Region (Colorado, Montana, North Dakota, Wyoming and California). The international areas of operations include 3

Argentina, China, Ecuador, Equatorial Guinea, the Mediterranean Sea, the North Sea, and Vietnam. For more information regarding Samedan's oil and gas properties, see "Item 2. Properties--Oil and Gas" of this Form 10-K. EXPLORATION ACTIVITIES DOMESTIC OFFSHORE. Samedan has been actively engaged in exploration, exploitation and development of oil and gas properties in the Gulf of Mexico (offshore Texas, Louisiana, Mississippi and Alabama) and offshore California since 1968. Generally, offshore properties are characterized by prolific reservoirs with high production rates, which therefore tend to deplete more rapidly than the Company's onshore properties. The Company's current offshore production is derived from 232 wells operated by Samedan and 279 wells operated by others. During the past 32 years, Samedan has drilled or participated in the drilling of 992 gross wells offshore. At December 31, 2000, the Company held offshore federal leases covering 1,037,827 gross developed acres and 793,507 gross undeveloped acres on which the Company currently intends to conduct future exploration activities. For more information, see "Item 2. Properties--Oil and Gas" of this Form 10-K. DOMESTIC ONSHORE. Samedan has been actively engaged in exploration, exploitation and development of oil and gas properties in three regions since the 1930's. The Gulf Coast Region covers onshore Louisiana, New Mexico and Texas. Properties in the Gulf Coast Region are characterized by gas reservoirs with strong production rates and oil fields with primary and secondary recovery operations that tend to deplete more gradually than the Company's offshore properties. The Mid-Continent Region covers Oklahoma and Southern Kansas. Properties in the Mid-Continent Region tend to be characterized by stable oil and gas production from primary and secondary recovery operations and the reservoirs tend to produce for longer periods compared to the Company's offshore properties. The Rocky Mountain Region covers Colorado, Montana, North Dakota, Wyoming and California. Reservoirs in the Rocky Mountain Region are primarily characterized by oil and gas production from primary and secondary recovery operations. Samedan's current onshore production is derived from 1,494 wells operated by Samedan and 1,380 wells operated by others. At December 31, 2000, the Company held 604,902 gross developed acres and 289,527 gross undeveloped acres onshore on which the Company may conduct future exploration activities. For more information, see "Item 2. Properties--Oil and Gas" of this Form 10-K. ARGENTINA. Samedan, through its subsidiary EDC Argentina, Inc., has been actively engaged in exploration, exploitation and development of oil and gas properties in Argentina since 1996. The Company's producing properties are located in southern Argentina in the El Tordillo field, which is characterized by secondary recovery oil production from a 10,000 acre reservoir. At December 31, 2000, the Company held 28,988 gross developed acres and 1,235,105 gross undeveloped acres in Argentina on which the Company may conduct future exploration activities. For more information, see "Item 2. Properties--Oil and Gas" of this Form 10-K. CHINA. Samedan, through its subsidiary EDC China, Inc., has been actively engaged in exploration, exploitation and development of oil and gas properties in China since 1996. The Company has two concessions in South Bohai Bay, offshore China. These concessions, Cheng Dao Xi and Cheng Zi Kou, are contiguous and adjoin non-owned production in the southern portion of Bohai Bay. At December 31, 2000, the Company held 7,413 gross developed acres and 200,032 gross undeveloped acres in China on which the Company may conduct future exploration activities. For more information, see "Item 2. Properties--Oil and Gas" of this Form 10-K. ECUADOR. Samedan, through its subsidiary EDC Ecuador Ltd., has been actively engaged in exploration, exploitation and development of oil and gas properties in Ecuador since 1996. The Company's objective in Ecuador is to develop the gas market for the Amistad gas field (offshore Ecuador) which was discovered in the late 1970's. The concession covers 12,355 gross developed acres and 851,771 gross undeveloped acres encompassing the Amistad field. For more information, see "Item 2. Properties--Oil and Gas" of this Form 10-K. EQUATORIAL GUINEA. Samedan has been actively engaged in exploration, exploitation and development of oil and gas properties offshore Equatorial Guinea (West Africa) since 1990. The primary offshore Equatorial Guinea 4

production is from the Alba field, which produces gas and condensate. The gas production will be utilized as feedstock by a methanol plant currently under construction. The plant will be owned by AMPCO, in which the Company indirectly owns a 45 percent interest through its 50 percent ownership of AMCCO. For more information on the methanol plant, see "Item 1. Business--Unconsolidated Subsidiary" of this Form 10-K. Based on reserve estimates, the Alba field can deliver gas sufficient for the plant to operate for 30 years. At December 31, 2000, the Company held 45,203 gross developed acres and 266,754 gross undeveloped acres offshore Equatorial Guinea on which the Company may conduct future exploration activities. For more information, see "Item 2. Properties--Oil and Gas" of this Form 10-K. NORTH SEA. Samedan, through its subsidiaries EDC (Europe) Limited and EDC (Denmark) Inc., has been actively engaged in exploration, exploitation and development of oil and gas properties in the North Sea since 1996. The Company's current oil and gas production in the North Sea is derived from 142 wells operated by others. Reservoirs in the North Sea tend to have the same attributes as Gulf of Mexico reservoirs. At December 31, 2000, the Company held 131,527 gross developed acres and 682,262 gross undeveloped acres on which the Company may conduct future exploration activities. For more information, see "Item 2. Properties--Oil and Gas" of this Form 10-K. MEDITERRANEAN SEA. In 1998, the Company, through its subsidiary, Samedan, Mediterranean Sea, entered into a participation agreement with a 40 percent interest covering 11 licenses, permits or leases. At December 31, 2000, the Company held 61,776 gross developed acres and 1,020,198 gross undeveloped acres. The acreage is located about 20 miles offshore Israel in water depths ranging from 700 feet to 5,000 feet. Through a recent acquisition, the Company has increased its interest in the 11 licenses to 47 percent. For more information, see "Item 2. Properties--Oil and Gas" of this Form 10-K. VIETNAM. During 2000, Samedan acquired a 78 percent interest in two offshore blocks totaling 1,701,812 gross undeveloped acres in the Nam Con Son basin. The Company anticipates reducing its interest to 60 percent before the planned exploration wells are drilled in 2001. For more information, see "Item 2. Properties--Oil and Gas" of this Form 10-K. PRODUCTION ACTIVITIES OPERATED PROPERTY STATISTICS. The percentage of oil and gas wells operated and the percentage of sales volume from operated properties are shown in the following table as of December 31: 2000 1999 1998 ----------------------------------------------------------------------- (IN PERCENTAGES) OIL GAS OIL GAS OIL GAS - ------------------------------------------------------------------------------------------------------------------- Operated well count basis 23.1 66.0 22.8 61.2 20.7 58.9 Operated sales volume basis 48.3 64.5 48.1 59.8 45.3 59.2 NET PRODUCTION. The following table sets forth Samedan's net oil and natural gas production including royalty, for the three years ended December 31: 2000 1999 1998 - ------------------------------------------------------------------------------------------------------------------- Oil Production (million BBLS) 9.4 11.0 13.6 Gas Production (BCF) 148.7 166.1 206.8 OIL AND GAS EQUIVALENTS. The following table sets forth Samedan's net production stated in oil and gas equivalent volumes, for the three years ended December 31: 2000 1999 1998 - ----------------------------------------------------------------------------------------------------------------- Total Oil Equivalents (million BOE) 34.2 38.6 48.1 Total Gas Equivalents (BCFe) 205.4 231.8 288.3 5

ACQUISITIONS OF OIL AND GAS PROPERTIES, LEASES AND CONCESSIONS During 2000, Samedan spent approximately $99 million on the purchase of proved oil and gas properties. Samedan spent approximately $.1 million in 1999 and $48.4 million in 1998 on proved properties. For more information, see "Item 2. Properties--Oil and Gas" of this Form 10-K. During 2000, Samedan spent approximately $17.6 million on acquisitions of unproved properties. Samedan spent approximately $7.9 million in 1999 and $37.6 million in 1998 on acquisitions of unproved properties. These properties were acquired primarily through various offshore lease sales, domestic onshore lease acquisitions and international concession negotiations. For more information, see "Item 2. Properties--Oil and Gas" of this Form 10-K. MARKETING NGM seeks opportunities to enhance the value of the Company's gas by marketing directly to end users and aggregating gas to be sold to gas marketers and pipelines. During 2000, approximately 69 percent of NGM's total sales were to end users. NGM is also actively involved in the purchase and sale of gas from other producers. Such third-party gas may be purchased from non-operators who own working interests in the Company's wells or from other producers' properties in which the Company may not own an interest. NGM, through its wholly-owned subsidiary, Noble Gas Pipeline, Inc., engages in the installation, purchase and operation of gas gathering systems. Samedan and EDC have short-term gas sales contracts with NGM, whereby Samedan and EDC are paid an index price for all gas sold to NGM. Samedan and EDC sold approximately 95 percent of their production to NGM in 2000. Sales, including hedging transactions, are recorded as gathering, marketing and processing revenues. NGM records the amount paid to Samedan, EDC and third parties as cost of sales in gathering, marketing and processing. All intercompany sales and expenses are eliminated in the Company's consolidated financial statements. The Company has a small number of long-term gas contracts representing less than five percent of its total gas sales. Oil produced by the Company is sold to purchasers in the United States and foreign locations at various prices depending on the location and quality of the oil. The Company has no long-term contracts with purchasers of its oil production. Crude oil and condensate are distributed through pipelines and by trucks to gatherers, transportation companies and end users. NTI markets approximately 45 percent of the Company's oil as well as certain third-party oil. The Company records all of NTI's sales as gathering, marketing and processing revenues and records cost of sales in gathering, marketing and processing costs. All intercompany sales and expenses are eliminated in the Company's consolidated financial statements. Oil prices are affected by a variety of factors that are beyond the control of the Company. The principal factors influencing the prices received by producers of domestic crude oil continue to be the pricing and production of the members of the Organization of Petroleum Exporting Countries. The Company's average oil price increased $8.08 from $16.29 per BBL in 1999 to $24.37 per BBL in 2000. Due to the volatility of oil prices, the Company, from time to time, has used derivative hedging and may do so in the future as a means of controlling its exposure to price changes. For additional information, see "Item 7a. Quantitative and Qualitative Disclosure About Market Risk" and "Item 8. Financial Statements and Supplementary Data" of this Form 10-K. Substantial competition in the natural gas marketplace continued in 2000. Gas prices, which were once determined largely by governmental regulations, are now determined by the marketplace. The Company's average gas price increased from $2.23 per MCF in 1999 to $3.77 per MCF in 2000. Due to the volatility of gas prices, the Company, from time to time, has used derivative hedging and may do so in the future as a means of controlling its exposure to price changes. For additional information, see "Item 7a. Quantitative and Qualitative Disclosure About Market Risk" and "Item 8. Financial Statements and Supplementary Data" of this Form 10-K. The largest single non-affiliated purchaser of the Company's oil production in 2000 accounted for approximately 19 percent of the Company's oil sales, representing approximately three percent of total revenues. The five largest 6

purchasers accounted for approximately 57 percent of total oil sales. The largest single non-affiliated purchaser of the Company's gas production in 2000 accounted for approximately two percent of its gas sales. The five largest purchasers accounted for approximately eight percent of total gas sales. The Company does not believe that its loss of a major oil or gas purchaser would have a material effect on the Company. REGULATIONS AND RISKS GENERAL. Exploration for and production and sale of oil and gas are extensively regulated at the national, state and local levels. Oil and gas development and production activities are subject to various state laws and regulations (and orders of regulatory bodies pursuant thereto) governing a wide variety of matters, including allowable rates of production, prevention of waste and pollution, and protection of the environment. Laws affecting the oil and gas industry are under constant review for amendment or expansion and frequently increase the regulatory burden on companies. Numerous governmental departments and agencies are authorized by statute to issue rules and regulations binding on the oil and gas industry. Many of these governmental bodies have issued rules and regulations that are often difficult and costly to comply with, and that carry substantial penalties for failure to comply. These laws, regulations and orders may restrict the rate of oil and gas production below the rate that would otherwise exist in the absence of such laws, regulations and orders. The regulatory burden on the oil and gas industry increases its costs of doing business and consequently affects the Company's profitability. CERTAIN RISKS. In the Company's exploration operations, losses may occur before any accumulation of oil or gas is found. If oil or gas is discovered, no assurance can be given that sufficient reserves will be developed to enable the Company to recover the costs incurred in obtaining the reserves or that reserves will be developed at a rate sufficient to replace reserves currently being produced and sold. The Company's international operations are also subject to certain political, economic and other uncertainties including, among others, risk of war, expropriation, renegotiation or modification of existing contracts, taxation policies, foreign exchange restrictions, international monetary fluctuations and other hazards arising out of foreign governmental sovereignty over areas in which the Company conducts operations. ENVIRONMENTAL MATTERS. As a developer, owner and operator of oil and gas properties, the Company is subject to various federal, state, local and foreign country laws and regulations relating to the discharge of materials into, and the protection of, the environment. The unauthorized release or discharge of oil or certain other regulated substances from the Company's domestic onshore or offshore facilities could subject the Company to liability under federal laws and regulations, including the Oil Pollution Act of 1990, the Outer Continental Shelf Lands Act and the Federal Water Pollution Control Act, as amended. These laws, among others, impose liability for such a release or discharge for pollution cleanup costs, damage to natural resources and the environment, various forms of direct and indirect economic losses, civil or criminal penalties, and orders or injunctions, including those that can require the suspension or cessation of operations causing or impacting or potentially impacting such release or discharge. The liability under these laws for a substantial such release or discharge, subject to certain specified limitations on liability, may be extraordinarily large. If any pollution was caused by willful misconduct, willful negligence or gross negligence within the privity and knowledge of the Company, or was caused primarily by a violation of federal regulations, the Federal Water Pollution Control Act provides that such limitations on liability do not apply. Certain of the Company's facilities are subject to regulations that require the preparation and implementation of spill prevention control and countermeasure plans relating to the prevention of, and preparation for, the possible discharge of oil into navigable waters. The Comprehensive Environmental Response, Compensation and Liability Act, as amended ("CERCLA"), also known as "Superfund," imposes liability on certain classes of persons that generated a hazardous substance that has been released into the environment or that own or operate facilities or vessels onto or into which hazardous substances are disposed. The Resource Conservation and Recovery Act, as amended, ("RCRA") and regulations promulgated thereunder, regulate hazardous waste, including its generation, treatment, storage and disposal. CERCLA currently exempts crude oil, and RCRA currently exempts certain oil and gas exploration and production drilling materials, such as drilling fluids and produced waters, from the definitions of hazardous substance and hazardous waste, respectively. The Company's operations, however, may involve the use or handling of other 7

materials that may be classified as hazardous substances and hazardous wastes, and therefore, these statutes and regulations promulgated under them would apply to the Company's generation, handling and disposal of these materials. In addition, there can be no assurance that such exemptions will be preserved in future amendments of such acts, if any, or that more stringent laws and regulations protecting the environment will not be adopted. Certain of the Company's facilities may also be subject to other federal environmental laws and regulations, including the Clean Air Act with respect to emissions of air pollutants. Certain state or local laws or regulations and common law may impose liabilities in addition to, or restrictions more stringent than, those described herein. The environmental laws, rules and regulations of foreign countries are generally less stringent than those of the United States, and therefore, the requirements of such jurisdictions do not generally impose an additional compliance burden on the Company or on its subsidiaries. The Company has made and will continue to make expenditures in its efforts to comply with environmental requirements. The Company does not believe that it has to date expended material amounts in connection with such activities or that compliance with such requirements will have a material adverse effect upon the capital expenditures, earnings or competitive position of the Company. Although such requirements do have a substantial impact upon the energy industry, generally they do not appear to affect the Company any differently or to any greater or lesser extent than other companies in the industry. INSURANCE. The Company has various types of insurance coverages as are customary in the industry which include, in various degrees, general liability, control of well, loss of production, pollution, political risks and physical damage insurance. The Company believes the coverages and types of insurance are adequate. COMPETITION The oil and gas industry is highly competitive. Since many companies and individuals are engaged in exploring for oil and gas and acquiring oil and gas properties, a high degree of competition for desirable exploratory and producing properties exists. A number of the companies with which the Company competes are larger and have greater financial resources than the Company. The availability of a ready market for the Company's oil and gas production depends on numerous factors beyond its control, including the level of consumer demand, the extent of worldwide oil and gas production, the costs and availability of alternative fuels, the costs and proximity of pipelines and other transportation facilities, regulation by state and federal authorities and the costs of complying with applicable environmental regulations. UNCONSOLIDATED SUBSIDIARY The Company has an unconsolidated subsidiary, Atlantic Methanol Capital Company ("AMCCO"), a 50 percent owned joint venture that owns an indirect 90 percent interest in Atlantic Methanol Production Company ("AMPCO"). The Company accounts for its interest in AMCCO using the equity method within the Company's wholly-owned subsidiary, Samedan of North Africa, Inc. For more information, see "Item 8. Financial Statements and Supplementary Data" of this Form 10-K. Samedan is participating with a 50 percent expense interest (45 percent ownership net of a five percent government carried interest) to construct a methanol plant in Equatorial Guinea. The total projected cost of the plant and supporting facilities is estimated to be $448 million including various contingencies and capitalized interest, with the Company responsible for $224 million. The plant is designed to produce 2,500 metric tons of methanol per day, which equates to approximately 20,000 BBLS per day. At this level of production, the plant would use approximately 125 MMCF of gas per day from the Alba field as feedstock. Reserve estimates indicate the Alba field can deliver sufficient gas for the plant to operate 30 years. The construction contract stipulates that first production should be achieved by the second quarter of 2001. Current marketing plans are to use two tankers, which are under long-term contracts, to transport the methanol to markets in 8

Europe and the United States. During 1999, AMCCO issued $250 million senior secured notes due 2004 that are not included in the Company's balance sheet. For more information, see "Item 7. Management Discussion and Analysis of Financial Condition and Results of Operations" of this Form 10-K. EMPLOYEES During the year, the total number of employees of the Company increased from 556 at December 31, 1999, to 576 at December 31, 2000. ITEM 2. PROPERTIES. OFFICES The principal executive office of the Registrant is located in Houston, Texas. The Company maintains offices for international, domestic onshore, and domestic offshore operations in Houston, Texas. The Company also maintains offices in China, Ecuador, Israel, the United Kingdom, and Vietnam. NGM's office is located in Houston, Texas, and NTI's office is located in Ardmore, Oklahoma. The Company also maintains offices in Ardmore, Oklahoma for centralized accounting, lease records, human resources and related administrative functions. OIL AND GAS The Company, directly or through various arrangements with others, searches for potential oil and gas properties, seeks to acquire exploration rights in areas of interest and conducts exploratory activities. These activities include geophysical and geological evaluation and exploratory drilling, where appropriate, on properties for which it acquired exploration rights. During 2000, Samedan drilled or participated in the drilling of 268 gross (146 net) wells, comprised of 50 gross (11.5 net) international wells and 218 gross (134.5 net) domestic wells. For more information regarding Samedan's oil and gas properties, see "Item 1. Business--Oil and Gas" of this Form 10-K. DOMESTIC OFFSHORE. During 2000, an exploitation program at Samedan's South Timbalier field consisting of two development wells, four workovers and additional compression increased production 66 MMCF of gas per day, net to the Company's interest. Upgrades at East Cameron 331/332 have resulted in a net incremental increase in total production of nearly 20 MMCF of gas and 1,080 BBLS of oil per day. An exploitation project consisting of seven sidetracks was completed at Main Pass 306, increasing production 875 net BBLS of oil per day. The High Island A-517 A-8 and A-14 development wells commenced production of 8.2 net MMCF of gas per day each. The Vermilion 161 BJ-6 development well commenced production of 7.5 MMCF of gas and 330 BBLS of oil per day, net to Samedan's interest. Production began from the 12 block Viosca Knoll 252 Unit. Four wells were producing approximately 42 MMCF of gas per day, net to Samedan's 40 percent interest. Additional exploration and development opportunities remain. Samedan recompleted its West Delta 58 C-4 well to the OX sand. The zone contains 68 feet of hydrocarbon pay and commenced production at the rate of 9.7 MMCF of gas and 992 BBLS of condensate per day, net to Samedan's interest. 9

A workover in the Vermilion 167 field yielded a net incremental increase of 600 BBLS of oil per day. Samedan entered into an exploration alliance with McMoRan Exploration Company and committed to participate with a 25 percent working interest in six prospects. Additionally, Samedan agreed to work with McMoRan in identifying future prospects on approximately 660,000 acres previously accumulated by McMoRan. Samedan's estimated costs for the committed exploration prospects are approximately $25 million. The Vermilion 196 #2 well, in which Samedan owns a 25 percent working interest, logged 70 feet of net hydrocarbon pay in three sands. The property expansion is continuing with two development wells and initial production is expected in the third quarter of 2001. Samedan purchased an additional 13.2 percent working interest (for a total working interest of 33.2 percent) in Vermilion 408 from McMoRan Exploration Company for $2.8 million. The block contains two wells with reserves estimated to be four million BOE. DOMESTIC ONSHORE. In 2000, Samedan maintained an active drilling program in the Bowdoin field located in Phillips and Valley Counties, Montana where 95 successful wells were drilled. The Harry Stagg #1 located in Lafayette Parish, Louisiana commenced production at a rate of 5.6 MMCF of gas and 274 BBLS of condensate per day, net to the Company's interest, with 8,400 pounds per square inch of flowing tubing pressure. The Runnels #3 in Matagorda County, Texas commenced production at the daily rate of 2.6 MMCF of natural gas and 68 BBLS of oil, net to Samedan's interest. EQUATORIAL GUINEA. The expansion of the 34 percent owned Alba field has been completed with the successful drilling of the Alba #8 well. The expansion included engineering, fabrication, transportation, and installation of a tripod well platform, a four-pile 12 slot manned platform with compression, various infield flow lines, a 19-mile pipeline and the drilling of several wells, some for production and some for reinjection. The expansion will increase the production capacity of the field, which lies 18 miles off the coast of Equatorial Guinea, to 225 MMCF of gas per day from 90 MMCF of gas per day. Approximately 125 MMCF of gas per day will be supplied to a methanol plant on Bioko Island, scheduled to start production in the second quarter of 2001. Approximately 10 MMCF of gas per day will be used for onshore operations, and the remainder will be reinjected. The Company, through its 50 percent ownership interest in AMCCO, indirectly owns a 45 percent working interest in AMPCO, which is constructing a methanol plant to use gas from the Alba field. The plant is designed to produce 2,500 metric tons of methanol per day, which is the equivalent of approximately 20,000 BBLS per day. The plant is designed to use approximately 125 MMCF of gas per day and is approximately 95 percent complete. It is being built under a turnkey construction contract and projected to be completed and begin production in the second quarter of 2001. For additional information, see "Item 1. Business--Unconsolidated Subsidiary" of this Form 10-K. ECUADOR. The Company owns a 100 percent working interest in the Block 3 concession, located offshore Ecuador in the Gulf of Guayaquil. The concession includes 12,355 gross developed acres and 851,771 gross undeveloped acres encompassing the Amistad gas field. The Company constructed and set a drilling and production platform for the Amistad gas field. A platform drilling rig had drilled three wells at year end. Additional evaluation wells will be drilled in 2001. Gas from the field is targeted to supply an electrical power generation facility to be constructed near the city of Machala. The Company has made progress payments to General Electric for the construction of two units that will ultimately be capable of producing 240 megawatts of electricity when in a combined cycle configuration. ISRAEL. The Company made a gas discovery approximately 15 miles off the coast of Israel with the Mari-B #1 well. The Mari-B #2 well was drilled approximately one mile east of the Mari-B #1 discovery. A delineation well was drilled to appraise the southern extension of the nearby Noa field which was discovered in 1999. Based on the data 10

from these wells, it is estimated that the combined Noa/Mari-B areas contain recoverable reserves in excess of 1.2 TCF of gas. In late 2000, the Company increased its interest in the exploration agreement from 40 to 47 percent. The agreement covers 11 licenses, permits or leases encompassing 1,081,974 gross acres offshore Israel. The partners in the exploration agreement are currently negotiating a supply contract with Israel Electric Corporation Ltd. CHINA. In October 2000, the Chinese government granted final approval of the development plan for the Cheng Dao Xi field to the Company's wholly-owned indirect subsidiary Energy Development Corporation (China), Inc. The field is located in the southern portion of Bohai Bay. The plan includes a drilling and production platform set in approximately 25 feet of water and 16 wells to develop the field, including injection wells to maintain field pressure. The production facilities are designed to process 10,000 BBLS of oil per day. A five-mile pipeline will also be installed to connect the field to the existing onshore infrastructure located in the Shengli oil field. The total projected $101 million cost for the development and construction of the field and pipeline will be shared 57 percent by the Company and 43 percent by the China Petro-Chemical Corporation. Initial production is expected in the second quarter of 2002. VIETNAM. Oil and gas exploration rights were acquired on two blocks in the Nam Con Son basin offshore Vietnam. Samedan will be the operator with a 60 percent interest in the two blocks, which encompass 1.7 million acres. Both oil and gas have been tested on the blocks in wells drilled by previous operators, but the discoveries were not developed. Two exploratory wells are planned for 2001. NORTH SEA. EDC (Europe) Limited, a wholly-owned indirect subsidiary of the Company, acquired, through an asset exchange, a 12 percent interest in Block 21/20a in the Cook field, 100 miles east of Aberdeen, Scotland. This field commenced production of 12,000 gross BBLS of oil per day in April 2000. Recoverable reserves are estimated in excess of 20 million BBLS of oil to be produced over a span of at least five years. Interests in two licenses in the Hanze field in the Dutch sector of the North Sea were acquired. The Company owns a 15 percent interest in one license in which production is expected to start during the second half of 2001. An exploration well on the second license, in which the Company owns 40 percent, is planned in 2001. A new oil platform, currently under construction, is expected to have a production rate of approximately 31,500 BBLS of oil per day. The Hanze field would be the first oil field to come into production in the Dutch sector of the North Sea in 10 years. ARGENTINA. The Company participated with a 13 percent working interest in 38 exploitation wells in the El Tordillo field during 2000. The Company is awaiting government approval on an oil and gas exploration permit of approximately 1.2 million acres. The permit is located in the Cuyo Basin of Mendoza Province in western Argentina. The Company was the successful bidder on an adjacent permit of approximately 1.1 million acres. Seismic work should commence in 2001. 11

NET EXPLORATORY AND DEVELOPMENTAL WELLS. The following table sets forth, for each of the last three years, the number of net exploratory and development wells drilled by or on behalf of Samedan. An exploratory well is a well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. A development well, for purposes of the following table and as defined in the rules and regulations of the Securities and Exchange Commission, is a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. The number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated. Completion refers to the installation of permanent equipment for the production of oil or gas, or in the case of a dry hole, to the reporting of abandonment to the appropriate agency. NET EXPLORATORY WELLS NET DEVELOPMENT WELLS --------------------------------------------- ---------------------------------------------- PRODUCTIVE(1) DRY(2) PRODUCTIVE(1) DRY(2) --------------------------------------------- ---------------------------------------------- YEAR ENDED DECEMBER 31, U.S. INT'L U.S. INT'L U.S. INT'L U.S. INT'L - ------------------------------------------------------------------------------------------------------------------- 2000 17.86 3.94 10.59 1.00 101.89 5.99 4.17 .57 1999 6.97 2.00 6.14 .55 26.10 4.82 2.42 .01 1998 15.63 .13 15.16 .33 42.21 3.92 10.71 - ---------- (1) A productive well is an exploratory or a development well that is not a dry hole. (2) A dry hole is an exploratory or development well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. At January 31, 2001, Samedan was drilling 9 gross (4.3 net) exploratory wells and 8 gross (3.6 net) development wells. These wells are located in Oklahoma, Texas, Louisiana, Argentina, and offshore in the Gulf of Mexico, Israel, Ecuador, Equatorial Guinea, and the North Sea. These wells have objectives ranging from approximately 5,500 feet to 25,000 feet. The drilling cost to Samedan of these wells is approximately $47 million if all are dry and approximately $62 million if all are completed as producing wells. 12

OIL AND GAS WELLS. The number of productive oil and gas wells in which Samedan held an interest as of December 31, were as follows: 2000(1)(3) 1999(1)(2)(3) 1998(1)(3) --------------------------------------------------------------------------- GROSS NET GROSS NET GROSS NET - ------------------------------------------------------------------------------------------------------------------- OIL WELLS United States - Onshore 1,341.5 564.0 1,512.5 683.2 4,571.5 895.8 United States - Offshore 210.5 119.2 254.5 128.2 344.0 145.9 International 604.0 66.2 1,041.0 122.9 1,019.0 119.2 - ------------------------------------------------------------------------------------------------------------------- TOTAL 2,156.0 749.4 2,808.0 934.3 5,934.5 1,160.9 - ------------------------------------------------------------------------------------------------------------------- GAS WELLS United States - Onshore 1,532.5 947.1 1,435.5 873.9 1,608.5 944.7 United States - Offshore 300.5 133.4 406.5 150.4 410.0 152.2 International 31.0 3.5 27.0 2.5 25.0 2.0 - ------------------------------------------------------------------------------------------------------------------- TOTAL 1,864.0 1,084.0 1,869.0 1,026.8 2,043.5 1,098.9 - ------------------------------------------------------------------------------------------------------------------- (1) Productive wells are producing wells and wells capable of production. A gross well is a well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned. A net well is deemed to exist when the sum of fractional ownership working interests in gross wells equals one. The number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof. (2) During 1999, the Company sold 250 net non-strategic wells contributing to the decreased well count. (3) One or more completions in the same bore hole is counted as one well in this table. The following table summarizes multiple completions and non-producing wells as of December 31 for the years shown. Included in wells not producing are productive wells awaiting additional action, pipeline connections or shut-in for various reasons. 2000 1999 1998 ------------------------------------------------------------------------- GROSS NET GROSS NET GROSS NET - ------------------------------------------------------------------------------------------------------------------- MULTIPLE COMPLETIONS Oil 13.5 6.9 14.0 9.2 21.5 15.5 Gas 36.5 14.0 49.0 23.2 47.5 24.7 NOT PRODUCING (SHUT-IN) Oil 386.0 177.5 857.0 233.5 1,609.5 237.2 Gas 62.0 20.6 33.0 4.5 58.5 23.2 At year-end 2000, Samedan had less than two percent of its oil and gas sales volumes committed to long-term supply contracts and had no similar agreements with foreign governments or authorities in which Samedan acts as producer. Since January 1, 2000, no oil or gas reserve information has been filed with, or included in any report to any federal authority or agency other than the Securities and Exchange Commission and the Energy Information Administration ("EIA"). Samedan files Form 23, including reserve and other information, with the EIA. 13

AVERAGE SALES PRICE. The following table sets forth for each of the last three years the average sales price per unit of oil produced and per unit of natural gas produced, and the average production cost per unit. YEAR ENDED DECEMBER 31, ------------------------------------------ 2000 1999 1998 - ------------------------------------------------------------------------------------------------------------------- Average sales price per BBL of oil (1): United States $ 23.75 $16.37 $ 11.98 International $ 26.09 $16.01 $ 10.28 Combined (2) $ 24.37 $16.29 $ 11.66 Average sales price per MCF of natural gas (1): United States $ 3.90 $ 2.30 $ 2.18 International $ 2.08 $ 1.38 $ 2.13 Combined $ 3.77 $ 2.23 $ 2.18 Average production (lifting) cost per unit of oil and natural gas production, excluding depreciation (MCFe) (3): United States $ .59 $ .51 $ .50 International $ .64 $ .49 $ .66 Combined $ .59 $ .50 $ .52 (1) Net production amounts used in this calculation include royalties. (2) Reflects a reduction of $2.92 per BBL in 2000 from hedging in the United States. (3) Oil production is converted to gas equivalents (MCFe) based on one BBL of oil equals six MCF of gas. 14

[MAP OF GULF OF MEXICO OPERATIONS] SIGNIFICANT OFFSHORE UNDEVELOPED LEASE HOLDINGS (INTERESTS ROUNDED TO NEAREST WHOLE PERCENT) NET WORKING BLOCK INTEREST (%) - ------------------------- EAST BREAKS - ----------- 279 33 420* 48 421* 48 464* 48 465* 48 475* 100 510* 33 519* 100 563* 100 588* 97 589* 97 632* 97 633* 97 GREEN CANYON - ------------ 23* 50 24* 43 25* 43 27* 43 85* 50 227* 50 228* 50 303* 40 723* 100 724* 100 768* 100 WEST CAMERON - ------------ 136 40 392 100 393 100 400 100 438 100 443 100 446 100 583 100 602 100 614 25 VERMILION - --------- 195 25 207 25 232 50 278 100 280 50 283 50 285 50 286 100 300 50 312 100 349 75 353 100 360 67 361 67 365 50 377 100 394 75 GARDEN BANKS - ------------ 34 100 35 100 62 25 63 25 64 25 78 100 107 25 116 100 122 100 154 100 326* 100 751* 100 795* 100 841* 39 MAIN PASS - --------- 192 100 293 100 GALVESTON - --------- 249-L 50 250-L 50 274-L 50 275-L 50 277-L 50 340-S 50 341-S 50 349-S 50 MUSTANG ISLAND - -------------- 829 80 830 80 SOUTH MARSH ISLAND - ------------------ 38 100 62 67 63 67 64 67 65 67 70 50 104 100 167 100 179 35 180 35 185 35 186 35 195 50 MISSISSIPPI CANYON - ------------------ 524* 50 573 100 583* 50 595* 24 639* 24 661* 25 665* 50 705* 25 849* 48 SOUTH TIMBALIER - --------------- 98 50 156 67 201 100 315 30 BRAZOS - ------ 308-L 50 336-L 50 337-L 50 543 100 EWING BANK - ---------- 833* 14 834* 14 949 97 993 48 995 43 996 43 EUGENE ISLAND - ------------- 96 25 97 25 109 25 300 67 317 67 HIGH ISLAND - ----------- A-218 100 A-230 100 A-232 100 A-426 33 A-435 33 A-516 100 VIOSCA KNOLL - ------------ 344 100 697 50 820 50 908* 100 ATWATER VALLEY - -------------- 327* 39 533* 40 * Located in water deeper than 1,000 feet. 15

The developed and undeveloped acreage (including both leases and concessions) that Samedan held as of December 31, 2000, is as follows: DEVELOPED ACREAGE (1)(2) UNDEVELOPED ACREAGE (2)(3) ----------------------------- ----------------------------- LOCATION GROSS ACRES NET ACRES GROSS ACRES NET ACRES - ------------------------------------------------------------------------------------------------------------------- United States Onshore Alabama 2,396 506 California 5,330 2,258 5,229 3,523 Colorado 61,678 59,088 21,682 16,858 Kansas 92,601 53,073 20,042 11,908 Louisiana 20,864 6,387 12,841 6,373 Michigan 1,876 427 Mississippi 878 34 1,884 51 Montana 172,843 119,234 17,586 5,264 New Mexico 3,117 1,766 2,325 1,738 North Dakota 1,932 1,554 5,767 3,246 Oklahoma 141,513 54,712 46,459 15,928 South Dakota 800 131 Texas 74,268 37,893 84,294 42,298 Utah 5,160 2,433 640 500 Wyoming 24,718 11,797 65,706 42,727 - ------------------------------------------------------------------------------------------------------------------- Total United States Onshore 604,902 350,229 289,527 151,478 - ------------------------------------------------------------------------------------------------------------------- United States Offshore (Federal Waters) Alabama 80,640 39,168 25,603 17,698 California 27,314 5,151 63,884 16,310 Florida 11,520 2,304 Louisiana 654,090 275,051 411,257 247,697 Mississippi 22,411 10,141 40,320 18,056 Texas 253,372 102,313 240,923 168,414 - ------------------------------------------------------------------------------------------------------------------- Total United States Offshore (Federal Waters) 1,037,827 431,824 793,507 470,479 - ------------------------------------------------------------------------------------------------------------------- International Argentina 28,988 3,977 1,235,105 1,162,339 Australia 938,999 373,252 China 7,413 4,225 200,032 149,293 Denmark 80,902 32,361 Ecuador 12,355 12,355 851,771 851,771 Equatorial Guinea 45,203 15,727 266,754 92,808 Ireland 296,797 169,174 Israel 61,776 29,071 1,020,198 480,095 Netherlands 168,624 49,782 United Kingdom 131,527 4,539 432,736 150,057 Vietnam 1,701,812 1,327,413 - ------------------------------------------------------------------------------------------------------------------- Total International 287,262 69,894 7,193,730 4,838,345 - ------------------------------------------------------------------------------------------------------------------- TOTAL 1,929,991 851,947 8,276,764 5,460,302 - ------------------------------------------------------------------------------------------------------------------- (1) Developed acreage is acreage spaced or assignable to productive wells. (2) A gross acre is an acre in which a working interest is owned. A net acre is deemed to exist when the sum of fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof. (3) Undeveloped acreage is considered to be those leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether or not such acreage contains proved reserves. Included within undeveloped acreage are those leased acres (held by production under the terms of a lease) that are not within the spacing unit containing, or acreage assigned to, the productive well so holding such lease. 16

ITEM 3. LEGAL PROCEEDINGS. The Noble Drilling litigation disclosed in the Company's 1999 Form 10-K was settled during 2000. The Company has other lawsuits pending but does not believe the outcome of the lawsuits, individually or collectively, will materially impair the Company's financial and operational condition. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. There were no matters submitted to a vote of security holders during the fourth quarter of 2000. EXECUTIVE OFFICERS OF THE REGISTRANT The following table sets forth certain information, as of March 12, 2001, with respect to the executive officers of the Registrant. Name Age Position - ---------------------------------------------------------------------------------------------------------------- Robert Kelley (1) 55 Chairman of the Board Charles D. Davidson (2) 51 President, Chief Executive Officer, Director Alan R. Bullington (3) 49 Vice President, General Manager-International Division, Samedan Oil Corporation Robert K. Burleson (4) 43 President, Noble Gas Marketing, Inc. Dan O. Dinges (5) 47 Senior Vice President, General Manager-Offshore Division and Operating Committee Member of Samedan Oil Corporation Albert D. Hoppe (6) 56 Senior Vice President, General Counsel and Secretary of the Registrant and Operating Committee Member of Samedan Oil Corporation James L. McElvany (7) 47 Vice President-Finance and Treasurer of the Registrant and Operating Committee Member of Samedan Oil Corporation Richard A. Peneguy, Jr. (8) 50 Vice President, General Manager-Onshore Division, Samedan Oil Corporation W. A. Poillion (9) 51 Senior Vice President and Operating Committee Member of Samedan Oil Corporation Kenneth P. Wiley (10) 48 Vice President-Information Systems of the Registrant - --------------- (1) Robert Kelley served as President and Chief Executive Officer of the Registrant from August 1, 1986 until October 2000 and as Chairman of the Board since October 27, 1992. Prior to August 1986, he had served as Executive Vice President of the Registrant from January 1986. Mr. Kelley served as President and Chief Executive Officer of Samedan, positions he held since 1984. For more than five years prior thereto, Mr. Kelley served as an officer of Samedan. He has served as a director of the Company since 1986. Mr. Kelley has announced his retirement effective April 30, 2001. 17

(2) Charles D. Davidson was elected President and Chief Executive Officer of the Company on October 2, 2000. Prior to October 2000, he served as President and Chief Executive Officer of Vastar Resources, Inc. from March 1997 to September 2000 (Chairman from April 2000) and was a Vastar Director from March 1994 to September 2000. From September 1993 to March 1997, he served as a Senior Vice President of Vastar. (3) Alan R. Bullington was promoted to Vice President and General Manager, International Division of Samedan on January 1, 1998. Prior thereto, he served as Manager-International Operations and Exploration and as Manager-International Operations. Prior to his employment with Samedan in 1990, he held various management positions within the exploration and production division of Texas Eastern Transmission Company. (4) Robert K. Burleson has served as President of Noble Gas Marketing, Inc. since June 14, 1995. Prior thereto, he served as Vice President- Marketing for Noble Gas Marketing since its inception in 1994. Previous to his employment with the Company, he was employed by Reliant Energy as Director of Business Development for their interstate pipeline, Reliant Gas Transmission. (5) Dan O. Dinges was promoted to Senior Vice President and General Manager, Offshore Division of Samedan on January 1, 1998. Prior thereto, he had served as Vice President and General Manager, Offshore Division of Samedan since January 1989. Mr. Dinges has been a member of the Operating Committee of Samedan since January 31, 1995. (6) Albert D. Hoppe was elected Senior Vice President, General Counsel and Secretary of the Registrant on December 5, 2000. Prior thereto, he served as Vice President, General Counsel and Secretary of Vastar Resources, Inc. from 1994 through 2000. (7) James L. McElvany has served as Vice President-Finance and Treasurer of the Registrant since July 1, 1999. Prior to July 1999, he had served as Vice President-Controller of the Registrant since December 1997. Prior thereto, he served as Controller of the Registrant since December 1983. He has been a member of the Operating Committee of Samedan since July 1, 1999. (8) Richard A. Peneguy, Jr. was promoted to Vice President and General Manager, Onshore Division of Samedan on January 1, 2000. Prior thereto, he had served as General Manager, Onshore Division of Samedan since January 1, 1991. (9) W. A. Poillion was promoted to Senior Vice President-Production and Drilling of Samedan on January 1, 1998. Prior thereto, he had served as Vice President-Production and Drilling of Samedan since November 1990. He has been a member of the Operating Committee of Samedan since November 1, 1990. From March 1, 1985 to October 31, 1990, he served as Manager of Offshore Production and Drilling for Samedan. (10) Kenneth P. Wiley has served as Vice President-Information Systems since July 1998. Prior thereto, he served as Manager-Information Systems for Samedan since November 1994. The terms of office for the officers of the Registrant continue until their successors are chosen and qualified. With the exception of Mr. Davidson, no other officer or executive officer of the Registrant has an employment agreement with the Registrant or any of its subsidiaries. There are no family relationships between any of the Registrant's officers. 18

PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS. COMMON STOCK. The Registrant's Common Stock, $3.33 1/3 par value ("Common Stock"), is listed and traded on the New York Stock Exchange under the symbol "NBL." The declaration and payment of dividends are at the discretion of the Board of Directors of the Registrant and the amount thereof will depend on the Registrant's results of operations, financial condition, contractual restrictions, cash requirements, future prospects and other factors deemed relevant by the Board of Directors. STOCK PRICES AND DIVIDENDS BY QUARTERS. The following table sets forth, for the periods indicated, the high and low sales price per share of Common Stock on the New York Stock Exchange and quarterly dividends paid per share. DIVIDENDS HIGH LOW PER SHARE - -------------------------------------------------------------------------------------------------------------------------- 2000 - ---- First quarter $33.63 $19.19 $.04 Second quarter $42.38 $29.13 $.04 Third quarter $41.50 $28.88 $.04 Fourth quarter $48.38 $34.69 $.04 1999 - ---- First quarter $31.44 $19.25 $.04 Second quarter $35.00 $24.88 $.04 Third quarter $33.88 $27.00 $.04 Fourth quarter $29.19 $19.13 $.04 TRANSFER AGENT AND REGISTRAR. The transfer agent and registrar for the Common Stock is First Chicago Trust Company of New York, P.O. Box 2500, Jersey City, New Jersey 07303. STOCKHOLDERS' PROFILE. As of December 31, 2000, the number of holders of record of Common Stock was 1,179. The following chart indicates the common stockholders by category. SHARES DECEMBER 31, 2000 OUTSTANDING - --------------------------------------------------------------------------------------------------------------------- Individuals 472,983 Joint accounts 65,082 Fiduciaries 143,075 Institutions 2,513,538 Nominees 52,889,663 Foreign 6,521 - --------------------------------------------------------------------------------------------------------------------- Total-Excluding Treasury Shares 56,090,862 - --------------------------------------------------------------------------------------------------------------------- RECENT SALES OF UNREGISTERED SECURITIES. The Company's unconsolidated subsidiary, Atlantic Methanol Capital Company ("AMCCO"), is a 50 percent owned joint venture that indirectly owns 90 percent of Atlantic Methanol Production Company ("AMPCO"), which is constructing a methanol plant in Equatorial Guinea. On November 10, 1999, AMCCO issued $125 million of 10.875% Series A-1 Senior Secured Notes and $125 million of 8.95% Series A-2 Senior Secured Notes ("Series A-2 Notes") due 2004, which are not included in the Company's balance sheet, to fund the Company's portion of the remaining construction payments. The Company has guaranteed the payment of interest on the Series A-2 Notes. In addition, the Company established a new series of preferred stock, Series B Mandatorily Convertible Preferred Stock, par value $1.00 per share (the "Series B Preferred"). The Company issued, in a private placement pursuant to Section 4(2) of the Securities Act, 125,000 shares of the Series B Preferred to Noble Share Trust, which is a Delaware statutory business trust, in exchange for all of the beneficial ownership interests in the Noble Share Trust. 19

Noble Share Trust holds the 125,000 shares of Series B Preferred for the benefit of the holders of the Series A-2 Notes. The Series A-2 indenture trustee, and the holders of 25 percent of the outstanding principal amount of the Series A-2 Notes, would have the right to require a public offering of the Series B Preferred to generate proceeds sufficient to repay the Series A-2 Notes, upon the occurrence of certain events ("Trigger Dates"), including (i) defaults under the Indenture governing the Series A-2 Notes, (ii) a default and acceleration of the Company's debt exceeding five percent of the Company's consolidated net tangible assets, and (iii) the simultaneous occurrence of a downgrade of the Company's unsecured senior debt rating to "Ba1" or below by Moody's or "BB+" or below by Standard & Poor's and a decline in the closing price of the Company's common stock for three consecutive trading days to below $17.50. The exercise of this mandatory remarketing right is subject to certain forbearance provisions that would allow the Company the opportunity to obtain funds for the repayment of the Series A-2 Notes by alternative means for a specified period of time. The terms of the Series B Preferred, including dividend and conversion features, would be reset at the time of the remarketing, based on the recommendation of Donaldson, Lufkin & Jenrette, as Remarketing Agent, as to the terms necessary to generate proceeds to repay the Series A-2 Notes. If the Remarketing Agent is not able to complete a registered public offering of the Series B Preferred, it may under certain circumstances conduct a private placement of such stock. If it is impossible for legal reasons to remarket the Series B Preferred, the Company would be obligated to repay the Series A-2 Notes. The Series B Preferred stock would be mandatorily convertible into the Company's common stock three years after remarketing (or failed remarketing). Generally, each share of Series B Preferred would then be mandatorily convertible at the "Mandatory Conversion Rate," which is equal to the following number of shares of the Company's common stock: (a) if the Mandatory Conversion Date Market Price is greater than or equal to the Threshold Appreciation Price, the quotient of (i) $1,000 divided by (ii) the Threshold Appreciation Price; (b) if the Mandatory Conversion Date Market Price is less than the Threshold Appreciation Price but is greater than the Reset Price, the quotient of $1,000 divided by the Mandatory Conversion Date Market Price; and (c) if the Mandatory Conversion Date Market Price is less than or equal to the Reset Price, the quotient of $1,000 divided by the Reset Price. "Mandatory Conversion Date Market Price" means the average closing price per share of the Company's common stock for the 20 consecutive trading days immediately prior to, but not including, the mandatory conversion date. "Threshold Appreciation Price" means the product of (i) the Reset Price (as the same may be adjusted from time to time) and (ii) 110 percent. "Reset Price" means the higher of (i) the closing price of a share of the Company's common stock on the Trigger Date or (ii) the quotient (rounded up to the nearest cent) of $125,000,000 divided by the number, as of the Trigger Date, of the authorized but unissued shares of common stock that have not been reserved as of the Trigger Date by the Company's Board of Directors for other purposes. In addition to the mandatory conversion discussed above, each share of the Series B Preferred is generally convertible, at the option of the holder thereof at any time before the mandatory conversion date, into 36.364 shares of the Company's common stock (the "Optional Conversion Rate"); provided, however, that the Optional Conversion Rate shall adjust, as of the earlier to occur of remarketing or failed remarketing, to the quotient of (i) $1,000 divided by (ii) the Threshold Appreciation Price. 20

ITEM 6. SELECTED FINANCIAL DATA. YEAR ENDED DECEMBER 31, - --------------------------------------------------------------------------------------------------------------------------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND RATIOS) 2000 1999 1998 1997 1996 - --------------------------------------------------------------------------------------------------------------------------- REVENUES AND INCOME Revenues $1,393,591 $ 909,842 $ 911,616 $1,116,623 $ 887,203 Net cash provided by operating activities 570,334 343,100 382,010 492,473 413,707 Net income (loss) 191,597 49,461 (164,025) 99,278 83,880 PER SHARE DATA Basic earnings (loss) per share $ 3.42 $ .87 $ (2.88) $ 1.75 $ 1.63 Cash dividends $ .16 $ .16 $ .16 $ .16 $ .16 Year-end stock price $ 46.00 $ 21.44 $ 24.63 $ 35.25 $ 47.88 Basic weighted average shares outstanding 55,999 57,005 56,955 56,872 51,414 FINANCIAL POSITION (at year end) Property, plant and equipment, net: Oil and gas mineral interests, equipment and facilities $1,485,123 $1,242,370 $1,429,667 $1,546,426 $1,559,691 Total assets 1,879,280 1,420,351 1,686,080 1,852,782 1,956,938 Long-term obligations: Long-term debt, net of current portion 525,494 445,319 745,143 644,967 798,028 Deferred income taxes 117,048 83,075 106,823 144,083 108,434 Other 61,639 53,877 52,868 56,425 50,603 Shareholders' equity 849,682 683,609 642,080 812,989 720,067 Ratio of debt to book capital .38 .39 .54 .44 .54 CAPITAL EXPENDITURES Oil and gas mineral interests, equipment and facilities $ 502,430 $ 121,077 $ 445,910 $ 320,561 $ 982,499 Methanol and power projects 98,737 89,728 25,131 Other 4,430 1,410 2,733 8,499 3,485 - --------------------------------------------------------------------------------------------------------------------------- Total capital expenditures $ 605,597 $ 212,215 $ 473,774 $ 329,060 $ 985,984 - --------------------------------------------------------------------------------------------------------------------------- For additional information, see "Item 8. Financial Statements and Supplementary Data" of this Form 10-K. OPERATING STATISTICS YEAR ENDED DECEMBER 31, - --------------------------------------------------------------------------------------------------------------------------------- 2000 1999 1998 1997 1996 - --------------------------------------------------------------------------------------------------------------------------------- GAS Sales (in millions) $ 549.9 $ 359.8 $ 441.8 $ 499.4 $ 365.4 Production (MMCF per day) 406.3 455.1 566.6 565.4 469.4 Average price (per MCF) $ 3.77 $ 2.23 $ 2.18 $ 2.48 $ 2.17 OIL Sales (in millions) $ 224.2 $ 174.9 $ 154.3 $ 243.6 $ 225.2 Production (BBLS per day) 25,805 30,003 37,217 38,345 34,520 Average price (per BBL) $ 24.37 $ 16.29 $ 11.66 $ 17.86 $ 18.28 Royalty sales (in millions) $ 17.3 $ 14.0 $ 13.1 $ 18.1 $ 13.9 21

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. LIQUIDITY AND CAPITAL RESOURCES LIQUIDITY The Company's net cash provided from operations in 2000 was significantly higher than 1999 due to higher commodity prices during the second half of the year for crude oil and natural gas. The oil price received by the Company in 2000 increased 50 percent from 1999 and the gas price received by the Company increased 69 percent in 2000 over the price received in 1999. In 1999, the Company's oil price increased 40 percent and the natural gas price increased two percent compared to 1998. CASH PROVIDED FROM OPERATIONS [CHART - dollars per BOE] [CHART - dollars per share] The Company's unconsolidated subsidiary, AMCCO, is a 50 percent owned joint venture that indirectly owns 90 percent of AMPCO, which is constructing a methanol plant in Equatorial Guinea. During 1999, AMCCO issued $250 million senior secured notes due 2004 which are not included in the Company's balance sheet, to fund the remaining construction payments. The plant construction started during 1998 and commercial production is expected during the second quarter of 2001. The construction cost of the turnkey contract is $322.5 million. Other associated expenditures required to complete the project and produce marketable supplies of methanol are projected to be $125.5 million. The total cost of the methanol project is estimated to be $448 million including various contingencies and capitalized interest, with the Company responsible for $224 million. Payments are due upon the completion of specific phases of the construction. During 2000, the Company recorded costs of $72 million toward the project, including capitalized interest, and $45.6 million in construction contract payments. The Company has construction contract phase payments totaling $8.1 million due in 2001. During 2000, $512 million was spent on exploration and development projects, $72 million on the methanol project and $27 million on the Machala power project in Ecuador for total expenditures of $611 million. The 2001 exploration and development budget is approximately $700 million, including $45 million for the methanol project and $42 million on the Machala power project. The Company's current ratio (current assets divided by current liabilities) was .83:1 at December 31, 2000, compared with .76:1 at December 31, 1999. The increase in the current ratio was due primarily to an increase in cash and short-term investments along with a $17.5 million decrease in other current liabilities. The Company's cash and short-term investments increased from $2.9 million at December 31, 1999, to $23.2 million at December 31, 2000. 22

FINANCING The Company's total long-term debt, net of unamortized discount, at December 31, 2000, was $525 million compared to $445 million at December 31, 1999. The ratio of debt to book capital (defined as the Company's debt plus its equity) was 38 percent at December 31, 2000, compared with 39 percent at December 31, 1999. The Company's long-term debt is comprised of: $100 million of 7 1/4% Notes Due 2023, $250 million of 8% Senior Notes Due 2027, $100 million of 7 1/4% Senior Debentures Due 2097 and the outstanding balance of $80 million on a $300 million credit facility. Other than the $80 million due on the credit facility, there is no principal payment due on long term debt during the next five years. The Company has a $300 million credit facility which exposes the Company to the risk of earnings or cash flow loss due to changes in market interest rates. At December 31, 2000, there was $80 million borrowed against the credit facility which has a maturity date of December 24, 2002. The interest rate is based upon a Eurodollar rate plus a range of 17.5 to 50 basis points. At year-end 1999, the Company had no borrowing against this facility. On June 17, 1999, the Company entered into a new $100 million 364 day credit agreement with certain commercial lending institutions. This agreement, which is based upon a Eurodollar rate plus 37.5 to 87.5 basis points depending upon the percentage of utilization, expired in 2000 without ever having been utilized. OTHER The Company has paid quarterly cash dividends of $.04 per share since 1989, and currently anticipates it will continue to pay quarterly dividends of $.04 per share. The Company's Board of Directors authorized a repurchase of up to $50 million of the Company's common stock. As of March 1, 2001, the Company had completed 60.5 percent of the repurchase plan. The repurchase of 1,386,400 shares during 2000 at an average cost of $21.84 per share was funded from the Company's current cash flow. The Company has sold a number of non-strategic oil and gas properties over the past three years. Total amounts of oil and gas reserves associated with the 2000, 1999 and 1998 dispositions were 1.2 million BBLS of oil and 4.8 BCF of gas, 5.1 million BBLS of oil and 34.2 BCF of gas, and .2 million BBLS of oil and 2.2 BCF of gas, respectively. The Company believes the disposition of non-strategic properties furthers the goal of concentrating its efforts on strategic properties. The Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standard ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities" in June 1998. The Statement establishes accounting and reporting standards requiring every derivative instrument (including certain derivative instruments embedded in other contracts) to be recorded in the balance sheet as either an asset or liability measured at its fair value. The Statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met wherein gains and losses are reflected in shareholders' equity until the hedged item is recognized. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company formally document, designate and assess the effectiveness of transactions that receive hedge accounting. Due to the issuance of SFAS No. 137, which deferred the effective date of SFAS No. 133, the Company is required to adopt the statement for fiscal years beginning after June 15, 2000. A company may also implement the statement as of the beginning of any fiscal quarter after the statement's issuance (that is, fiscal quarters beginning June 16, 1998, and thereafter). SFAS No. 133 must be applied to (a) derivative instruments and (b) certain derivative instruments embedded in hybrid contracts that were issued, acquired, or substantively modified after December 31, 1997 (and, at the Company's election, before January 1, 1998). 23

During 2000, the FASB issued SFAS No. 138 which amends the accounting and reporting standards of SFAS No. 133 for certain derivative instruments and certain hedging activities and should be adopted concurrently with SFAS No. 133, according to its provisions and the issuance of SFAS No. 137. The normal purchases and normal sales exception may be applied to contracts that implicitly or explicitly permit net settlement and contracts that have a market mechanism to facilitate net settlement. The Company adopted SFAS Nos. 133 and 138 effective January 1, 2001. The adoption of these FASB's did not have a material impact on the Company's results of operations or financial position. RESULTS OF OPERATIONS NET INCOME AND REVENUES The Company's net income for 2000 of $191.6 million was primarily the result of a 50 percent and 69 percent increase in the average oil and gas price to $24.37 per BBL and $3.77 per MCF, respectively, compared to 1999. The impact of the increased oil price was approximately $76 million in additional oil revenues compared to 1999. The impact of the increase in the 2000 average natural gas price was approximately $229 million in additional gas revenues compared to 1999. The increase in net income for 1999 compared to 1998, is primarily due to significantly higher oil prices received during 1999 coupled with the $143 million charge for property impairments in 1998. NATURAL GAS INFORMATION Natural gas revenues increased dramatically in 2000, due to a 69 percent increase in the average price. The 69 percent increase in the average price received for the Company's 2000 gas production offset a decline of 11 percent in the average daily gas production. Gas production in both the third and fourth quarters of 2000 rose above the low experienced in the second quarter of 2000. Natural gas accounted for 71 percent of the Company's total gas and oil revenues in 2000. Gas sales and average daily production for 1999 declined despite a slight increase in the Company's average price. Revenues were down because natural gas production declined 20 percent in 1999 compared to 1998. The table below depicts daily natural gas production in MMCF by area for the last three years. 2000 1999 1998 - -------------------------------------------------------------------------------------------------------------------- Offshore 291.3 304.9 404.5 Onshore 86.9 116.9 139.4 International 28.1 33.3 22.7 - -------------------------------------------------------------------------------------------------------------------- Total 406.3 455.1 566.6 - -------------------------------------------------------------------------------------------------------------------- Natural gas production during 2000 ranged from a low of 354.2 MMCF per day in June, to a high of 438.3 MMCF per day in December. 2000 DAILY PRODUCTION BY QUARTER [CHART - MMCF] [CHART - MBBLS] 24

CRUDE OIL INFORMATION Crude oil revenues increased during 2000 due to significantly stronger oil prices. The 50 percent increase in the average price received for the Company's 2000 oil production offset a decline of 14 percent in the average daily production. Oil production in both the third and fourth quarters of 2000 rose above the low experienced in the second quarter of 2000. Crude oil accounted for 29 percent of the Company's total oil and gas revenues in 2000. Oil sales increased 40 percent and average daily production declined 19 percent in 1999, compared to 1998. The table below depicts daily oil production in BBLS by area for the last three years. 2000 1999 1998 - -------------------------------------------------------------------------------------------------------------------- Offshore 12,077 13,501 17,566 Onshore 6,942 9,901 12,505 International 6,786 6,601 7,146 - -------------------------------------------------------------------------------------------------------------------- Total 25,805 30,003 37,217 - -------------------------------------------------------------------------------------------------------------------- Crude oil production during 2000 ranged from a low of 24,019 BBLS per day in May, to a high of 27,434 BBLS per day in August. The Company's December 2000 oil production volume was 25,974 BBLS per day. HEDGING ACTIVITY The Company, through its subsidiaries, from time to time, uses various hedging arrangements in connection with anticipated crude oil and natural gas sales to minimize the impact of product price fluctuations. Such arrangements include fixed price hedges, costless collars, and other contractual arrangements. Although these hedging arrangements expose the Company to credit risk, the Company monitors the creditworthiness of its counterparties, which generally are major financial institutions, and believes that losses from nonperformance are unlikely to occur. Hedging gains and losses related to the Company's oil and gas production are recorded in oil and gas sales and royalties. For more information, see "Item 7a. Quantitative and Qualitative Disclosures About Market Risk" of this Form 10-K. COSTS AND EXPENSES Oil and gas operations expense, consisting of lease operating expense, workover expenses, production taxes and other related lifting costs increased four percent in 2000 from 1999 and decreased 22 percent in 1999 compared to 1998. Included in operations expense were workover costs of $21.1 million, $5.7 million and $6.5 million for 2000, 1999 and 1998, respectively. The workovers, which enhanced production during 2000, increased operations expense by $.10 per MCFe. Workover costs for 1999 and 1998 were held to a minimum due to low product prices. [CHART - OPERATING EXPENSES] [CHART - DD&A EXPENSES] 25

In 2000, depreciation, depletion and amortization ("DD&A") expense decreased nine percent, compared to 1999, due to lower oil and gas production volumes. This decrease reflects a 14 percent decrease in oil volumes and an 11 percent decrease in natural gas production volumes. In 1999, DD&A expense decreased 19 percent compared to 1998, resulting from lower oil and gas production volumes and a lower DD&A rate due to the impairment of operating assets in 1998. The Company provides for the cost of future liabilities related to restoration and dismantlement costs for offshore facilities. This provision is based on the Company's best estimate of such costs to be incurred in future years based on information from the Company's engineers. These estimated costs are provided through charging DD&A expense using a ratio of production divided by reserves multiplied by the estimated costs to dismantle and restore. The Company's accumulated provision for future dismantlement and restoration cost was $79.7 million at December 31, 2000, $83.0 million at December 31, 1999 and $68.8 million at December 31, 1998. Total estimated future dismantlement and restoration costs of $136.1 million are included in future production and development costs for purposes of estimating the future net revenues relating to the Company's proved reserves. Oil and gas exploration expense consists of dry hole expense, undeveloped lease amortization, abandoned assets, seismic and other miscellaneous exploration expense. The table below depicts the exploration expense for the last three years. (IN THOUSANDS) 2000 1999 1998 - -------------------------------------------------------------------------------------------------------------------- Dry hole expense $ 38,463 $ 19,204 $ 57,736 Undeveloped lease amortization 16,075 9,645 7,953 Abandoned assets 3,375 2,483 15,325 Seismic 18,738 7,797 15,754 Other 11,592 7,655 13,390 - -------------------------------------------------------------------------------------------------------------------- Total Exploration Expense $ 88,243 $ 46,784 $ 110,158 - -------------------------------------------------------------------------------------------------------------------- IMPAIRMENT OF OPERATING ASSETS The Company recorded no asset impairments under SFAS No. 121 during 2000 or 1999. In the fourth quarter of 1998, the Company recorded a $223.3 million pre-tax charge for the write-down of properties due to downward reserve revisions. The assets impaired under SFAS No. 121 were oil and gas properties maintained under the successful efforts method of accounting. The excess of the net book value over the projected discounted future net revenue of the impaired properties was charged to "Impairment of Operating Assets" expense. SELLING, GENERAL AND ADMINISTRATIVE EXPENSES ("SG&A") SG&A expenses have decreased $.6 million in 2000 compared to 1999 and $.3 million in 1999 compared to 1998. The decreases reflect the Company's effort to reduce SG&A through efficiencies and other cost reduction measures. GATHERING, MARKETING AND PROCESSING NGM markets the majority of the Company's natural gas, as well as certain third-party gas. NGM sells gas directly to end-users, gas marketers, industrial users, interstate and intrastate pipelines, and local distribution companies. NTI markets a portion of the Company's oil, as well as certain third-party oil. The Company records all of NGM's and NTI's sales and expenses as gathering, marketing and processing revenues and expenses. All intercompany sales and expenses have been eliminated in the Company's consolidated financial statements. 26

The gathering, marketing and processing revenues less expenses for both NGM and NTI are reflected in the table below. 2000 1999 1998 (IN THOUSANDS) ---------------------------- --------------------------- ---------------------------- (AMOUNTS INCLUDE INTER- COMPANY ELIMINATIONS) NTI NGM NTI NGM NTI NGM - --------------------------------------------------------------------------------------------------------------------- Revenues $ 91,204 $ 498,729 $ 62,671 $ 275,375 $ 67,075 $ 216,728 Expenses Cost of goods sold 63,005 464,600 35,974 237,475 40,293 179,931 Transportation 19,455 24,014 19,128 27,816 20,024 27,200 General and administrative 190 3,002 180 2,742 161 2,614 - --------------------------------------------------------------------------------------------------------------------- Total Expenses $ 82,650 $ 491,616 $ 55,282 $ 268,033 $ 60,478 $ 209,745 - --------------------------------------------------------------------------------------------------------------------- Gross Margin $ 8,554 $ 7,113 $ 7,389 $ 7,342 $ 6,597 $ 6,983 - --------------------------------------------------------------------------------------------------------------------- The margins for NGM on a per MMBTU basis were $.027 for 2000, $.026 for 1999 and $.049 for 1998. The increase in NGM's margin on a per MMBTU basis for 2000 compared to 1999, was due to the improvement in gas prices. The decrease in NGM's margin on a per MMBTU basis for 1999 compared to 1998, was due primarily to increased transportation expense. The margins for NTI on a per BBL basis were $1.28 for 2000, $.87 for 1999 and $.63 for 1998. The increase in NTI's margin on a per BBL basis for each of the years presented was due primarily to improved crude oil prices coupled with lower transportation costs. FUTURE TRENDS The Company expects increased oil and gas production in 2001 and 2002 compared to 2000. The increase in 2001 would be primarily due to the Cook and Hanze acquisitions, as well as the completion of the Alba field expansion and the startup of the methanol plant, which would utilize gas feedstock from the Alba field. The Amistad gas field development and Machala power project are expected to be completed and contributing to cash flow and gas production in 2002. The China field development is also projected to be completed with first oil production expected in 2002. The Company recently set its 2001 exploration and development budget at approximately $700 million. Such expenditures are planned to be funded through internally generated cash flows. The Company believes that it has the capital structure to take advantage of strategic acquisitions, as they become available, through internally generated cash flows or borrowings. Management believes that the Company is well positioned with its balanced reserves of oil and gas and downstream projects. The uncertainty of commodity prices continues to affect the oil, gas and methanol industries. The Company can not predict the extent to which its revenues will be affected by inflation, government regulation or changing prices. ITEM 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. The Company is exposed to market risk in the normal course of its business operations. Management believes that the Company is well positioned with its mix of oil and gas reserves to take advantage of future price increases that may occur. However, the uncertainty of oil and gas prices continues to impact the domestic oil and gas industry. Due to the volatility of oil and gas prices, the Company, from time to time, has used derivative hedging and may do so in the future as a means of controlling its exposure to price changes. The swap component of the contracts discussed in the following paragraphs was treated as a hedge for accounting purposes only. The Company had entered into three crude oil premium swap contracts related to its production for calendar year 2000. Two of the contracts provided for payments based on daily NYMEX settlement prices. These contracts related to 2,500 BBLS per day and 2,000 BBLS per day and had trigger prices of $21.73 per BBL and $22.45 per BBL, respectively, and both had knockout prices of $17.00 per BBL. These two contracts entitled the Company to receive settlements from the counterparties in amounts, if any, by which the settlement price for each NYMEX trading day was less than the trigger price, provided the NYMEX price was also greater than the $17.00 per BBL knockout price. If a daily settlement price was $17.00 per BBL or less, then neither party had any liability to the other for that day. If a 27

daily settlement price was above the applicable trigger price, then the Company would owe the counterparty for the excess of the settlement price over the trigger price for that day. Payment was made monthly under each of these contracts, in an amount equal to the net amount due to either party based on the sum of the daily amounts determined as described in this paragraph for that month. The third contract related to 2,500 BBLS per day and provided for payments based on monthly average NYMEX settlement prices. The contract entitled the Company to receive monthly settlements from the counterparty in an amount, if any, by which the arithmetic average of the daily NYMEX settlement prices for the month was less than the trigger price, which was $21.73 per BBL, multiplied by the number of days in the month, provided such average NYMEX price was also greater than the $17.00 per BBL knockout price. If the average NYMEX settlement price for the month was $17.00 per BBL or less, then neither party would have any liability to the other for that month. If the average NYMEX settlement price for the month was above the trigger price, then the Company would pay the counterparty an amount equal to the excess of the average settlement price over the trigger price, multiplied by the number of days in the month. The net effect of these premium swap contracts was a $2.87 per BBL reduction in the average crude oil price realized by the Company in 2000. The Company has treated the swap component of these contracts as a hedge (for accounting purposes only), at swap prices ranging from $19.40 per BBL to $20.20 per BBL, which existed at the dates it entered into these contracts. In addition, the Company has separately accounted for the premium component of these contracts by marking them to market, resulting in a gain of $2,921,000 recorded in other income for the year ended December 31, 2000. In addition to the premium swap crude oil hedging contracts, the Company had entered into crude oil costless collar hedges from January 1, 2000 to April 30, 2000 for volumes of 2,000 BBLS per day. These costless collars had a floor price ranging from $21.53 per BBL to $23.27 per BBL and a cap price ranging from $25.83 per BBL to $27.31 per BBL. These costless collar contracts entitled the Company to receive settlements from the counterparties in amounts, if any, by which the monthly average settlement price for each NYMEX trading day during a contract month was less than the floor price. If the monthly average settlement price was above the applicable cap price, then the Company would owe the counterparties for the excess of the monthly average settlement price over the applicable cap price. If the monthly average settlement price fell between the applicable floor and cap price, then neither party would have any liability to the other party for that month. Payment, if any, was made monthly under each of the contracts in an amount equal to the net amount due either party based on the volumes per day multiplied by the difference between the NYMEX average price and the cap, if the NYMEX average price exceeded the cap price, or if the NYMEX average price was less than the floor price, then the volumes per day multiplied by the difference between the floor price and the NYMEX average price. The net effect of these costless collar hedges was a $.05 per BBL reduction in the average crude oil price realized by the Company in 2000. The Company had no oil or gas hedging contracts for future production as of December 31, 2000. During 1999 and 1998, the Company had no oil or gas hedging transactions for its production. NGM, from time to time, employs hedging arrangements in connection with its purchases and sales of production. While most of NGM's purchases are made for an index-based price, NGM's customers often require prices that are either fixed or related to NYMEX. In order to establish a fixed margin and mitigate the risk of price volatility, NGM may convert a fixed or NYMEX sale to an index-based sales price (such as by purchasing an index-based futures contract obligating NGM for delivery of production). Due to the size of such transactions and certain restraints imposed by contract and by Company guidelines, as of December 31, 2000, the Company had no material market risk exposure from NGM's hedging activity. 28

The Company has a $300 million credit agreement (see Note 3 - Debt, to the Consolidated Financial Statements) which exposes the Company to the risk of earnings or cash flow loss due to changes in market interest rates. At December 31, 2000, there was $80 million borrowed against the credit facility which has a maturity date of December 24, 2002. The interest rate is based upon a Eurodollar rate plus a range of 17.5 to 50 basis points. All other Company long-term debt is fixed-rate and, therefore, does not expose the Company to the risk of earnings or cash flow loss due to changes in market interest rates. On June 17, 1999, the Company entered into a new $100 million 364 day credit agreement with certain commercial lending institutions. This agreement, which is based upon a Eurodollar rate plus 37.5 to 87.5 basis points depending upon the percentage of utilization, expired in 2000 without ever having been utilized. The Company does not invest in foreign currency derivatives. The U.S. dollar is considered the primary currency for each of the Company's international operations. Transactions that are completed in a foreign currency are translated into U.S. dollars and recorded in the financial statements. Translation gains or losses were not material in any of the periods presented and the Company does not believe it is currently exposed to any material risk of loss on this basis. Such gains or losses are included in other expense on the income statement. However, certain sales transactions are concluded in foreign currencies and the Company, therefore, is exposed to potential risk of loss based on fluctuation in exchange rates from time to time. 29

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Report of Independent Public Accountants................................................................ 31 Consolidated Balance Sheet as of December 31, 2000 and 1999............................................. 32 Consolidated Statement of Operations for each of the three years in the period ended December 31, 2000..................................................................................... 33 Consolidated Statement of Cash Flows for each of the three years in the period ended December 31, 2000..................................................................................... 34 Consolidated Statement of Shareholders' Equity for each of the three years in the period ended December 31, 2000..................................................................................... 35 Notes to Consolidated Financial Statements.............................................................. 36 Supplemental Oil and Gas Information (Unaudited)........................................................ 50 Interim Financial Information (Unaudited)............................................................... 56 All other financial statement schedules have been omitted because the required information is not present or is not present in amounts sufficient to require submission of the schedule or because the information required is included in the financial statements, including the notes thereto. 30

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Shareholders and Board of Directors of Noble Affiliates, Inc.: We have audited the accompanying consolidated balance sheet of Noble Affiliates, Inc. (a Delaware corporation) and subsidiaries as of December 31, 2000 and 1999, and the related consolidated statements of operations, shareholders' equity and cash flows for each of the three years in the period ended December 31, 2000. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Noble Affiliates, Inc. and subsidiaries as of 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. ARTHUR ANDERSEN LLP Oklahoma City, Oklahoma January 26, 2001 31

CONSOLIDATED BALANCE SHEET NOBLE AFFILIATES, INC. AND SUBSIDIARIES DECEMBER 31, - ------------------------------------------------------------------------------------------------------------------- (IN THOUSANDS, EXCEPT SHARE AMOUNTS) 2000 1999 - ------------------------------------------------------------------------------------------------------------------- ASSETS CURRENT ASSETS: Cash and short-term investments $ 23,152 $ 2,925 Accounts receivable - trade 235,843 98,794 Materials and supplies inventories 4,645 5,517 Other current assets 7,621 10,678 - ------------------------------------------------------------------------------------------------------------------- Total current assets 271,261 117,914 - ------------------------------------------------------------------------------------------------------------------- PROPERTY, PLANT AND EQUIPMENT, AT COST: Oil and gas mineral interests, equipment and facilities (successful efforts method of accounting) 3,213,223 2,786,848 Other 43,244 43,945 - ------------------------------------------------------------------------------------------------------------------- 3,256,467 2,830,793 Accumulated depreciation, depletion and amortization (1,771,344) (1,588,423) - ------------------------------------------------------------------------------------------------------------------- Total property, plant and equipment, net 1,485,123 1,242,370 - ------------------------------------------------------------------------------------------------------------------- INVESTMENT IN UNCONSOLIDATED SUBSIDIARY 74,159 15,625 - ------------------------------------------------------------------------------------------------------------------- OTHER ASSETS 48,737 44,442 - ------------------------------------------------------------------------------------------------------------------- TOTAL ASSETS $ 1,879,280 $ 1,420,351 - ------------------------------------------------------------------------------------------------------------------- LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Accounts payable - trade $ 279,379 $ 103,753 Other current liabilities 30,730 48,215 Income taxes - current 15,308 2,503 - ------------------------------------------------------------------------------------------------------------------- Total current liabilities 325,417 154,471 - ------------------------------------------------------------------------------------------------------------------- DEFERRED INCOME TAXES 117,048 83,075 - ------------------------------------------------------------------------------------------------------------------- OTHER DEFERRED CREDITS AND NONCURRENT LIABILITIES 61,639 53,877 - ------------------------------------------------------------------------------------------------------------------- LONG-TERM DEBT 525,494 445,319 - ------------------------------------------------------------------------------------------------------------------- SHAREHOLDERS' EQUITY: Preferred stock - par value $1.00; 4,000,000 shares authorized, none issued Common stock - par value $3.33 1/3; 100,000,000 shares authorized; 59,002,162 and 58,569,963 shares issued in 2000 and 1999, respectively 196,672 195,231 Capital in excess of par value 373,259 360,983 Retained earnings 325,452 142,813 - ------------------------------------------------------------------------------------------------------------------- 895,383 699,027 Less common stock in treasury at cost (December 31, 2000, 2,911,300 shares and December 31, 1999, 1,524,900 shares) (45,701) (15,418) - ------------------------------------------------------------------------------------------------------------------- Total shareholders' equity 849,682 683,609 - ------------------------------------------------------------------------------------------------------------------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 1,879,280 $ 1,420,351 - ------------------------------------------------------------------------------------------------------------------- SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. 32

CONSOLIDATED STATEMENT OF OPERATIONS NOBLE AFFILIATES, INC. AND SUBSIDIARIES YEAR ENDED DECEMBER 31, - -------------------------------------------------------------------------------------------------------------------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) 2000 1999 1998 - -------------------------------------------------------------------------------------------------------------------- REVENUES: Oil and gas sales and royalties $ 791,353 $ 548,733 $ 609,164 Gathering, marketing and processing 589,933 338,046 284,407 Other income 10,816 23,100 18,045 Income (loss) from investment in unconsolidated subsidiary 1,489 (37) - -------------------------------------------------------------------------------------------------------------------- Total Revenue 1,393,591 909,842 911,616 - -------------------------------------------------------------------------------------------------------------------- COSTS AND EXPENSES: Oil and gas exploration 88,243 46,784 110,158 Oil and gas operations 121,866 116,698 149,030 Gathering, marketing and processing 574,266 323,314 270,826 Depreciation, depletion and amortization 230,800 254,515 313,191 Impairment of operating assets 223,251 Selling, general and administrative 47,291 47,859 48,110 Interest 37,968 48,935 50,511 Interest capitalized (6,326) (5,894) (6,753) - -------------------------------------------------------------------------------------------------------------------- Total Expenses 1,094,108 832,211 1,158,324 - -------------------------------------------------------------------------------------------------------------------- INCOME (LOSS) BEFORE TAXES 299,483 77,631 (246,708) - -------------------------------------------------------------------------------------------------------------------- INCOME TAX PROVISION (BENEFIT): Current 74,616 24,508 (19,679) Deferred 33,270 3,662 (63,004) - -------------------------------------------------------------------------------------------------------------------- Total Tax Provision (Benefit) 107,886 28,170 (82,683) - -------------------------------------------------------------------------------------------------------------------- NET INCOME (LOSS $ 191,597 $ 49,461 $ (164,025) - -------------------------------------------------------------------------------------------------------------------- BASIC EARNINGS (LOSS) PER SHARE $ 3.42 $ .87 $ (2.88) - -------------------------------------------------------------------------------------------------------------------- DILUTED EARNINGS (LOSS) PER SHARE $ 3.38 $ .86 $ (2.88) - -------------------------------------------------------------------------------------------------------------------- WEIGHTED AVERAGE SHARES OUTSTANDING: Basic 55,999 57,005 56,955 Diluted 56,755 57,349 56,955 - -------------------------------------------------------------------------------------------------------------------- SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. 33

CONSOLIDATED STATEMENT OF CASH FLOWS NOBLE AFFILIATES, INC. AND SUBSIDIARIES YEAR ENDED DECEMBER 31, - ---------------------------------------------------------------------------------------------------------- (IN THOUSANDS) 2000 1999 1998 - ---------------------------------------------------------------------------------------------------------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss) $ 191,597 $ 49,461 $ (164,025) Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 230,800 254,515 313,191 Dry hole 38,463 19,204 57,736 Impairment of operating assets 223,251 Amortization of undeveloped leasehold costs, net 16,075 9,645 7,953 (Gain) loss on disposal of assets (3,799) (12,079) 15,434 Noncurrent deferred income taxes 33,973 (23,749) (37,260) (Income) loss from unconsolidated subsidiary (1,489) 37 Increase (decrease) in other deferred credits 7,762 1,011 (3,558) (Increase) decrease in other (3,747) (1,295) 12,708 Changes in working capital, not including cash: (Increase) decrease in accounts receivable (137,049) 7,719 56,154 (Increase) decrease in other current assets 3,557 16,571 (44,423) Increase (decrease) in accounts payable 198,871 (4,785) (55,025) Increase (decrease) in other current liabilities (4,680) 26,845 (126) - ---------------------------------------------------------------------------------------------------------- NET CASH PROVIDED BY OPERATING ACTIVITIES 570,334 343,100 382,010 - ---------------------------------------------------------------------------------------------------------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures (536,901) (142,124) (489,452) Investment in unconsolidated subsidiary (57,045) (51,962) (25,061) Proceeds from the transfer of our interest to unconsolidated subsidiary 61,987 Proceeds from sale of property, plant and equipment 12,608 58,137 3,412 - ---------------------------------------------------------------------------------------------------------- NET CASH USED IN INVESTING ACTIVITIES (581,338) (73,962) (511,101) - ---------------------------------------------------------------------------------------------------------- CASH FLOWS FROM FINANCING ACTIVITIES: Exercise of stock options 13,717 1,188 2,229 Cash dividends paid (8,958) (9,120) (9,113) Proceeds from bank debt 137,000 Repayment of bank debt (57,000) (300,000) Repayment of notes payable - unconsolidated subsidiary (23,245) (38,101) Proceeds from notes payable - unconsolidated subsidiary 60,720 Purchase of treasury stock (30,283) Proceeds from issuance of long-term debt 100,000 - ---------------------------------------------------------------------------------------------------------- NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES 31,231 (285,313) 93,116 - ---------------------------------------------------------------------------------------------------------- INCREASE (DECREASE) IN CASH AND SHORT-TERM CASH INVESTMENTS 20,227 (16,175) (35,975) CASH AND SHORT-TERM CASH INVESTMENTS AT BEGINNING OF YEAR 2,925 19,100 55,075 - ---------------------------------------------------------------------------------------------------------- CASH AND SHORT-TERM CASH INVESTMENTS AT END OF YEAR $ 23,152 $ 2,925 $ 19,100 - ---------------------------------------------------------------------------------------------------------- SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION: Cash paid during the year for: Interest (net of amount capitalized) $ 32,976 $ 44,845 $ 43,368 Income taxes $ 56,890 $ 30,000 $ 4,276 SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. 34

CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY NOBLE AFFILIATES, INC. AND SUBSIDIARIES CAPITAL IN TREASURY COMMON STOCK EXCESS OF STOCK AT RETAINED (IN THOUSANDS, EXCEPT SHARES ISSUED) SHARES ISSUED AMOUNT PAR VALUE COST EARNINGS - --------------------------------------------------------------------------------------------------------------------- DECEMBER 31, 1997 58,423,438 $194,743 $358,054 $(15,418) $ 275,610 - --------------------------------------------------------------------------------------------------------------------- Net Loss (164,025) Exercise of stock options 82,470 275 1,954 Cash dividends ($.16 per share) (9,113) - --------------------------------------------------------------------------------------------------------------------- DECEMBER 31, 1998 58,505,908 $195,018 $360,008 $(15,418) $ 102,472 - --------------------------------------------------------------------------------------------------------------------- Net Income 49,461 Exercise of stock options 64,055 213 975 Cash dividends ($.16 per share) (9,120) - --------------------------------------------------------------------------------------------------------------------- DECEMBER 31, 1999 58,569,963 $195,231 $360,983 $(15,418) $ 142,813 - --------------------------------------------------------------------------------------------------------------------- Net Income 191,597 Purchase of treasury stock (30,283) Exercise of stock options 432,199 1,441 12,276 Cash dividends ($.16 per share) (8,958) - --------------------------------------------------------------------------------------------------------------------- DECEMBER 31, 2000 59,002,162 $196,672 $373,259 $(45,701) $ 325,452 - --------------------------------------------------------------------------------------------------------------------- SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. 35

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLAR AMOUNTS IN TABLES, UNLESS OTHERWISE INDICATED, ARE IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES CONSOLIDATION The consolidated accounts include Noble Affiliates, Inc. (the "Company") and the consolidated accounts of its wholly-owned subsidiaries: Noble Gas Marketing, Inc. ("NGM"); Noble Trading, Inc. ("NTI"); NPM, Inc.; and Samedan Oil Corporation ("Samedan"). Listed below are consolidated entities at December 31, 2000. NOBLE AFFILIATES, INC. Noble Gas Marketing, Inc. Noble Gas Pipeline, Inc. Noble Trading, Inc. NPM, Inc. Samedan Oil Corporation Samedan of North Africa, Inc. Samedan International Machalapower Cia. Ltda. Samedan, Mediterranean Sea Samedan Transfer Sub Samedan Vietnam Limited Samedan, Mediterranean Sea, Inc. Samedan of Tunisia, Inc. Samedan Oil of Canada, Inc. Samedan Oil of Indonesia, Inc. Samedan Pipe Line Corporation Samedan Royalty Corporation Energy Development Corporation ("EDC") EDC Australia, Ltd. EDC Ecuador Ltd. EDC Ecuador Limited EDC Portugal Ltd. EDC (UK) Limited EDC (Denmark) Inc. EDC (Europe) Limited EDC (ISE) Limited EDC (Oilex) Limited Brabant Oil Limited Burnside Overseas Exploration Ltd. Energy Development Corporation (Argentina), Inc. Energy Development Corporation (China), Inc. Energy Development Corporation (HIPS), Inc. Gasdel Pipeline System Incorporated HGC, Inc. Producers Service, Inc. NATURE OF OPERATIONS The Company is an independent energy company engaged through its subsidiaries in the exploration, development, production and marketing of oil and gas. Samedan operates throughout the major basins in the United States, including the Gulf of Mexico, as well as international operations in Argentina, China, Ecuador, Equatorial Guinea, the 36

Mediterranean Sea, the North Sea, and Vietnam. The Company markets its oil and gas production through NGM, NTI and Samedan. USE OF ESTIMATES The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities. Such estimates and assumptions also affect the disclosure of contingent assets and liabilities at the date of the financial statements as well as amounts of revenues and expenses recognized during the reporting period. Of the estimates and assumptions that affect reported results, the estimate of the Company's oil and gas reserves is the most significant. FOREIGN CURRENCY TRANSLATION The U.S. dollar is considered the primary currency for each of the Company's international operations. Transactions that are completed in a foreign currency are translated into U.S. dollars and recorded in the financial statements. Translation gains or losses were not material in any of the periods presented and are included in other expense on the income statement. INVENTORIES Materials and supplies inventories, consisting principally of tubular goods and production equipment, are stated at the lower of cost or market, with cost being determined by the first-in, first-out method. PROPERTY, PLANT AND EQUIPMENT The Company accounts for its oil and gas properties under the successful efforts method of accounting. Under this method, costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells that find proved reserves and to drill and equip development wells are capitalized. Capitalized costs of producing oil and gas properties are amortized to operations by the unit-of-production method based on proved developed oil and gas reserves on a property-by-property basis as estimated by Company engineers. Estimated future restoration and abandonment costs are recorded by charges to depreciation, depletion and amortization ("DD&A") expense over the productive lives of the related properties. The Company has provided $79.7 million for such future costs classified with accumulated DD&A in the December 31, 2000 balance sheet. The total estimated future dismantlement and restoration costs of $136.1 million are included in future production and development costs for purposes of estimating the future net revenues relating to the Company's proved reserves. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized. Individually significant undeveloped oil and gas properties are periodically assessed for impairment of value and a loss is recognized at the time of impairment by providing an impairment allowance. Other undeveloped properties are amortized on a composite method based on the Company's experience of successful drilling and average holding period. Geological and geophysical costs, delay rentals and costs to drill exploratory wells which do not find proved reserves are expensed. Repairs and maintenance are charged to expense as incurred. Developed oil and gas properties and other long-lived assets are periodically assessed to determine if circumstances indicate that the carrying amount of an asset may not be recoverable. The Company performs this review of recoverability by estimating future cash flows. If the sum of the expected future cash flows is less than the carrying amount of the asset, an impairment is recognized based on the discounted amount of such cash flows. 37

INCOME TAXES The Company files a consolidated federal income tax return. Deferred income taxes are provided for temporary differences between the financial reporting and tax bases of the Company's assets and liabilities. CAPITALIZATION OF INTEREST The Company capitalizes interest costs associated with the development and construction of significant properties or projects. STATEMENT OF CASH FLOWS For purposes of reporting cash flows, cash and short-term investments include cash on hand and investments purchased with original maturities of three months or less. BASIC EARNINGS PER SHARE AND DILUTED EARNINGS PER SHARE Basic income per share of common stock has been computed on the basis of the weighted average number of shares outstanding during each period. The diluted net income per share of common stock includes the effect of outstanding stock options. The following table summarizes the calculation of basic earnings per share ("EPS") and diluted EPS components required by SFAS No. 128, as of December 31: 2000 1999 1998(1) ---------------------------- --------------------------- ---------------------------- (IN THOUSANDS INCOME SHARES INCOME SHARES INCOME SHARES EXCEPT PER SHARE AMOUNTS) (NUMERATOR) (DENOMINATOR) (NUMERATOR) (DENOMINATOR) (NUMERATOR) (DENOMINATOR) - --------------------------------------------------------------------------------------------------------------------- Net income/shares $191,597 55,999 $49,461 57,005 $(164,025) 56,955 - --------------------------------------------------------------------------------------------------------------------- BASIC EPS $3.42 $.87 $(2.88) - --------------------------------------------------------------------------------------------------------------------- Net income/shares $191,597 55,999 $49,461 57,005 $(164,025) 56,955 Effect of Diluted Securities Stock options 756 344 - --------------------------------------------------------------------------------------------------------------------- Adjusted net income and shares $191,597 56,755 $49,461 57,349 $(164,025) 56,955 - --------------------------------------------------------------------------------------------------------------------- DILUTED EPS $3.38 $.86 $(2.88) - --------------------------------------------------------------------------------------------------------------------- (1) In 1998, the diluted EPS is antidilutive as a result of the net operating loss; therefore, the basic EPS and diluted EPS are the same. REVENUE RECOGNITION AND GAS IMBALANCES Samedan and EDC have gas sales contracts with NGM, whereby Samedan and EDC are paid an index price for all gas sold to NGM. NGM records sales, including hedging transactions, as gathering, marketing and processing revenues. NGM records the amount paid to Samedan, EDC and third parties as cost of sales in gathering, marketing and processing. All intercompany sales and costs have been eliminated. The Company follows an entitlements method of accounting for its gas imbalances. Gas imbalances occur when the Company sells more or less gas than its entitled ownership percentage of total gas production. Any excess amount received above the Company's share is treated as a liability. If less than the Company's entitlement is received, the underproduction is recorded as a receivable. The Company records the noncurrent liability in Other Deferred Credits and Noncurrent Liabilities, and the current liability in Other Current Liabilities. The Company's gas imbalance liabilities were $14.2 million and $12.0 million for 2000 and 1999, respectively. The Company records the noncurrent receivable in Other Assets, and the current receivable in Other Current Assets. The Company's gas imbalance receivables were $18.5 million and $17.9 million for 2000 and 1999, respectively, and are valued at the amount which is expected to be received. 38

TAKE-OR-PAY SETTLEMENTS The Company records gas contract settlements which are not subject to recoupment in Other Income when the settlement is received. TRADING AND HEDGING ACTIVITIES The Company, through its subsidiaries, from time to time, uses various hedging arrangements in connection with anticipated crude oil and natural gas sales to minimize the impact of product price fluctuations. Such arrangements include fixed price hedges, costless collars, and other contractual arrangements. Although these hedging arrangements expose the Company to credit risk, the Company monitors the creditworthiness of its counterparties, which generally are major financial institutions, and believes that losses from nonperformance are unlikely to occur. Hedging gains and losses related to the Company's oil and gas production are recorded in oil and gas sales and royalties. The swap component of the contracts discussed in the following paragraphs was treated as a hedge for accounting purposes only. The Company had entered into three crude oil premium swap contracts related to its production for calendar year 2000. Two of the contracts provided for payments based on daily NYMEX settlement prices. These contracts related to 2,500 BBLS per day and 2,000 BBLS per day and had trigger prices of $21.73 per BBL and $22.45 per BBL, respectively, and both had knockout prices of $17.00 per BBL. These two contracts entitled the Company to receive settlements from the counterparties in amounts, if any, by which the settlement price for each NYMEX trading day was less than the trigger price, provided the NYMEX price was also greater than the $17.00 per BBL knockout price. If a daily settlement price was $17.00 per BBL or less, then neither party had any liability to the other for that day. If a daily settlement price was above the applicable trigger price, then the Company would owe the counterparty for the excess of the settlement price over the trigger price for that day. Payment was made monthly under each of these contracts, in an amount equal to the net amount due to either party based on the sum of the daily amounts determined as described in this paragraph for that month. The third contract related to 2,500 BBLS per day and provided for payments based on monthly average NYMEX settlement prices. The contract entitled the Company to receive monthly settlements from the counterparty in an amount, if any, by which the arithmetic average of the daily NYMEX settlement prices for the month was less than the trigger price, which was $21.73 per BBL, multiplied by the number of days in the month, provided such average NYMEX price was also greater than the $17.00 per BBL knockout price. If the average NYMEX settlement price for the month was $17.00 per BBL or less, then neither party would have any liability to the other for that month. If the average NYMEX settlement price for the month was above the trigger price, then the Company would pay the counterparty an amount equal to the excess of the average settlement price over the trigger price, multiplied by the number of days in the month. The net effect of these premium swap contracts was a $2.87 per BBL reduction in the average crude oil price realized by the Company in 2000. The Company has treated the swap component of these contracts as a hedge (for accounting purposes only), at swap prices ranging from $19.40 per BBL to $20.20 per BBL, which existed at the dates it entered into these contracts. In addition, the Company has separately accounted for the premium component of these contracts by marking them to market, resulting in a gain of $2,921,000 recorded in other income for the year ended December 31, 2000. In addition to the premium swap crude oil hedging contracts, the Company had entered into crude oil costless collar hedges from January 1, 2000 to April 30, 2000 for volumes of 2,000 BBLS per day. These costless collars had a floor price ranging from $21.53 per BBL to $23.27 per BBL and a cap price ranging from $25.83 per BBL to $27.31 per BBL. These costless collar contracts entitled the Company to receive settlements from the counterparties in amounts, if any, by which the monthly average settlement price for each NYMEX trading day during a contract month was less than the floor price. If the monthly average settlement price was above the applicable cap price, then the Company would owe the counterparties for the excess of the monthly average settlement price over the applicable cap price. If 39

the monthly average settlement price fell between the applicable floor and cap price, then neither party would have any liability to the other party for that month. Payment, if any, was made monthly under each of the contracts in an amount equal to the net amount due either party based on the volumes per day multiplied by the difference between the NYMEX average price and the cap, if the NYMEX average price exceeded the cap price, or if the NYMEX average price was less than the floor price, then the volumes per day multiplied by the difference between the floor price and the NYMEX average price. The net effect of these costless collar hedges was a $.05 per BBL reduction in the average crude oil price realized by the Company in 2000. The Company had no oil or gas hedging contracts for future production as of December 31, 2000. During 1999 and 1998, the Company had no oil or gas hedging transactions for its production. In addition to the hedging arrangements pertaining to the Company's production as described above, NGM employs various hedging arrangements in connection with its purchases and sales of third party production to lock in profits or limit exposure to gas price risk. Most of the purchases made by NGM are on an index basis; however, purchasers in the markets in which NGM sells often require fixed or NYMEX related pricing. NGM may use a hedge to convert the fixed or NYMEX sale to an index basis thereby determining the margin and minimizing the risk of price volatility. During 2000, NGM had hedging transactions with broker-dealers that ranged from 423,000 MMBTU to 1,023,000 MMBTU of gas per day. At December 31, 2000, NGM had in place hedges ranging from approximately 20,000 MMBTU to 1,133,000 MMBTU of gas per day for January 2001 to May 2006 for future physical transactions. In 1999, NGM had hedging transactions with broker-dealers that ranged from 146,000 MMBTU to 815,000 MMBTU of gas per day. During 1998, NGM had hedging transactions with broker-dealers that ranged from 508,811 MMBTU to 1,061,536 MMBTU of gas per day. NGM records hedging gains or losses relating to fixed term sales as gathering, marketing and processing revenues in the periods in which the related contract is completed. SELF-INSURANCE The Company self-insures the medical and dental coverage provided to certain of its employees, certain workers' compensation and the first $200,000 of its general liability coverage. A provision for self-insured claims is recorded when sufficient information is available to reasonably estimate the amount of the loss. UNCONSOLIDATED SUBSIDIARY The Company has an unconsolidated subsidiary, Atlantic Methanol Capital Company ("AMCCO"), a 50 percent owned joint venture that owns an indirect 90 percent interest in Atlantic Methanol Production Company ("AMPCO"). The Company accounts for its interest in AMCCO using the equity method within the Company's wholly-owned subsidiary, Samedan of North Africa, Inc. Samedan is participating with a 50 percent expense interest (45 percent ownership net of a five percent government carried interest) to construct a methanol plant in Equatorial Guinea. RECLASSIFICATION Certain reclassifications have been made to the 1999 and 1998 consolidated financial statements to conform to the 2000 presentation. RECENTLY ISSUED PRONOUNCEMENTS The Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standard ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities" in June 1998. The Statement establishes 40

accounting and reporting standards requiring every derivative instrument (including certain derivative instruments embedded in other contracts) to be recorded in the balance sheet as either an asset or liability measured at its fair value. The Statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met wherein gains and losses are reflected in shareholders' equity until the hedged item is recognized. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company formally document, designate and assess the effectiveness of transactions that receive hedge accounting. Due to the issuance of SFAS No. 137, which deferred the effective date of SFAS No. 133, the Company is required to adopt the statement for fiscal years beginning after June 15, 2000. A company may also implement the statement as of the beginning of any fiscal quarter after the statement's issuance (that is, fiscal quarters beginning June 16, 1998, and thereafter). SFAS No. 133 must be applied to (a) derivative instruments and (b) certain derivative instruments embedded in hybrid contracts that were issued, acquired, or substantively modified after December 31, 1997 (and, at the Company's election, before January 1, 1998). During 2000, the FASB issued SFAS No. 138 which amends the accounting and reporting standards of SFAS No. 133 for certain derivative instruments and certain hedging activities and should be adopted concurrently with SFAS No. 133, according to its provisions and the issuance of SFAS No. 137. The normal purchases and normal sales exception may be applied to contracts that implicitly or explicitly permit net settlement and contracts that have a market mechanism to facilitate net settlement. The Company adopted SFAS Nos. 133 and 138 effective January 1, 2001. The adoption of these FASB's did not have a material impact on the Company's results of operations or financial position. NOTE 2 - DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS The following methods and assumptions were used to estimate the fair value of each class of financial instruments pursuant to the requirements of SFAS No. 107, "Disclosures about Fair Value of Financial Instruments." CASH AND SHORT-TERM INVESTMENTS The carrying amount approximates fair value due to the short maturity of the instruments. OIL AND GAS PRICE HEDGE AGREEMENTS The fair value of oil and gas price hedges is the estimated amount the Company would receive or pay to terminate the hedge agreements at the reporting date taking into account creditworthiness of the hedging parties. LONG-TERM DEBT The fair value of the Company's long-term debt is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for debt of the same remaining maturities. 41

The carrying amounts and estimated fair values of the Company's financial instruments as of December 31, for each of the years are as follows: 2000 1999 ---------------------------- --------------------------- CARRYING FAIR CARRYING FAIR (IN THOUSANDS) AMOUNT VALUE AMOUNT VALUE - -------------------------------------------------------------------------------------------------------------------- Cash and short-term investments $ 23,152 $ 23,152 $ 2,925 $ 2,925 Long-term debt (including current portion) $ 525,494 $ 539,375 $ 445,319 $ 407,500 Oil hedge agreements $ $ $ $ (7,879) NOTE 3 - DEBT A summary of debt at December 31 follows: (IN THOUSANDS) 2000 1999 - -------------------------------------------------------------------------------------------------------------------- $300 million Credit Agreement $ 80,000 $ 7 1/4% Notes Due 2023 100,000 100,000 8% Senior Notes Due 2027 250,000 250,000 7 1/4% SENIOR DEBENTURES DUE 2097 100,000 100,000 - -------------------------------------------------------------------------------------------------------------------- Outstanding debt 530,000 450,000 - -------------------------------------------------------------------------------------------------------------------- Less: unamortized discount 4,506 4,681 - -------------------------------------------------------------------------------------------------------------------- Long-term debt $ 525,494 $ 445,319 - -------------------------------------------------------------------------------------------------------------------- The Company's total long-term debt, net of unamortized discount, at December 31, 2000, was $525 million compared to $445 million at December 31, 1999. The ratio of debt to book capital (defined as the Company's debt plus its equity) was 38 percent at December 31, 2000, compared with 39 percent at December 31, 1999. The Company's long-term debt is comprised of: $100 million of 7 1/4% Notes Due 2023, $250 million of 8% Senior Notes Due 2027, $100 million of 7 1/4% Senior Debentures Due 2097 and the outstanding balance of $80 million on a $300 million credit facility. Other than the $80 million due on the credit facility, there is no principal payment due on long term debt during the next five years. The Company has a $300 million credit facility which exposes the Company to the risk of earnings or cash flow loss due to changes in market interest rates. At December 31, 2000, there was $80 million borrowed against the credit facility which has a maturity date of December 24, 2002. The interest rate is based upon a Eurodollar rate plus a range of 17.5 to 50 basis points. At year-end 1999, the Company had no borrowing outstanding on this facility. On June 17, 1999, the Company entered into a new $100 million 364 day credit agreement with certain commercial lending institutions. This agreement, which is based upon a Eurodollar rate plus 37.5 to 87.5 basis points depending upon the percentage of utilization, expired in 2000 without ever having been utilized. 42

NOTE 4 - INCOME TAXES The following table details the difference between the federal statutory tax rate and the effective tax rate for the years ended December 31: (AMOUNTS EXPRESSED IN PERCENTAGES) 2000 1999 1998 - --------------------------------------------------------------------------------------------------------------------- Statutory rate (benefit) 35.0 35.0 (35.0) Effect of: State taxes, net of federal benefit .3 (.2) Difference between U.S. and foreign rates .2 3.1 1.3 Other, net .5 (1.8) .4 - --------------------------------------------------------------------------------------------------------------------- Effective rate 36.0 36.3 (33.5) - --------------------------------------------------------------------------------------------------------------------- The net current deferred tax asset (liability) in the following table is classified as Other Current Assets in the Consolidated Balance Sheet. The tax effects of temporary differences which gave rise to deferred tax assets and liabilities as of December 31 were: (IN THOUSANDS) 2000 1999 - --------------------------------------------------------------------------------------------------------------------- U.S. and State Current Deferred Tax Assets: Accrued expenses $ 1,061 $ 525 Deferred income (186) 36 Allowance for doubtful accounts 225 284 Other (21) 14 - --------------------------------------------------------------------------------------------------------------------- Net current deferred tax asset 1,079 859 - --------------------------------------------------------------------------------------------------------------------- U.S. and State Non-current Deferred Tax Liabilities: Property, plant and equipment, principally due to differences in depreciation, amortization, lease impairment and abandonments (121,799) (84,969) Accrued expenses 9,309 8,041 Deferred income 3,303 2,748 Allowance for doubtful accounts 5,779 4,865 Income tax accruals 9,579 9,244 Other 2,962 2,552 - --------------------------------------------------------------------------------------------------------------------- Net non-current deferred liability (90,867) (57,519) - --------------------------------------------------------------------------------------------------------------------- U.S. and state net deferred tax liability (89,788) (56,660) - --------------------------------------------------------------------------------------------------------------------- Foreign Deferred Tax Liabilities: Property, plant and equipment of foreign operations (26,181) (25,556) - --------------------------------------------------------------------------------------------------------------------- Deferred tax liability (26,181) (25,556) - --------------------------------------------------------------------------------------------------------------------- Total net deferred tax liability $ (115,969) $ (82,216) - --------------------------------------------------------------------------------------------------------------------- The components of income from operations before income taxes for each year are as follows: (IN THOUSANDS) 2000 1999 1998 - --------------------------------------------------------------------------------------------------------------------- Domestic $268,489 $83,439 $(225,692) Foreign 30,994 (5,808) (21,016) - --------------------------------------------------------------------------------------------------------------------- Total $299,483 $77,631 $(246,708) - --------------------------------------------------------------------------------------------------------------------- 43

The income tax provision (benefit) relating to operations for each year consists of the following: (IN THOUSANDS) 2000 1999 1998 - --------------------------------------------------------------------------------------------------------------------- U.S. current $ 65,358 $18,963 $(20,842) U.S. deferred 32,311 7,150 (62,366) State current 917 313 236 State deferred 334 (313) (1,080) Foreign current 8,341 5,232 927 Foreign deferred 625 (3,175) 442 - --------------------------------------------------------------------------------------------------------------------- Total $107,886 $28,170 $(82,683) - --------------------------------------------------------------------------------------------------------------------- NOTE 5 - COMMON STOCK, STOCK OPTIONS AND STOCKHOLDER RIGHTS The Company has two stock option plans, the 1992 Stock Option and Restricted Stock Plan ("1992 Plan") and the 1988 Non-Employee Director Stock Option Plan ("1988 Plan"). The Company accounts for these plans under APB Opinion 25. Compensation expense totaling $781,275 was recognized in 2000, due to the accelerated vesting of stock options as a result of the retirement of certain employees and is recorded in selling, general and administrative expense in the accompanying Consolidated Statement of Operations. Under the Company's 1992 Plan, the Board of Directors may grant stock options and award restricted stock. No restricted stock has been issued under the 1992 Plan. Since the adoption of the 1992 Plan, stock options have been issued at the market price on the date of grant. The earliest the granted options may be exercised is over a three year period at the rate of 33 1/3% each year commencing on the first anniversary of the grant date. The options expire ten years from the grant date. The 1992 Plan was amended in 2000, by a vote of the shareholders, to increase the maximum number of shares of common stock that may be issued under the 1992 Plan to 6,500,000 shares. At December 31, 2000, the Company had reserved 5,799,221 shares of common stock for issuance, including 2,353,006 shares available for grant, under its 1992 Plan. The Company's 1988 Plan allows stock options to be issued to certain non-employee directors at the market price on the date of grant. The options may be exercised one year after issue and expire ten years from the grant date. The 1988 Plan provides for the grant of options to purchase a maximum of 550,000 shares of the Company's authorized but unissued common stock. At December 31, 2000, the Company had reserved 399,000 shares of common stock for issuance, including 165,500 shares available for grant, under its 1988 Plan. The Company adopted a stockholder rights plan on August 27, 1997, designed to assure that the Company's stockholders receive fair and equal treatment in the event of any proposed takeover of the Company and to guard against partial tender offers and other abusive takeover tactics to gain control of the Company without paying all stockholders a fair price. The rights plan was not adopted in response to any specific takeover proposal. Under the rights plan, the Company declared a dividend of one right ("Right") on each share of Noble Affiliates, Inc. common stock. Each Right will entitle the holder to purchase one one-hundredth of a share of a new Series A Junior Participating Preferred Stock, par value $1.00 per share, at an exercise price of $150.00. The Rights are not currently exercisable and will become exercisable only in the event a person or group acquires beneficial ownership of 15 percent or more of Noble Affiliates, Inc. common stock. The dividend distribution was made on September 8, 1997, to stockholders of record at the close of business on that date. The Rights will expire on September 8, 2007. 44

Stock options outstanding under the plans mentioned above and one previously terminated plan are presented for the periods indicated. NUMBER OPTION OF SHARES PRICE RANGE - --------------------------------------------------------------------------------------------------------------------- OUTSTANDING DECEMBER 31, 1997 2,205,335 $ 11.63-$40.38 - --------------------------------------------------------------------------------------------------------------------- Granted 722,604 $ 35.94-$37.75 Exercised (82,470) $ 11.63-$40.38 Canceled (28,227) $ 24.25-$40.38 - --------------------------------------------------------------------------------------------------------------------- OUTSTANDING DECEMBER 31, 1998 2,817,242 $ 13.38-$40.38 - --------------------------------------------------------------------------------------------------------------------- Granted 810,895 $ 20.06-$27.50 Exercised (64,055) $ 13.38-$24.25 Canceled (85,812) $ 20.06-$40.38 - --------------------------------------------------------------------------------------------------------------------- OUTSTANDING DECEMBER 31, 1999 3,478,270 $ 13.50-$40.38 - --------------------------------------------------------------------------------------------------------------------- Granted 774,343 $ 20.06-$38.88 Exercised (432,199) $ 13.50-$40.38 Canceled (109,404) $ 20.06-$40.38 - --------------------------------------------------------------------------------------------------------------------- OUTSTANDING DECEMBER 31, 2000 3,711,010 $ 13.50-$40.38 - --------------------------------------------------------------------------------------------------------------------- EXERCISABLE AT DECEMBER 31, 2000 2,404,760 $ 13.50-$40.38 - --------------------------------------------------------------------------------------------------------------------- The SFAS No. 123 method of accounting is based on several assumptions and should not be viewed as indicative of the operations of the Company in future periods. The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions used for grants in 2000, 1999 and 1998, respectively, as follows: (AMOUNTS EXPRESSED IN PERCENTAGES) 2000 1999 1998 - --------------------------------------------------------------------------------------------------------------------- Interest rate 6.25 5.50 5.75 Dividend yield .40 .40 .40 Expected volatility 51.67 42.95 32.66 Expected life 9.71 8.80 9.74 The weighted average fair value of options granted using the Black-Scholes option pricing model for 2000, 1999 and 1998, respectively, is as follows: 2000 1999 1998 - --------------------------------------------------------------------------------------------------------------------- Black-Scholes model weighted average fair value option price $16.66 $10.01 $19.02 The Company applies APB Opinion No. 25 in accounting for its fixed price stock options. Compensation expense totaling $781,275 was recognized in 2000, due to the accelerated vesting of stock options as a result of the retirement of certain employees. The table below sets forth the Company's net income and earnings per share for each of the years ended December 31, as reported and on a pro forma basis as if the compensation cost of stock options had been determined consistent with SFAS No. 123, "Accounting for Stock-Based Compensation." (IN THOUSANDS EXCEPT PER SHARE AMOUNTS) 2000 1999 1998 - --------------------------------------------------------------------------------------------------------------------- Net Income: As Reported $ 191,597 $49,461 $ (164,025) Pro Forma $ 183,427 $41,176 $ (171,741) Basic Earnings Per Share: As Reported $ 3.42 $ .87 $ (2.88) Pro Forma $ 3.28 $ .72 $ (3.02) Diluted Earnings Per Share: As Reported $ 3.38 $ .86 $ (2.88) Pro Forma $ 3.23 $ .72 $ (3.02) 45

NOTE 6 - EMPLOYEE BENEFIT PLANS PENSION PLAN AND OTHER POSTRETIREMENT BENEFIT PLANS The Company has a non-contributory defined benefit pension plan covering substantially all of its domestic employees. The benefits are based on an employee's years of service and average earnings for the 60 consecutive calendar months of highest compensation. The Company also has an unfunded restoration plan to ensure payments of amounts for which employees are entitled under the provisions of the pension plan, but which are subject to limitations imposed by federal tax laws. The Company's funding policy has been to make annual contributions equal to the actuarially computed liability to the extent such amounts are deductible for income tax purposes. Plan assets consist of equity securities and fixed income investments. The Company sponsors other plans for the benefit of its employees and retirees. These plans include health care and life insurance benefits. The following table reflects the required SFAS No. 132, "Employers' Disclosures About Pension and Other Postretirement Benefits," disclosures at December 31: PENSION BENEFITS OTHER BENEFITS ----------------------------- ---------------------------- (IN THOUSANDS) 2000 1999 2000 1999 - -------------------------------------------------------------------------------------------------------------------- CHANGE IN BENEFIT OBLIGATION Benefit obligation at beginning of year $ 64,194 $ 82,823 $ 2,738 $ 3,187 Service cost 3,566 3,802 231 294 Interest cost 5,525 4,720 187 187 Plan participants' contributions 42 38 Amendments (363) Actuarial (gain) loss 6,423 (24,294) (328) (533) Benefit paid (3,085) (2,857) (152) (72) - -------------------------------------------------------------------------------------------------------------------- Benefit obligation at year end $ 76,623 $ 64,194 $ 2,718 $ 2,738 - -------------------------------------------------------------------------------------------------------------------- CHANGE IN PLAN ASSETS Fair value of plan assets at beginning of year $ 59,168 $ 60,559 $ $ Actual return on plan assets (992) 1,083 Employer contribution 396 383 152 72 Benefit paid (3,085) (2,857) (152) (72) - -------------------------------------------------------------------------------------------------------------------- Fair value of plan at end of year $ 55,487 $ 59,168 $ $ - -------------------------------------------------------------------------------------------------------------------- Fund status $ (21,136) $ (5,026) $ (2,718) $ (2,738) Unrecognized net actuarial loss (gain) (6,560) (18,989) 19 222 Unrecognized prior service cost 2,743 3,035 (304) (334) Unrecognized net transition obligation (assets) 1,214 1,239 - -------------------------------------------------------------------------------------------------------------------- Prepaid (accrued) benefit costs $ (23,739) $ (19,741) $ (3,003) $ (2,850) - -------------------------------------------------------------------------------------------------------------------- COMPONENTS OF NET PERIODIC BENEFIT COST Service cost $ 3,567 $ 3,802 $ 231 $ 294 Interest cost 5,525 4,720 188 188 Expected return on plan assets (4,666) (4,264) Transition (assets) obligation recognition 24 24 Amortization of prior service cost 291 291 (30) (30) Recognized net actuarial loss (347) 35 (11) 34 - -------------------------------------------------------------------------------------------------------------------- Net periodic benefit cost $ 4,394 $ 4,608 $ 378 $ 486 - -------------------------------------------------------------------------------------------------------------------- WEIGHTED-AVERAGE ASSUMPTIONS AS OF DECEMBER 31, Discount rate 8.00% 8.00% 8.00% 8.00% Expected return on plan assets 8.50% 8.50% Rate of compensation increase 5.50% 5.50% 5.50% 5.50% 46

The following table reflects the aggregate pension obligation components required by SFAS No. 132 for the defined benefit pension plan and the restoration benefit plan, which are aggregated in the previous tables, at December 31: DEFINED BENEFIT RESTORATION PENSION PLAN BENEFIT PLAN ---------------------------- ---------------------------- (IN THOUSANDS) 2000 1999 2000 1999 - -------------------------------------------------------------------------------------------------------------------- AGGREGATED PENSION BENEFITS Aggregate fair value of plan assets $ 55,487 $ 59,168 $ $ Aggregate accumulated benefit obligation 61,902 56,092 14,721 8,102 - -------------------------------------------------------------------------------------------------------------------- Fund status of net periodic benefit assets (obligation) $ (6,415) $ 3,076 $ (14,721) $ (8,102) - -------------------------------------------------------------------------------------------------------------------- Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following results: 1-PERCENTAGE- 1-PERCENTAGE- (IN THOUSANDS) POINT INCREASE POINT DECREASE - ------------------------------------------------------------------------------------------------------------------- Total service and interest cost components $ 472 $ 373 Total postretirement benefit obligation $ 2,628 $2,136 EMPLOYEE SAVINGS PLAN ("ESP") The Company has an ESP which is a defined contribution plan. Participation in the ESP is voluntary and all regular employees of the Company are eligible to participate. The Company may match up to 100 percent of the participant's contribution not to exceed six percent of the employee's base compensation. The following table indicates the Company's contribution for the years ended December 31: (IN THOUSANDS) 2000 1999 1998 - ------------------------------------------------------------------------------------------------------------------- Employers' plan contribution $1,858 $1,823 $1,938 NOTE 7 - ADDITIONAL BALANCE SHEET AND STATEMENT OF OPERATIONS INFORMATION Included in accounts receivable-trade is an allowance for doubtful accounts at December 31: (IN THOUSANDS) 2000 1999 - ------------------------------------------------------------------------------------------------------------------- Allowance for doubtful accounts $ 645 $ 1,237 Other current assets include the following at December 31: (IN THOUSANDS) 2000 1999 - ------------------------------------------------------------------------------------------------------------------- Deferred tax asset $ 1,079 $ 859 Prepaid federal income taxes $ 56,890 $ 30,000 Other current liabilities include the following at December 31: (IN THOUSANDS) 2000 1999 - ------------------------------------------------------------------------------------------------------------------- Gas imbalance liabilities $ 1,348 $ 2,604 Note payable unconsolidated subsidiary $ $ 23,245 Accrued interest payable $ 11,949 $ 10,897 Louisiana workers compensation $ 5,387 $ 4,751 Oil and gas operations expense included the following for the years ended December 31: (IN THOUSANDS) 2000 1999 1998 - -------------------------------------------------------------------------------------------------------------------- Lease operating expense $ 93,948 $ 107,289 $ 136,155 Workover expense 21,124 5,708 6,518 Production taxes 10,264 6,679 8,436 Other (3,470) (2,978) (2,079) - -------------------------------------------------------------------------------------------------------------------- Total operations expense $ 121,866 $ 116,698 $ 149,030 - -------------------------------------------------------------------------------------------------------------------- 47

Oil and gas exploration expense included the following for the years ended December 31: (IN THOUSANDS) 2000 1999 1998 - ------------------------------------------------------------------------------------------------------------------- Dry hole expense $ 38,463 $ 19,204 $ 57,736 Undeveloped lease amortization 16,075 9,645 7,953 Abandoned assets 3,375 2,483 15,325 Seismic 18,738 7,797 15,754 Other 11,592 7,655 13,390 - ------------------------------------------------------------------------------------------------------------------- Total exploration expense $ 88,243 $ 46,784 $ 110,158 - ------------------------------------------------------------------------------------------------------------------- During the past three years, there was no purchaser that accounted for more than ten percent of total oil and gas sales and royalties. NOTE 8 - IMPAIRMENT OF LONG-LIVED ASSETS The Company follows SFAS No. 121 and any assets impaired are oil and gas properties maintained under the successful efforts method of accounting. The excess of the net book value over the projected discounted future net revenue of the impaired properties is charged to "Impairment of Operating Assets." The Company recorded no asset impairments under SFAS No. 121 during 2000 or 1999. In December 1998, the Company recorded a $223.3 million pre-tax charge for the write-down under SFAS No. 121 of properties due to downward reserve revisions. 48

NOTE 9 - UNCONSOLIDATED SUBSIDIARY The Company has an unconsolidated subsidiary, AMCCO, a 50 percent owned joint venture that owns an indirect 90 percent interest in AMPCO. The Company accounts for its interest in AMCCO using the equity method within the Company's wholly-owned subsidiary, Samedan of North Africa, Inc. Samedan is participating with a 50 percent expense interest (45 percent ownership net of a five percent government carried interest) to construct a methanol plant in Equatorial Guinea. The total projected cost of the plant and supporting facilities is estimated to be $448 million including various contingencies and capitalized interest, with the Company responsible for $224 million. The plant is designed to produce 2,500 metric tons of methanol per day, which equates to approximately 20,000 BBLS per day. At this level of production, the plant would use approximately 125 MMCF of gas per day from the Alba field as feedstock. Reserve estimates indicate the Alba field can deliver sufficient gas for the plant to operate 30 years. The construction contract stipulates that first production should be achieved by the second quarter of 2001. Current marketing plans are to use two tankers, which are under long-term contracts, to transport the methanol to markets in Europe and the United States. On November 10, 1999, AMCCO issued $125 million of 10.875% Series A-1 Senior Secured Notes and $125 million of 8.95% Series A-2 Senior Secured Notes ("Series A-2 Notes") due 2004, which are not included in the Company's balance sheet. The Company has guaranteed the payment of interest on the Series A-2 Notes. In addition, the Company established a new series of preferred stock, Series B Mandatory Convertible Preferred Stock, par value $1.00 per share (the "Series B Preferred"). The Company issued, in a private placement pursuant to Section 4(2) of the Securities Act, 125,000 shares of the Series B Preferred to Noble Share Trust, which is a Delaware statutory business trust, in exchange for all of the beneficial ownership interests in Noble Share Trust. Noble Share Trust holds the 125,000 shares of Series B Preferred for the benefit of the holders of the Series A-2 Notes. The following are summarized financial statements for AMCCO as of December 31: CONSOLIDATED BALANCE SHEET ATLANTIC METHANOL CAPITAL COMPANY (IN THOUSANDS) 2000 1999 - --------------------------------------------------------------------------------------------------------------------- ASSETS Current assets $ 45,676 $ 68,638 Non-current assets 392,272 239,946 - --------------------------------------------------------------------------------------------------------------------- Total assets $ 437,948 $ 308,584 - --------------------------------------------------------------------------------------------------------------------- LIABILITIES, MINORITY INTEREST AND MEMBERS' EQUITY Current liabilities $ 1,197 $ 3,504 Non-current liabilities 250,000 250,000 Minority interest 36,556 22,939 Members' equity 150,195 32,141 - --------------------------------------------------------------------------------------------------------------------- Total liabilities, minority interest and members' equity $ 437,948 $ 308,584 - --------------------------------------------------------------------------------------------------------------------- CONSOLIDATED STATEMENT OF OPERATIONS ATLANTIC METHANOL CAPITAL COMPANY (IN THOUSANDS) 2000 1999 - --------------------------------------------------------------------------------------------------------------------- Interest income $ 4,389 $ 2,524 Expenses: Interest (net of amount capitalized) 1,005 1,640 Administrative 86 - --------------------------------------------------------------------------------------------------------------------- Net income $ 3,298 $ 884 - --------------------------------------------------------------------------------------------------------------------- 49

SUPPLEMENTAL OIL AND GAS INFORMATION (Unaudited) There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves. Oil and gas reserve engineering is a subjective process of estimating underground accumulations of oil and gas that can not be precisely measured, and estimates of engineers other than Samedan's might differ materially from the estimates set forth herein. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered. PROVED GAS RESERVES (Unaudited) The following reserve schedule was developed by the Company's reserve engineers and sets forth the changes in estimated quantities of proved gas reserves of the Company during each of the three years presented. NATURAL GAS AND CASINGHEAD GAS (MMCF) - ----------------------------------------------------------------------------------------------------------------------- UNITED EQUATORIAL NORTH PROVED RESERVES AS OF: STATES ARGENTINA ECUADOR GUINEA ISRAEL SEA TOTAL - ----------------------------------------------------------------------------------------------------------------------- JANUARY 1, 2000 759,781 5,221 87,500 384,102 26,452 1,263,056 Revisions of previous estimates (7,022) 44 131 7,864 1,017 Extensions, discoveries and other additions 135,844 218,154 3,101 357,099 Production (136,010) (721) (941) (8,665) (146,337) Sale of minerals in place (4,840) (4,840) Purchase of minerals in place 4,634 4,634 - ----------------------------------------------------------------------------------------------------------------------- DECEMBER 31, 2000 752,387 4,544 87,500 383,292 218,154 28,752 1,474,629 - ----------------------------------------------------------------------------------------------------------------------- PROVED RESERVES AS OF: - ----------------------------------------------------------------------------------------------------------------------- JANUARY 1, 1999 873,222 5,386 321,642 39,056 1,239,306 Revisions of previous estimates (15,700) 482 63,478 (2,392) 45,868 Extensions, discoveries and other additions 87,293 87,500 192 174,985 Production (150,871) (647) (1,018) (10,404) (162,940) Sale of minerals in place (34,165) (34,165) Purchase of minerals in place 2 2 - ----------------------------------------------------------------------------------------------------------------------- DECEMBER 31, 1999 759,781 5,221 87,500 384,102 26,452 1,263,056 - ----------------------------------------------------------------------------------------------------------------------- PROVED RESERVES AS OF: - ----------------------------------------------------------------------------------------------------------------------- JANUARY 1, 1998 1,107,158 5,565 322,205 47,287 1,482,215 Revisions of previous estimates (155,314) 27 396 (1,030) (155,921) Extensions, discoveries and other additions 71,061 71,061 Production (196,220) (206) (959) (7,201) (204,586) Sale of minerals in place (2,232) (2,232) Purchase of minerals in place 48,769 48,769 - ----------------------------------------------------------------------------------------------------------------------- DECEMBER 31, 1998 873,222 5,386 321,642 39,056 1,239,306 - ----------------------------------------------------------------------------------------------------------------------- PROVED DEVELOPED GAS RESERVES AS OF: - ----------------------------------------------------------------------------------------------------------------------- January 1, 2001 690,301 4,544 383,292 25,652 1,103,789 January 1, 2000 703,166 5,221 11,687 26,452 746,526 January 1, 1999 818,787 5,386 12,862 39,056 876,091 January 1, 1998 1,022,192 5,565 13,425 47,287 1,088,469 - ----------------- 50

PROVED OIL RESERVES (Unaudited) The following reserve schedule was developed by the Company's reserve engineers and sets forth the changes in estimated quantities of proved oil reserves of the Company during each of the three years presented. CRUDE OIL AND CONDENSATE (BBLS IN THOUSANDS) - ----------------------------------------------------------------------------------------------------------------------- UNITED EQUATORIAL NORTH PROVED RESERVES AS OF: STATES ARGENTINA CHINA GUINEA SEA TOTAL - ----------------------------------------------------------------------------------------------------------------------- JANUARY 1, 2000 65,523 10,285 9,768 30,684 5,786 122,046 Revisions of previous estimates (1,493) 68 185 (366) (1,606) Extensions, discoveries and other additions 12,788 17,491 5,731 36,010 Production (7,309) (916) (914) (654) (9,793) Sale of minerals in place (935) (229) (1,164) Purchase of minerals in place 1,126 2,150 3,276 - ------------------------------------------------------------------------------------------------------------------------ DECEMBER 31, 2000 69,700 9,437 9,768 47,446 12,418 148,769 - ------------------------------------------------------------------------------------------------------------------------ PROVED RESERVES AS OF: - ------------------------------------------------------------------------------------------------------------------------ JANUARY 1, 1999 77,306 11,128 22,001 6,146 116,581 Revisions of previous estimates (1,394) (24) 9,617 (57) 8,142 Extensions, discoveries and other additions 3,687 9,768 354 13,809 Production (8,952) (819) (934) (657) (11,362) Sale of minerals in place (5,125) (5,125) Purchase of minerals in place 1 1 - ------------------------------------------------------------------------------------------------------------------------ DECEMBER 31, 1999 65,523 10,285 9,768 30,684 5,786 122,046 - ------------------------------------------------------------------------------------------------------------------------ PROVED RESERVES AS OF: - ------------------------------------------------------------------------------------------------------------------------ JANUARY 1, 1998 89,065 11,997 22,766 7,035 130,863 Revisions of previous estimates (5,935) 16 166 (129) (5,882) Extensions, discoveries and other additions 4,802 35 4,837 Production (11,540) (885) (931) (795) (14,151) Sale of minerals in place (155) (155) Purchase of minerals in place 1,069 1,069 - ------------------------------------------------------------------------------------------------------------------------ DECEMBER 31, 1998 77,306 11,128 22,001 6,146 116,581 - ------------------------------------------------------------------------------------------------------------------------ PROVED DEVELOPED OIL RESERVES AS OF: - ------------------------------------------------------------------------------------------------------------------------ January 1, 2001 58,903 9,437 9,768 47,446 5,728 131,282 January 1, 2000 60,618 10,285 9,768 14,743 3,986 99,400 January 1, 1999 72,949 11,128 11,425 4,346 99,848 January 1, 1998 82,713 11,997 12,191 5,234 112,135 PROVED RESERVES. Proved reserves are estimated quantities of crude oil, natural gas, natural gas liquids and condensate liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. PROVED DEVELOPED RESERVES. Proved developed reserves are proved reserves which are expected to be recovered through existing wells with existing equipment and operating methods. 51

OIL AND GAS OPERATIONS (Unaudited) Aggregate results of operations for each period ended December 31, in connection with the Company's oil and gas producing activities are shown below. Amounts are presented in accordance with SFAS No. 19, and may not agree with amounts determined using traditional industry definitions. (IN THOUSANDS) - ----------------------------------------------------------------------------------------------------------------------------- UNITED EQUATORIAL NORTH OTHER DECEMBER 31, 2000 STATES ARGENTINA ECUADOR GUINEA SEA INT'L TOTAL - ----------------------------------------------------------------------------------------------------------------------------- Revenues $ 705,270 $ 25,298 $ $ 25,501 $ 35,284 $ $ 791,353 Production costs 129,359 6,952 5,010 5,962 147,283 Exploration expenses 78,955 179 (4) 121 2,739 2,575 84,565 DD&A and valuation provision 222,161 7,796 47 1,355 12,231 449 244,039 - ----------------------------------------------------------------------------------------------------------------------------- Income (loss) 274,795 10,371 (43) 19,015 14,352 (3,024) 315,466 Income tax expense (benefit) 96,675 6,048 (15) 8,978 4,316 (1,000) 115,002 - ----------------------------------------------------------------------------------------------------------------------------- Result of operations from pro- ducing activities (excluding corporate overhead and interest costs) $ 178,120 $ 4,323 $ (28) $ 10,037 $ 10,036 $ (2,024) $ 200,464 - ----------------------------------------------------------------------------------------------------------------------------- DECEMBER 31, 1999 - ----------------------------------------------------------------------------------------------------------------------------- Revenues $ 493,718 $ 14,302 $ $ 16,036 $ 24,677 $ $ 548,733 Production costs 125,803 4,640 3,183 7,106 140,732 Exploration expenses 45,461 542 130 196 4,270 2,779 53,378 DD&A and valuation provision 231,157 6,401 16 3,212 19,687 849 261,322 - ----------------------------------------------------------------------------------------------------------------------------- Income (loss) 91,297 2,719 (146) 9,445 (6,386) (3,628) 93,301 Income tax expense (benefit) 31,646 1,651 4,428 (733) (1,094) 35,898 - ----------------------------------------------------------------------------------------------------------------------------- Result of operations from pro- ducing activities (excluding corporate overhead and interest costs) $ 59,651 $ 1,068 $ (146) $ 5,017 $ (5,653) $ (2,534) $ 57,403 - ----------------------------------------------------------------------------------------------------------------------------- DECEMBER 31, 1998 - ----------------------------------------------------------------------------------------------------------------------------- Revenues $ 564,771 $ 9,105 $ $ 10,282 $ 25,006 $ $ 609,164 Production costs 154,594 6,274 2,962 9,044 172,874 Exploration expenses 90,614 87 658 5,828 9,987 107,174 DD&A and valuation provision 513,725 6,083 2,998 13,869 46 536,721* - ----------------------------------------------------------------------------------------------------------------------------- Income (loss) (194,162) (3,339) 3,664 (3,735) (10,033) (207,605) Income tax expense (benefit) (68,764) (1,822) 1,786 (794) (2,489) (72,083) - ----------------------------------------------------------------------------------------------------------------------------- Result of operations from pro- ducing activities (excluding corporate overhead and interest costs) $(125,398) $ (1,517) $ $ 1,878 $ (2,941) $ (7,544) $(135,522) - ----------------------------------------------------------------------------------------------------------------------------- *Includes a pre-tax charge of $223.3 million pursuant to SFAS No. 121. 52

COSTS INCURRED IN OIL AND GAS ACTIVITIES (Unaudited) Costs incurred in connection with the Company's oil and gas acquisition, exploration and development activities for each of the years are shown below. Amounts are presented in accordance with SFAS No. 19, and may not agree with amounts determined using traditional industry definitions. (IN THOUSANDS) - --------------------------------------------------------------------------------------------------------------------- UNITED EQUATORIAL NORTH OTHER DECEMBER 31, 2000 STATES ECUADOR GUINEA ISRAEL SEA INT'L TOTAL - --------------------------------------------------------------------------------------------------------------------- Property acquisition costs Proved $ 6,822 $ $ $ 50,861 $ 41,284 $ $ 98,967 Unproved 12,559 1,927 2,218 858 17,562 - --------------------------------------------------------------------------------------------------------------------- Total $ 19,381 $ $ $ 52,788 $ 43,502 $ 858 $ 116,529 - --------------------------------------------------------------------------------------------------------------------- Exploration costs $ 115,728 $ (4) $ 62 $ 11,387 $ 1,396 $ 2,139 $ 130,708 - --------------------------------------------------------------------------------------------------------------------- Development costs $ 180,339 $ 35,078 $ 36,820 $ 1,502 $ 2,219 $ 9,570 $ 265,528 - --------------------------------------------------------------------------------------------------------------------- DECEMBER 31, 1999 - --------------------------------------------------------------------------------------------------------------------- Property acquisition costs Proved $ 69 $ $ $ $ $ $ 69 Unproved 7,280 620 7,900 - --------------------------------------------------------------------------------------------------------------------- Total $ 7,349 $ $ $ $ $ 620 $ 7,969 - --------------------------------------------------------------------------------------------------------------------- Exploration costs $ 43,999 $ 130 $ 123 $ $ 3,229 $ 7,722 $ 55,203 - --------------------------------------------------------------------------------------------------------------------- Development costs $ 48,042 $ 2,569 $ 1,748 $ $ 4,972 $ 4,863 $ 62,194 - --------------------------------------------------------------------------------------------------------------------- DECEMBER 31, 1998 - --------------------------------------------------------------------------------------------------------------------- Property acquisition costs Proved $ 48,444 $ $ $ $ $ $ 48,444 Unproved 36,760 311 500 37,571 - --------------------------------------------------------------------------------------------------------------------- Total $ 85,204 $ $ $ $ 311 $ 500 $ 86,015 - --------------------------------------------------------------------------------------------------------------------- Exploration costs $ 132,958 $ $ 465 $ $ 5,328 $ 10,136 $ 148,887 - --------------------------------------------------------------------------------------------------------------------- Development costs $ 242,838 $ $ 10,977 $ $ 9,761 $ 18,169 $ 281,745 - --------------------------------------------------------------------------------------------------------------------- AGGREGATE CAPITALIZED COSTS (Unaudited) Aggregate capitalized costs relating to the Company's oil and gas producing activities, and related accumulated DD&A, as of December 31 are shown below: 2000 1999 -------------------------------------- ---------------------------------------- (IN THOUSANDS) U. S. INT'L TOTAL U. S. INT'L TOTAL - --------------------------------------------------------------------------------------------------------------------- Unproved oil and gas properties $ 80,750 $ 69,462 $ 150,212 $ 79,823 $ 13,288 $ 93,111 Proved oil and gas properties 2,598,115 464,896 3,063,011 2,389,937 303,800 2,693,737 - --------------------------------------------------------------------------------------------------------------------- 2,678,865 534,358 3,213,223 2,469,760 317,088 2,786,848 Accumulated DD&A (1,637,659) (107,534) (1,745,193) (1,471,889) (88,154) (1,560,043) - --------------------------------------------------------------------------------------------------------------------- Net capitalized costs $ 1,041,206 $ 426,824 $ 1,468,030 $ 997,871 $ 228,934 $ 1,226,805 - --------------------------------------------------------------------------------------------------------------------- 53

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES (Unaudited) The following information is based on the Company's best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2000, 1999 and 1998 in accordance with SFAS No. 69. The Standard requires the use of a 10 percent discount rate. This information is not the fair market value nor does it represent the expected present value of future cash flows of the Company's proved oil and gas reserves. UNITED EQUATORIAL NORTH OTHER DECEMBER 31, 2000 STATES ECUADOR GUINEA ISRAEL SEA INT'L TOTAL - --------------------------------------------------------------------------------------------------------------------- (IN MILLIONS OF DOLLARS) Future cash inflows $ 8,825 $ 305 $ 1,125 $ 524 $ 379 $ 462 $ 11,620 Future production and development costs 1,759 90 178 92 89 186 2,394 Future income tax expenses 1,909 58 256 117 78 74 2,492 - --------------------------------------------------------------------------------------------------------------------- Future net cash flows 5,157 157 691 315 212 202 6,734 10% annual discount for estimated timing of cash flows 2,037 62 273 124 84 80 2,660 - --------------------------------------------------------------------------------------------------------------------- Standardized measure of discounted future net cash flows $ 3,120 $ 95 $ 418 $ 191 $ 128 $ 122 $ 4,074 - --------------------------------------------------------------------------------------------------------------------- DECEMBER 31, 1999 - --------------------------------------------------------------------------------------------------------------------- (IN MILLIONS OF DOLLARS) Future cash inflows $ 3,565 $ 320 $ 779 $ $ 181 $ 463 $ 5,308 Future production and development costs 1,566 73 189 85 207 2,120 Future income tax expenses 376 46 111 18 49 600 - --------------------------------------------------------------------------------------------------------------------- Future net cash flows 1,623 201 479 78 207 2,588 10% annual discount for estimated timing of cash flows 686 85 203 33 88 1,095 - --------------------------------------------------------------------------------------------------------------------- Standardized measure of discounted future net cash flows $ 937 $ 116 $ 276 $ $ 45 $ 119 $ 1,493 - --------------------------------------------------------------------------------------------------------------------- DECEMBER 31, 1998 - --------------------------------------------------------------------------------------------------------------------- (IN MILLIONS OF DOLLARS) Future cash inflows $ 2,647 $ $ 301 $ $ 113 $ 96 $ 3,157 Future production and development costs 1,146 140 62 30 1,378 Future income tax expenses 182 19 6 8 215 - --------------------------------------------------------------------------------------------------------------------- Future net cash flows 1,319 142 45 58 1,564 10% annual discount for estimated timing of cash flows 490 53 17 22 582 - --------------------------------------------------------------------------------------------------------------------- Standardized measure of discounted future net cash flows $ 829 $ $ 89 $ $ 28 $ 36 $ 982 - --------------------------------------------------------------------------------------------------------------------- Construction of AMPCO's Equatorial Guinea methanol plant is scheduled to be completed in the second quarter of 2001. The future net cash inflows for 1998, 1999 and 2000 do not include cash flows relating to the Company's anticipated future methanol sales. For more information regarding Samedan's methanol plant, see Item 1. "Business--Unconsolidated Subsidiary" and Item 2. "Properties--Oil and Gas" of this Form 10-K. 54

Future cash inflows are estimated by applying year-end prices of oil and gas relating to the Company's proved reserves to the year-end quantities of those reserves, with consideration given to the effect of existing hedging contracts, if any. The year-end NYMEX West Texas intermediate crude oil price utilized in the computation of future cash inflows was $26.83 per BBL, which was adjusted by differentials applied on a property-by-property basis to yield a weighted average price of $24.27 per BBL. The West Texas intermediate crude oil price, as of February 28, 2001, was $27.38 per BBL, an increase of $.55 per BBL compared to year-end 2000. The Company estimates that a $1.00 per BBL change in the average oil price from the year-end price would change discounted future net cash flows before income taxes by approximately $76 million. The year-end Henry Hub natural gas price utilized in the computation of future cash inflows was $10.53 per MCF, which was adjusted by differentials applied on a property-by-property basis to yield a weighted average price of $9.14 per MCF. As of February 28, 2001, natural gas index prices at Henry Hub had decreased approximately $5.36 per MCF to $5.17 per MCF compared with the year-end price. The Company estimates that a $.10 per MCF change in the average gas price from the year-end price would change discounted future net cash flows before income taxes by approximately $45 million. Future production and development costs, which include dismantlement and restoration expense, are computed by estimating the expenditures to be incurred in developing and producing the Company's proved oil and gas reserves at the end of the year, based on year-end costs, and assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the estimated future pretax net cash flows relating to the Company's proved oil and gas reserves, less the tax bases of the properties involved. The future income tax expenses give effect to tax credits and allowances, but do not reflect the impact of general and administrative costs and exploration expenses of ongoing operations relating to the Company's proved oil and gas reserves. At December 31, 2000, the Company had estimated gas imbalance receivables of $18.5 million and estimated gas imbalance liabilities of $14.2 million; at year-end 1999, $17.9 million in receivables and $12.0 million in liabilities; and at year-end 1998, $19.1 million in receivables and $14.8 million in liabilities. Neither the gas imbalance receivables nor gas imbalance liabilities have been included in the standardized measure of discounted future net cash flows as of each of the three years ended December 31, 2000, 1999 and 1998. 55

SOURCES OF CHANGES IN DISCOUNTED FUTURE NET CASH FLOWS (Unaudited) Principal changes in the aggregate standardized measure of discounted future net cash flows attributable to the Company's proved oil and gas reserves, as required by Financial Accounting Standards Board's SFAS No. 69, at year end are shown below. (IN MILLIONS) 2000 1999 1998 - -------------------------------------------------------------------------------------------------------------------- Standardized measure of discounted future net cash flows at the beginning of the year $ 1,493 $ 982 $ 1,352 Extensions, discoveries and improved recovery, less related costs 1,462 410 39 Revisions of previous quantity estimates (20) 89 (132) Changes in estimated future development costs (52) (202) (17) Purchases (sales) of minerals in place 69 (58) 46 Net changes in prices and production costs 2,448 673 (443) Accretion of discount 185 102 189 Sales of oil and gas produced, net of production costs (662) (425) (454) Development costs incurred during the period 172 21 127 Net change in income taxes (1,207) (317) 503 Change in timing of estimated future production, and other 186 218 (228) - -------------------------------------------------------------------------------------------------------------------- Standardized measure of discounted future net cash flows at the end of the year $ 4,074 $1,493 $ 982 - -------------------------------------------------------------------------------------------------------------------- INTERIM FINANCIAL INFORMATION (Unaudited) Interim financial information for the years ended December 31, 2000 and 1999 is as follows: QUARTER ENDED --------------------------------------------------------------- (IN THOUSANDS EXCEPT PER SHARE AMOUNTS) MAR. 31, JUNE 30, SEPT. 30, DEC. 31, - ------------------------------------------------------------------------------------------------------------------- 2000 Revenues $ 268,872 $ 301,777 $ 357,353 $ 453,284 Gross profit from operations $ 49,444 $ 68,025 $ 97,489 $ 103,399 Net income $ 26,880 $ 36,861 $ 57,217 $ 70,640 Basic earnings per share $ .48 $ .66 $ 1.02 $ 1.26 Diluted earnings per share $ .47 $ .65 $ 1.01 $ 1.24 1999 Revenues $ 175,865 $ 216,245 $ 241,971 $ 252,698 Gross profit from operations $ 128 $ 22,959 $ 41,453 $ 38,087 Net income (loss) $ (8,901) $ 9,179 $ 27,654 $ 21,529 Basic earnings per share $ (.16) $ .16 $ .49 $ .38 Diluted earnings per share $ (.16) $ .16 $ .48 $ .38 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. Not applicable. 56

PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. The section entitled "Election of Directors" in the Registrant's proxy statement for the 2001 annual meeting of stockholders sets forth certain information with respect to the directors of the Registrant and is incorporated herein by reference. Certain information with respect to the executive officers of the Registrant is set forth under the caption "Executive Officers of the Registrant" in Part I of this report. The section entitled "Section 16(a) Beneficial Ownership Reporting Compliance" in the Registrant's proxy statement for the 2001 annual meeting of stockholders sets forth certain information with respect to compliance with Section 16(a) of the Securities Exchange Act of 1934, as amended, and is incorporated herein by reference. ITEM 11. EXECUTIVE COMPENSATION. The section entitled "Executive Compensation" in the Registrant's proxy statement for the 2001 annual meeting of stockholders sets forth certain information with respect to the compensation of management of the Registrant, and except for the report of the Compensation, Benefits and Stock Option Committee of the Board of Directors and the information therein under "Executive Compensation--Performance Graph" is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT. The sections entitled "Security Ownership of Certain Beneficial Owners" and "Security Ownership of Directors and Executive Officers" in the Registrant's proxy statement for the 2001 annual meeting of stockholders set forth certain information with respect to the ownership of the Registrant's common stock and are incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. The section entitled "Certain Transactions" in the Registrant's proxy statement for the 2001 annual meeting of stockholders sets forth certain information with respect to certain relationships and related transactions, and is incorporated herein by reference. PART IV ITEM 14. FINANCIAL STATEMENT SCHEDULES, EXHIBITS AND REPORTS ON FORM 8-K. (a) The following documents are filed as a part of this report: (1) Financial Statements and Financial Statement Schedules and Supplementary Data: These documents are listed in the Index to Consolidated Financial Statements in Item 8 hereof. (2) Exhibits: The exhibits required to be filed by this Item 14 are set forth in the Index to Exhibits accompanying this report. (b) The Registrant made no filings on Form 8-K during 2000. 57

SIGNATURES Pursuant to the requirements of Section 13 or 15(d) 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. NOBLE AFFILIATES, INC. Date: March 12, 2001 By: /s/ James L. McElvany ----------------------------------------- James L. McElvany, Vice President-Finance and Treasurer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. Signature Capacity in which signed Date - --------- ------------------------ ---- /s/ Robert Kelley Chairman of the Board March 12, 2001 - ------------------------------------ Robert Kelley /s/ Charles D. Davidson President, Chief Executive Officer March 12, 2001 - ------------------------------------ and Director (Principal Executive Charles D. Davidson Officer) /s/ James L. McElvany Vice President-Finance and Treasurer March 12, 2001 - ------------------------------------ (Principal Financial and Accounting James L. McElvany Officer) /s/ Alan A. Baker Director March 12, 2001 - ------------------------------------ Alan A. Baker /s/ Michael A. Cawley Director March 12, 2001 - ------------------------------------ Michael A. Cawley /s/ Edward F. Cox Director March 12, 2001 - ------------------------------------ Edward F. Cox /s/ Thomas E. Hassen Director March 12, 2001 - ------------------------------------ Thomas E. Hassen /s/ Dale P. Jones Director March 12, 2001 - ------------------------------------ Dale P. Jones /s/ Harold F. Kleinman Director March 12, 2001 - ------------------------------------ Harold F. Kleinman /s/ T. Don Stacy Director March 12, 2001 - ------------------------------------ T. Don Stacy 58

INDEX TO EXHIBITS Exhibit Number Exhibit ** - ------- ------- 3.1 -- Certificate of Incorporation, as amended, of the Registrant as currently in effect (filed as Exhibit 3.2 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1987 and incorporated herein by reference). 3.2 -- Certificate of Designations of Series A Junior Participating Preferred Stock of the Registrant dated August 27, 1997 (filed Exhibit A of Exhibit 4.1 to the Registrant's Registration Statement on Form 8-A filed on August 28, 1997 and incorporated herein by reference). 3.3 -- Composite copy of Bylaws of the Registrant as currently in effect (filed as Exhibit 3.4 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1997 and incorporated herein by reference). 3.4 -- Certificate of Designations of Series B Mandatorily Convertible Preferred Stock of the Registrant dated November 9, 1999. 4.1 -- Indenture dated as of October 14, 1993 between the Registrant and U.S. Trust Company of Texas, N.A., as Trustee, relating to the Registrant's 7 1/4% Notes Due 2023, including form of the Registrant's 7 1/4% Notes Due 2023 (filed as Exhibit 4.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 1993 and incorporated herein by reference). 4.2 -- Indenture relating to Senior Debt Securities dated as of April 1, 1997 between the Registrant and U.S. Trust Company of Texas, N.A., as Trustee (filed as Exhibit 4.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 1997 and incorporated herein by reference). 4.3 -- First Indenture Supplement relating to $250 million of the Registrant's 8% Senior Notes Due 2027 dated as of April 1, 1997 between the Registrant and U.S. Trust Company of Texas, N.A., as Trustee (filed as Exhibit 4.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 1997 and incorporated herein by reference). 4.4 -- Second Indenture Supplement, between the Company and U.S. Trust Company of Texas, N.A. as trustee, relating to $100 million of the Registrant's 7 1/4% Senior Debentures Due 2097 dated as of August 1, 1997 (filed as Exhibit 4.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 1997 and incorporated herein by reference). 4.5 -- Rights Agreement, dated as of August 27, 1997, between the Registrant and Liberty Bank and Trust Company of Oklahoma City, N.A., as Right's Agent (filed as Exhibit 4.1 to the Registrant's Registration Statement on Form 8-A filed on August 28, 1997 and incorporated herein by reference). 4.6 -- Amendment No. 1 to Rights Agreement dated as of December 8, 1998, between the Registrant and Bank One Trust Company, as successor Rights Agent to Liberty Bank and Trust Company of Oklahoma City, N.A. (filed as Exhibit 4.2 to the Registrant's Registration Statement on Form 8-A/A (Amendment No. 1) filed on December 14, 1998 and incorporated herein by reference). 10.1* -- Samedan Oil Corporation Bonus Plan, as amended and restated on September 24, 1996 (filed as Exhibit 10.1 to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1996 and incorporated herein by reference). 10.2* -- Restoration of Retirement Income Plan for certain participants in the Noble Affiliates Retirement Plan dated September 21, 1994, effective as of May 19, 1994 (filed as Exhibit 10.5 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1994 and incorporated herein by reference). 59

Exhibit Number Exhibit ** - ------ ------- 10.3* -- Noble Affiliates Thrift Restoration Plan dated May 9, 1994 (filed as Exhibit 10.6 to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1994 and incorporated herein by reference). 10.4* -- Noble Affiliates Restoration Trust dated September 21, 1994, effective as of October 1, 1994 (filed as Exhibit 10.7 to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1994 and incorporated herein by reference). 10.5* -- Noble Affiliates, Inc. 1992 Stock Option and Restricted Stock Plan, as amended and restated, dated November 2, 1992 (filed as Exhibit 4.1 to the Registrant's Registration Statement on Form S-8 (Registration No. 33-54084) and incorporated herein by reference). 10.6* -- 1982 Stock Option Plan of the Registrant (filed as Exhibit 4.1 to the Registrant's Registration Statement on Form S-8 (Registration No. 2-81590) and incorporated herein by reference). 10.7* -- Amendment No. 1 to the 1982 Stock Option Plan of the Registrant (filed as Exhibit 4.2 to the Registrant's Registration Statement on Form S-8 (Registration No. 2-81590) and incorporated herein by reference). 10.8* -- Amendment No. 2 to the 1982 Stock Option Plan of the Registrant (filed as Exhibit 10.11 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1995 and incorporated herein by reference). 10.9* -- 1988 Nonqualified Stock Option Plan for Non-Employee Directors of the Registrant, as amended and restated, effective as of January 30, 1996 (filed as Exhibit 10.13 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1996 and incorporated herein by reference). 10.10* -- Form of Indemnity Agreement entered into between the Registrant and each of the Registrant's directors and bylaw officers (filed as Exhibit 10.18 to the Registrant's Annual Report of Form 10-K for the year ended December 31, 1995 and incorporated herein by reference). 10.11 -- Guaranty of the Registrant dated October 28, 1982, guaranteeing certain obligations of Samedan (filed as Exhibit 10.12 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1993 and incorporated herein by reference). 10.12 -- Stock Purchase Agreement dated as of July 1, 1996, between Samedan Oil Corporation and Enterprise Diversified Holdings Incorporated (filed as Exhibit 2.1 to the Registrant's Current Report on Form 8-K (Date of Event: July 31, 1996) dated August 13, 1996 and incorporated herein by reference). 10.13* -- Noble Affiliates, Inc. 1992 Stock Option and Restricted Stock Plan, as amended and restated on December 10, 1996, subject to the approval of stockholders (filed as Exhibit 10.21 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1996 and incorporated herein by reference). 10.14 -- Amended and Restated Credit Agreement dated as of December 24, 1997 among the Registrant, as borrower, and Union Bank of Switzerland, Houston agency, as the agent for the lender, and NationsBank of Texas, N.A. and Texas Commerce Bank National Association, as managing agents, and Bank of Montreal, CIBC Inc., The First National Bank of Chicago, Royal Bank of Canada, and Societe Generale, Southwest agency, as co-agents, and certain commercial lending institutions, as lenders (filed as Exhibit 10.20 to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1997 and incorporated herein by reference). 60

Exhibit Number Exhibit ** - ------ ------- 10.15 -- Noble Preferred Stock Remarketing and Registration Rights Agreement dated as of November 10, 1999 by and among the Registrant, Noble Share Trust, The Chase Manhattan Bank, and Donaldson, Lufkin & Jenrette Securities Corporation (filed as Exhibit 10.15 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1999 and incorporated herein by reference). 10.16* -- Employment Agreement effective as of October 2, 2000 between Noble Affiliates, Inc. and Charles D. Davidson. 21 -- Subsidiaries. 23 -- Consent of Arthur Andersen LLP for inclusion of their report in this Form 10-K. * Management contract or compensatory plan or arrangement required to be filed as an exhibit hereto. ** Copies of exhibits will be furnished upon prepayment of 25 cents per page. Requests should be addressed to the Vice President-Finance and Treasurer, Noble Affiliates, Inc., 350 Glenborough Drive, Suite 100, Houston, Texas 77067. 61

DIRECTORS ROBERT KELLEY CHAIRMAN OF THE BOARD, NOBLE AFFILIATES, INC. CHARLES D. DAVIDSON PRESIDENT AND CHIEF EXECUTIVE OFFICER, NOBLE AFFILIATES, INC. ALAN A. BAKER CONSULTANT AND FORMER CHAIRMAN AND CHIEF EXECUTIVE OFFICER, HALLIBURTON ENERGY SERVICES MICHAEL A. CAWLEY TRUSTEE, PRESIDENT AND CHIEF EXECUTIVE OFFICER, THE SAMUEL ROBERTS NOBLE FOUNDATION, INC. EDWARD F. COX PARTNER, LAW FIRM OF PATTERSON, BELKNAP, WEBB AND TYLER THOMAS E. HASSEN MANAGING DIRECTOR, CO-HEAD GLOBAL ENERGY RESOURCES GROUP, CREDIT SUISSE FIRST BOSTON CORPORATION DALE P. JONES CONSULTANT AND FORMER VICE CHAIRMAN AND PRESIDENT, HALLIBURTON COMPANY HAROLD F. KLEINMAN OF COUNSEL, LAW FIRM OF THOMPSON & KNIGHT L.L.P. T. DON STACY FORMER CHAIRMAN AND PRESIDENT, AMOCO EURASIA PETROLEUM CO. DIRECTORS EMERITI GEORGE J. MCLEOD JOHN F. SNODGRASS JACK D. WILKES EXECUTIVE OFFICERS ROBERT KELLEY CHAIRMAN OF THE BOARD, NOBLE AFFILIATES, INC. CHARLES D. DAVIDSON PRESIDENT AND CHIEF EXECUTIVE OFFICER, NOBLE AFFILIATES, INC. ALAN R. BULLINGTON VICE PRESIDENT AND GENERAL MANAGER, INTERNATIONAL DIVISION OF SAMEDAN OIL CORPORATION ROBERT K. BURLESON PRESIDENT, NOBLE GAS MARKETING, INC. DAN O. DINGES SENIOR VICE PRESIDENT AND GENERAL MANAGER, OFFSHORE DIVISION OF SAMEDAN OIL CORPORATION ALBERT D. HOPPE SENIOR VICE PRESIDENT, GENERAL COUNSEL, AND SECRETARY, NOBLE AFFILIATES, INC. JAMES L. MCELVANY VICE PRESIDENT, CHIEF FINANCIAL OFFICER, TREASURER, AND ASSISTANT SECRETARY, NOBLE AFFILIATES, INC. RICHARD A. PENEGUY, JR. VICE PRESIDENT AND GENERAL MANAGER, ONSHORE DIVISION OF SAMEDAN OIL CORPORATION W. A. POILLION SENIOR VICE PRESIDENT-PRODUCTION AND DRILLING, SAMEDAN OIL CORPORATION KENNETH P. WILEY VICE PRESIDENT-INFORMATION SYSTEMS, NOBLE AFFILIATES, INC. 62

CORPORATE AND SUBSIDIARY OFFICES NOBLE AFFILIATES, INC. CORPORATE HEADQUARTERS 350 GLENBOROUGH DRIVE SUITE 100 HOUSTON, TEXAS 77067 (281) 872-3100 INVESTOR RELATIONS WILLIAM R. MCKOWN III ASSISTANT TREASURER (281) 872-3100 INVESTOR_RELATIONS@SAMEDAN.COM WWW.NOBLEAFF.COM SUBSIDIARY HEADQUARTERS SAMEDAN OIL CORPORATION 350 GLENBOROUGH DRIVE SUITE 100 HOUSTON, TEXAS 77067 NOBLE GAS MARKETING, INC. 350 GLENBOROUGH DRIVE SUITE 180 HOUSTON, TEXAS 77067 NOBLE TRADING, INC. 110 WEST BROADWAY POST OFFICE BOX 909 ARDMORE, OKLAHOMA 73402 OPERATIONAL OFFICES DOMESTIC OFFSHORE SAMEDAN OIL CORPORATION 350 GLENBOROUGH DRIVE SUITE 240 HOUSTON, TEXAS 77067 DOMESTIC ONSHORE SAMEDAN OIL CORPORATION 12600 NORTHBOROUGH DRIVE SUITE 250 HOUSTON, TEXAS 77067 INTERNATIONAL SAMEDAN OIL CORPORATION 350 GLENBOROUGH DRIVE SUITE 300 HOUSTON, TEXAS 77067 INDEPENDENT PUBLIC ACCOUNTANTS ARTHUR ANDERSEN LLP OKLAHOMA CITY, OKLAHOMA TRANSFER AGENT AND REGISTRAR FIRST CHICAGO TRUST COMPANY OF NEW YORK A DIVISION OF EQUISERVE POST OFFICE BOX 2500 JERSEY CITY, NEW JERSEY 07303 (800) 317-4445 WWW.EQUISERVE.COM HEARING IMPAIRED (201) 222-4955 COMMON STOCK LISTED NEW YORK STOCK EXCHANGE SYMBOL - NBL - ------------------------------------------------------------------------------- ANNUAL MEETING The Annual Meeting of Stockholders of Noble Affiliates, will be held on Tuesday, April 24, 2001, 9:30 a.m. at the Wyndham Greenspoint Hotel located at 12400 Greenspoint Drive in Houston, Texas. All stockholders are cordially invited to attend. FORM 10-K The Company's Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Securities and Exchange Commission, is included in this report. Additional copies are available without charge upon request by writing to the Chief Financial Officer, Noble Affiliates, Inc., 350 Glenborough Drive, Suite 100, Houston, Texas 77067, via the Company's Internet website: http://www.nobleaff.com, or via the Securities and Excange Commission's Internet website: http://www.sec.gov. - -------------------------------------------------------------------------------

NOBLE AFFILIATES, INC. EMPLOYMENT AGREEMENT -------------------- This Employment Agreement (this "Agreement") is effective as of October 2, 2000 between NOBLE AFFILIATES, INC., a Delaware corporation (the "Company"), and CHARLES D. DAVIDSON (the "Employee"). W I T N E S S E T H: WHEREAS, the Company desires to employ the Employee, and the Employee desires to be employed by the Company, as President and Chief Executive Officer in accordance with the terms and conditions set forth in this Agreement; NOW THEREFORE, for and in consideration of the premises and the mutual covenants contained herein, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, and subject to the terms and conditions hereinafter set forth, the parties hereto agree as follows: 1. DEFINITIONS. ----------- In addition to the words and terms elsewhere defined in this Agreement, the following words and terms as used herein shall have the following meanings, unless the context or use indicates a different meaning: "Annualized Compensation Amount" means an amount equal to (i) the annualized salary payable to the Employee pursuant to Subsection 4(a), plus (ii) the target bonus established for the Employee pursuant to Subsection 4(b) of this Agreement, both during the then-effective fiscal year of the Company. "Cause" means by reason of any of the following: (A) Employee's conviction of, or plea of nolo contendere to, any felony or to any crime or offense causing substantial harm to any of the Related Parties (defined below) or involving acts of theft, fraud, embezzlement, moral turpitude or similar conduct; (B) malfeasance in the conduct of Employee's duties, including, but not limited to, (1) willful and intentional misuse or diversion of funds of any of the Related Parties, (2) embezzlement, or (3) fraudulent or willful and material misrepresentations or concealments on any written reports submitted to the Related Parties; or (C) Employee's material breach of the provisions of this Agreement or material failure to follow or comply with the reasonable and lawful written directives of the Board of Directors of the Company, provided, however, that as regards the foregoing clause (C), Employee shall have been informed, in writing, of such material breach or failure and given a period of thirty (30) days to remedy same. "Common Stock" means the Company's common stock, $3.33 - 1/3 par value per share. An "Event of Default" means the occurrence of any of the following events prior to a Triggering Event, unless remedied or otherwise cured within thirty (30) days after the Company's receipt of written notice from the Employee of such event: (a) without his prior concurrence, the

Employee is assigned any duties or responsibilities that are inconsistent with his position, duties, responsibilities or status at the commencement of the term of this Agreement, or his reporting responsibilities in effect at such time are changed, (b) the Employee's base salary is reduced, or (c) any change in any employee benefit plans or arrangements in effect on the date hereof in which the Employee participates (including without limitation any annual incentive bonus plan, pension and retirement plan, savings and profit sharing plan, stock ownership or purchase plan, stock option plan, or life, medical or disability insurance plan), which would adversely affect the Employee's rights or benefits thereunder, unless such change occurs pursuant to a program or a plan amendment or termination that is applicable to all senior executive officers of the Company and does not result in a proportionately greater reduction in the rights of or benefits to the Employee as compared to any other senior executive officer of the Company. "Good Reason" means the occurrence of a Triggering Event (as defined below) AND: (a) without his prior concurrence, the Employee is assigned any duties or responsibilities that are inconsistent with his position, duties, responsibilities or status at the commencement of the term of this Agreement, or his reporting responsibilities in effect at such time are changed, (b) the Employee's base salary is reduced, or (c) any change in any employee benefit plans or arrangements in effect on the date hereof in which the Employee participates (including without limitation any annual incentive bonus plan, pension and retirement plan, savings and profit sharing plan, stock ownership or purchase plan, stock option plan, or life, medical or disability insurance plan), which would adversely affect the Employee's rights or benefits thereunder, unless such change occurs pursuant to a program or a plan amendment or termination that is applicable to all senior executive officers of the Company and does not result in a proportionately greater reduction in the rights of or benefits to the Employee as compared to any other senior executive officer of the Company. "Related Parties" means the Company and its subsidiaries and other affiliates. A "Triggering Event" shall be deemed to have occurred if: (i) individuals who, as of the date hereof, constitute the Company's Board of Directors (the "Incumbent Board") cease for any reason to constitute at least fifty-one percent (51%) of the Company's Board, provided that any person becoming a director subsequent to the date hereof whose election, or nomination for election by the Company's stockholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be, for purposes of this Agreement, considered as though such person were a member of the Incumbent Board; (ii) the stockholders of the Company shall approve a reorganization, merger or consolidation, in any case, with respect to which persons who were the stockholders of the Company immediately prior to such reorganization, merger or consolidation do not, immediately thereafter, own outstanding voting securities representing at least fifty-one percent (51%) of the combined voting power entitled to vote generally in the election of the directors ("Voting Securities") of the resulting reorganized, merged or consolidated company; 2

(iii) the stockholders of the Company shall approve a liquidation or dissolution of the Company or a sale of all or substantially all of the Company's assets to a non-Related Party; or (iv) any "person," as that term is defined in Section 3(a)(9) of the Securities Exchange Act of 1934, as amended (the "Exchange Act") (other than the Company, any other Related Party, any employee benefit plan of the Company or any of its Related Parties, or any entity organized, appointed or established by the Company for or pursuant to the terms of such a plan), together with all "affiliates" and "associates" (as such terms are defined in Rule 12b-2 under the Exchange Act) of such person (as well as any "person" or "group" as those terms are used in Sections 13(d) and 14(d) of the Exchange Act and the rules promulgated thereunder), shall become the "beneficial owner" or "beneficial owners" (as defined in Rules 13d-3 and 13d-5 under the Exchange Act), directly or indirectly, of securities of the Company representing in the aggregate twenty-five percent (25%) or more of either (A) the then outstanding shares of Common Stock or (B) the Voting Securities of the Company, in either such case other than solely as a result of acquisitions of such securities directly from the Company. Without limiting the foregoing, a person who, directly or indirectly, through any contract, arrangement, understanding, relationship or otherwise has or shares the power to vote, or to direct the voting of, or to dispose, or to direct the disposition of, Common Stock or other Voting Securities of the Company shall be deemed the beneficial owner of such Common Stock or Voting Securities. Notwithstanding the foregoing, a "Triggering Event" shall not be deemed to have occurred for purposes of subparagraph (iv) of this definition solely as the result of an acquisition of securities by the Company which, by reducing the number of shares of Common Stock or other Voting Securities of the Company outstanding, increases (i) the proportionate number of shares of Common Stock beneficially owned by any person to twenty-five percent (25%) or more of the shares of Common Stock then outstanding or (ii) the proportionate voting power represented by the Voting Securities of the Company beneficially owned by any person to twenty-five percent (25%) or more of the combined voting power of all then outstanding Voting Securities; provided, however, that if any person referred to in clause (i) or (ii) of this sentence shall thereafter become the beneficial owner of any additional shares of Common Stock or other Voting Securities of the Company (other than a result of a stock split, stock dividend or similar transaction), then a Triggering Event shall be deemed to have occurred. 2. EMPLOYMENT. ---------- The Company hereby employs the Employee and the Employee hereby accepts employment on the terms and conditions set forth herein. 3. TERM. ---- The initial term of this Agreement shall be from the date hereof until the third anniversary hereof, unless sooner terminated in accordance with the provisions herein regarding termination. 3

Subject to earlier termination as provided herein, the initial three year term of this Agreement shall be automatically extended for successive one year extensions, beginning on the date of the first anniversary of this Agreement and on each anniversary thereafter, unless either the Employee or the Company gives written notice to the other at least six months prior to such anniversary. 4. COMPENSATION. ------------ (a) BASE SALARY. For all services rendered by the Employee under this Agreement, the Company shall pay the Employee a base salary of Four Hundred Seventy-Five Thousand Dollars ($475,000) per year. Such salary: (i) shall be payable in equal installments in accordance with the customary payroll policies of the Company in effect at the time such payment is made, or as otherwise mutually agreed upon, and (ii) may, in the sole discretion of the Company's Board of Directors, be increased in future years. (b) ANNUAL TARGET BONUS. Effective for the Company's fiscal year ending December 31, 2001 and continuing with respect to each subsequent fiscal year thereafter during the term of this Agreement, Employee will be eligible for a "target bonus," under the Company's annual incentive bonus plan in effect at the applicable time, of up to seventy percent (70%) of Employee's base salary in effect at the applicable time. For the Company's fiscal year ending December 31, 2000, Employee's bonus shall not be less than the mathematical product of Three Hundred Thousand Dollars ($300,000) multiplied by a fraction of which (i) the numerator is the number of days during such fiscal year that the Employee is employed by the Company and (ii) the denominator is 365. The Employee's bonus pursuant to this Subsection 4(b) shall be earned as of the end of the Company's relevant fiscal year and payable in accordance with the customary policies of the Company in effect at the time for the Company's other senior executive officers. (c) BENEFITS. The Employee shall be entitled to participate in or receive benefits under any employee benefit plan or arrangements made available by the Company in the future to its senior executive officers, subject to and on a basis consistent with the terms, conditions and overall administration of such plan or arrangement. Nothing paid to the Employee under any plan or arrangement presently in effect or made available in the future shall be deemed to be in lieu of the salary and bonuses payable to the Employee pursuant to Subsections 4(a) and 4(b). (d) STOCK OPTION. In consideration of the Employee's execution of this Agreement, the Company will grant a non-qualified stock option to purchase Eighty Thousand (80,000) shares of the Common Stock to the Employee (the "Initial Options") pursuant to the Noble Affiliates, Inc. 1992 Stock Option and Restricted Stock Plan (the "Option Plan"). Such option shall vest and become exercisable in three equal annual installments. The exercise price for such option will be the Fair Market Value (as determined under the Option Plan) of the Common Stock on the date of grant, such grant to be made within one week following the commencement of the Employee's employment with the Company. The option to purchase 80,000 shares of the Common Stock is intended to encompass Employee's option grants during the calendar year 2000, and, while the Board of Directors could award additional options to the Employee during such period, there is no present intention to do so even though options may be awarded to other executives of the Company 4

during such time period. Beginning with calendar year 2001, Employee will be eligible to participate in the Option Plan under the same terms and conditions in effect for the Company's other senior executive officers. (e) EXPENSES. Upon receipt of itemized vouchers, expense account reports, and supporting documents submitted to the Company in accordance with the Company's procedures from time to time in effect, the Company shall reimburse Employee for all reasonable and necessary travel, entertainment, and other reasonable and necessary business expenses incurred ordinarily and necessarily by Employee in connection with the performance of his duties hereunder. (f) VACATION. Employee shall be entitled to a minimum of five (5) weeks paid vacation during each twelve month period commencing on the effective date of this Agreement. 5. POSITION, DUTIES, EXTENT OF SERVICES AND SITUS. ---------------------------------------------- (a) POSITION AND DUTIES. Employee shall serve as the President and Chief Executive Officer of the Company. (b) EXTENT OF SERVICES. The Employee shall devote all of his business time, attention, and energy to the business and affairs of the Company and shall not during the term of his employment under this Agreement engage in any other business activity which could constitute a conflict of interest, whether or not such business activity is pursued for gain, profit, or other pecuniary advantage. This shall not be construed as preventing the Employee from serving on the Boards of Directors of other companies or from managing his current investments or investing his assets in such form or manner as will not require any services on the part of the Employee in the operation and the affairs of the companies in which such investments are made, subject to the provisions of Section 6 hereof. 6. NON-SOLICITATION; CONFIDENTIALITY AND PENDING PROSPECTS. ------------------------------------------------------- (a) The Employee acknowledges that (i) as a result of his position with the Company he will receive specialized and unique knowledge concerning the Company, its business, its customers and the industry in which it competes, (ii) the Company's business, in large part, depends upon its exclusive possession and use of its proprietary information, (iii) the Company is entitled to protection against the unauthorized disclosure or use by Employee of its proprietary information, and (iv) he has received in this Agreement good and valuable consideration for the covenants he is making in this Section 6. (b) For a period of twenty-four (24) months after the termination of Employee's employment with the Company, the Employee shall not, without the written consent of the Company: solicit, entice, persuade or induce, directly or indirectly, any individual (or person who within the preceding ninety (90) days was an employee) of any of the Related Parties or any other person who is under contract with or rendering services to any of the Related Parties, to (i) terminate his or her employment by, or contractual relationship with, a Related Party, (ii) refrain from 5

extending or renewing the same (upon the same or new terms), (iii) refrain from rendering services to or for a Related Party, (iv) become employed by or to enter into contractual relations with any party other than a Related Party, or (v) enter into a relationship with a competitor of any of the Related Parties. (c) Employee recognizes and acknowledges that the Company would suffer irreparable harm and substantial loss if Employee violated any of the terms and provisions of this Section 6 and that the actual damages which might be sustained by the Company as the result of any breach of this Section 6 would be difficult to ascertain. Employee agrees, at the election of the Company and in addition to, and not in lieu of, the Company's right to terminate Employee's employment and to seek all other remedies and damages which the Company may have at law and/or equity for such breach, that the Company shall be entitled to an injunction restraining Employee from breaching any of the terms or provisions of this Section 6. (d) During the time of Employee's employment with the Company and for a period of one (1) year thereafter, Employee will not compete with the Company for any acquisition, prospect or project that the Company was pursuing prior to Employee's termination, and Employee shall hold in strict confidence and shall not, directly or indirectly, disclose or reveal to any person, or use for his own personal benefit or for the benefit of anyone else, any trade secrets, confidential dealings, or other confidential or proprietary information of any kind, nature, or description (whether or not acquired, learned, obtained, or developed by Employee alone or in conjunction with others) belonging to or concerning the Company or any other Related Party, except (i) with the prior written consent of the Company duly authorized by its Board of Directors, (ii) in the course of the proper performance of Employee's duties hereunder, (iii) for information (x) that becomes generally available to the public other than as a result of unauthorized disclosure by Employee or his affiliates or (y) that becomes available to Employee on a non-confidential basis from a source, other than the Company, who is not bound by a duty of confidentiality, or by any other contractual, legal, or fiduciary obligation, to the Company, or (iv) as required by applicable law or legal process. 7. DISABILITY. ---------- Employee shall be entitled to participate in, and receive coverage under, as applicable, any disability plan made available to the Company's senior executive officers from time to time. The Company shall have the right immediately to terminate the Employee's employment under this Agreement upon the "Complete Disability" of the Employee as hereinafter defined. The term "Complete Disability" as used in this Section 7 shall mean (i) the total inability of the Employee, despite any reasonable accommodation required by law, due to bodily injury or disease or any other physical or mental incapacity, to perform the services provided for hereunder for a period of one hundred twenty (120) days in the aggregate, within any given period of one hundred eighty (180) consecutive days during the term of this Agreement, in addition to any statutorily required leave of absence, and (ii) where such inability will, in the opinion of a qualified physician selected by the Company's Board of Directors, be permanent and continuous during the remainder of Employee's life. 6

8. DEATH. ----- If the Employee dies during the term of his employment, the Company shall pay to such person as the Employee shall designate in a notice filed with the Company, or, if no such person shall be designated, to Employee's estate as a death benefit, any payments the Employee's spouse, beneficiaries, or estate may be entitled to receive pursuant to any pension or employee benefit plan or life insurance policy maintained by the Company at such time for its senior executive officers, and, except for any obligations of the Company under Sections 22 and 25, all other obligations of the Company hereunder shall cease at the time of the Employee's death. 9. TERMINATION. ----------- 9.1 TERMINATION PRIOR TO A TRIGGERING EVENT. (a) Upon at least thirty (30) days' prior written notice to the Employee and prior to a Triggering Event, the Company may terminate the Employee's employment with the Company under this Agreement for Cause or in accordance with Section 7 and, subject to the provisions of Sections 22 and 25, with no liability on its part for further payments to the Employee (other than accrued and unpaid salary through the termination date). The Company may effect a termination for Cause pursuant to this Subsection 9.1(a) only by the affirmative vote of a majority of the members of the Board of Directors of the Company. In voting upon such termination for Cause, if the Employee is also a member of the Board of Directors of the Company, then he may not vote on, and will not be considered present for any purpose with respect to, a matter presented to the Board of Directors of the Company pursuant to this Subsection 9.1(a). (b) Prior to a Triggering Event, the Employee may terminate his employment with the Company under this Agreement by giving at least six (6) months' prior written notice of his desire to terminate employment to the Board of Directors of the Company. If the Employee's employment with the Company under this Agreement is terminated pursuant to this Subsection 9.1(b), the Employee will continue to accrue and receive his base salary in effect at the time pursuant to Subsection 4(a) through the date of termination specified in such notice with no liability on the part of the Company for further payments to the Employee, subject to the provisions of Sections 22 and 25. (c) Prior to a Triggering Event, if the Employee's employment with the Company is terminated by the Company without Cause or if the Employee terminates his employment with the Company following the occurrence of an Event of Default which has not been waived in writing by the Employee, the Employee will continue to accrue and receive his base salary in effect at the time pursuant to Subsection 4(a) through the date of termination and , unless the Employee's employment is terminated in accordance with Section 7, will be entitled to receive the benefits provided for under Subsection 10.1 with no liability on the part of the Company for further payments to the Employee, subject to the provisions of Sections 22 and 25. 9.2 TERMINATION ON OR AFTER A TRIGGERING EVENT. (a) Upon at least thirty (30) days' prior written notice to the Employee and on or after a Triggering Event, the Company may terminate the Employee's employment with the Company under this Agreement for Cause or in accordance with 7

Section 7 and, subject to the provisions of Sections 22 and 25, with no liability on its part for further payments to the Employee (other than accrued and unpaid salary through the termination date). The Company may effect a termination for Cause pursuant to this Subsection 9.2(a) only by the affirmative vote of a majority of the members of the Board of Directors of the Company. In voting upon such termination for Cause, if the Employee is also a member of the Board of Directors of the Company, then he may not vote on, and will not be considered present for any purpose with respect to, a matter presented to the Board of Directors of the Company pursuant to this Subsection 9.2(a). (b) On or after a Triggering Event, if the Employee's employment with the Company is terminated by the Company without Cause or if the Employee terminates his employment with the Company for Good Reason, the Employee will continue to accrue and receive his base salary in effect at the time pursuant to Subsection 4(a) through the date of termination and, unless the Employee's employment is terminated in accordance with Section 7, will be entitled to receive the payments and benefits provided for under Subsections 10.2 and 10.3 with no liability on the part of the Company for further payments to the Employee, subject to the provisions of Sections 22 and 25. (c) On or after a Triggering Event, the Employee may, in his sole and absolute discretion and without any prior approval by the Board of Directors of the Company, and upon six (6) months' prior written notice to the Board of Directors of the Company, terminate his employment with the Company under this Agreement for any reason whatsoever. If the Employee's employment with the Company under this Agreement is terminated pursuant to this Subsection 9.2(c), the Employee will continue to accrue and receive his base salary in effect at the time pursuant to Subsection 4(a) through the date of termination specified in such notice with no liability on the part of the Company for further payments to the Employee, subject to the provisions of Sections 22 and 25. 10. COMPENSATION AFTER CERTAIN TERMINATIONS. --------------------------------------- 10.1 REMAINING COMPENSATION. If the Employee's employment with the Company is terminated pursuant to Subsection 9.1(c), then, within five days after the date of such termination, the Remaining Compensation (as herein defined) shall become due and payable and shall be paid to the Employee in a single lump sum in cash. For purposes of this Subsection 10.1, the "Remaining Compensation" shall mean the annual base salary for one year only payable to the Employee pursuant to Subsection 4(a) at the time of termination plus an amount representing any accrued and unpaid bonuses earned under Subsection 4(b). 10.2 POST TRIGGERING EVENT SEVERANCE. If, at any time on or within twenty-four (24) months after a Triggering Event, the Employee's employment with the Company is terminated by the Company without Cause or if the Employee terminates his employment with the Company for Good Reason, then: (i) within five days after the date of such termination, the Company shall pay the Employee a lump sum amount in cash equal to two and one-half (2.5) times the Annualized Compensation Amount, and 8

(ii) the vesting of all outstanding Initial Options then owned by Employee shall be accelerated so that all such options are immediately exercisable in accordance with their terms. 10.3 GROSS-UP PAYMENT. In the event that (i) the Employee becomes entitled to the payment provided under Section 10.2 of this Agreement (the "Change in Control Payment") and any of the Change in Control Payment will be subject to the tax (the "Excise Tax") imposed by Section 4999 of the Internal Revenue Code of 1986, as amended (the "Code"), or any successor provision, or (ii) any payments or benefits received or to be received by the Employee pursuant to the terms of any other plan, arrangement or agreement (the "Benefit Payments") will be subject to the Excise Tax, the Company shall pay to the Employee an additional amount (the "Gross-Up Payment") such that the net amount retained by the Employee, after deduction of any Excise Tax on the Change in Control Payment and the Benefit Payments, and any federal, state and local income tax and Excise Tax upon the payment provided for by this Section 10.3, shall be equal to the Change in Control Payment and the Benefit Payments, provided, however, that in determining the amount of the Gross- Up Payment, any Excise Tax on the Change in Control Payment and the Benefit Payments shall be determined using a rate no higher than twenty percent (20%). For purposes of determining whether any of the Change in Control Payment or the Benefit Payments will be subject to the Excise Tax and the amount of such Excise Tax, (i) any payments or benefits received or to be received by the Employee in connection with a change in control of the Company or the Employee's termination of employment (whether pursuant to the terms of this Agreement or any other plan, arrangement or agreement with the Company, any person whose actions result in change in control or any person affiliated with the Company or such persons) shall be treated as "parachute payments" within the meaning of Section 280G(b)(2) of the Code, and all "excess parachute payments" within the meaning of Section 280G(b)(1) shall be treated as subject to the Excise Tax, except to the extent that, in the opinion of tax counsel selected by the Board of Directors of the Company, such payments or benefits (in whole or in part) do not constitute parachute payments, or such excess payments (in whole or in part) represent reasonable compensation for services actually rendered within the meaning of Section 280G(b)(4) of the Code, (ii) the amount of the Change in Control Payment and the Benefit Payments that shall be treated as subject to the Excise Tax shall be equal to the lesser of (A) the total amount of the Change in Control Payment and the Benefits Payments or (B) the amount of excess parachute payments within the meaning of Sections 280G(b)(1) and (4) (after applying clause (i), above) and (iii) the value of any non-cash benefits or any deferred payment or benefit shall be determined by tax counsel, selected by the Board of Directors of the Company, in accordance with the principles of Sections 280G(d)(3) and (4) of the Code. For purposes of determining the amount of the Gross-Up Payment, the Employee shall be deemed to pay federal income taxes at the highest marginal rate of federal income taxation in the calendar year in which the Gross-Up Payment is to be made and state and local income taxes at the highest marginal rates of taxation in the state and locality of the Employee's residence on the date of termination, net of the maximum reduction in federal income taxes which could be obtained from deduction of such state and local taxes. In the event that the Excise Tax is subsequently determined to be less than the amount taken into account hereunder at the time of termination of the Employee's employment, the Employee shall repay to the Company at that time that amount of such reduction in Excise Tax as is finally determined to be the portion of the Gross-Up Payment attributable to such reduction plus interest on the amount of such 9

repayment at the rate provided in Section 1274(b)(2)(B) of the Code. In the event that the Excise Tax is determined to exceed the amount taken into account hereunder at the time of the termination of the Employee's employment (including by reason of any payment the existence or amount of which cannot be determined at the time of the Gross-Up Payment), the Company shall make an additional gross-up payment to the Employee in respect of such excess (plus any interest payable with respect to such excess) at the time that the amount of such excess is finally determined. 11. MITIGATION. ---------- The Employee shall not be required to mitigate the amount of any payment provided for in this Agreement by seeking other employment or otherwise, nor shall the amount of any payment provided for in this Agreement be reduced by any compensation earned by the Employee as the result of employment by another employer after the date of termination of Employee's employment with the Company, or otherwise. 12. ENTIRE AGREEMENT. ---------------- This Agreement embodies the entire agreement and understanding between the parties hereto with respect to the subject matter hereof and supersedes all prior negotiations, agreements, and understandings relating to such subject matter, and may be modified or amended only by an instrument in writing signed by the parties hereto. 13. LAW TO GOVERN. ------------- This Agreement is executed and delivered in the State of Texas and shall be governed, construed and, except as stated in Section 26, enforced in accordance with the internal laws of the State of Texas without regard to principles of conflicts of law that would require the application of the law of another jurisdiction. 14. ASSIGNMENT. ---------- This Agreement is personal to the parties, and neither this Agreement nor any interest herein may be assigned (other than by will or by the laws of descent and distribution) without the prior written consent of the parties hereto nor be subject to alienation, anticipation, sale, pledge, encumbrance, execution, levy, or other legal process of any kind against the Employee or any of his beneficiaries or any other person. Notwithstanding the foregoing, the Company shall be permitted to assign this Agreement to any corporation or other business entity succeeding to substantially all of the business and assets of the Company by merger, consolidation, sale of assets, or otherwise, if the Company obtains the assumption of this Agreement by such successor. 10

15. BINDING AGREEMENT. ----------------- Subject to the provisions of Section 14 of this Agreement, this Agreement shall be binding upon and shall inure to the benefit of the Company and the Employee and their respective representatives, successors, and assigns. 16. REFERENCES AND GENDER. --------------------- All references to "Sections" and "Subsections" contained herein are, unless specifically indicated otherwise, references to sections and subsections of this Agreement. Whenever herein the singular number is used, the same shall include the plural where appropriate, and words of either gender shall include the other gender where appropriate. 17. WAIVER. ------ No waiver of any right under this Agreement shall be deemed effective unless the same is set forth in writing and signed by the party giving such waiver, and no waiver of any right shall be deemed to be a waiver of any such right in the future. Only the Board of Directors of the Company has authority to waive any provision of this Agreement. 18. NOTICES. ------- Except as may be otherwise specifically provided in this Agreement, all notices required or permitted hereunder shall be in writing and will be deemed to be delivered on the third day following being deposited in the United States mail, postage prepaid, registered or certified mail, return receipt requested, and (i) if to the Company, to its principal business office to the attention of the Chairman of the Board and (ii) if to the Executive, if addressed to his last known home address, or at such other addresses as may have theretofore been specified by written notice delivered in accordance herewith. 19. OTHER INSTRUMENTS. ----------------- The parties hereto covenant and agree that they will execute such other and further instruments and documents as are or may become necessary or convenient to effectuate and carry out the terms of this Agreement. 20. HEADINGS. -------- The headings used in this Agreement are used for reference purposes only and do not constitute substantive matter to be considered the terms of this Agreement. 21. INVALID PROVISION. ----------------- Any clause, sentence, provision, section, subsection, or paragraph of this Agreement held by a court of competent jurisdiction to be invalid, illegal, or ineffective shall not impair, invalidate, or nullify the remainder of this Agreement, but the effect thereof shall be confined to the clause, sentence, provision, section, subsection, or paragraph so held to be invalid, illegal or ineffective. 11

22. RIGHTS UNDER PLANS AND PROGRAMS. ------------------------------- Unless expressly provided in this Agreement, no provision of this Agreement is intended, nor shall it be construed, to reduce or in any way restrict any benefit to which the Employee otherwise may be independently entitled under any other agreement, plan, arrangement, or program providing benefits for the Employee, and to the extent such other agreement, plan, arrangement, or program is made available to the Company's chief executive officer and the available provisions conflict with a provision of this Agreement, then such applicable provisions of such other agreement, plan, arrangement, or program shall control. 23. MULTIPLE COPIES. --------------- This Agreement may be executed simultaneously in one or more counterparts, each of which shall be deemed an original and all of which shall together constitute one and the same instrument. The terms of this Agreement shall become binding upon each party from and after the time that he or it executed a copy hereof. In like manner, from and after the time that any party executes a consent or other document, such consent or other document shall be binding upon such parties. 24. WITHHOLDING OF TAXES. -------------------- The Company may withhold from any amounts payable under this Agreement all federal, state, city, or other taxes as shall be required pursuant to any law or government regulation or ruling. 25. LEGAL FEES AND EXPENSES. ----------------------- Subject to Section 26 and any final, non-appealable determination by a court of competent jurisdiction, each party shall pay and be responsible for its legal fees and expenses incurred in connection with a dispute under this Agreement, including as a result of a party contesting the validity or enforceability of this Agreement. 26. ARBITRATION. ----------- ANY DISPUTE ARISING IN CONNECTION WITH THIS AGREEMENT OR IN ANY WAY ARISING OUT OF OR RELATED TO THE EMPLOYMENT RELATIONSHIP BETWEEN THE EMPLOYEE AND THE COMPANY, OR THE TERMINATION OF THAT RELATIONSHIP, INCLUDING ANY CLAIM OF UNLAWFUL DISCRIMINATION, SHALL BE FINALLY RESOLVED BY ARBITRATION IN HOUSTON, TEXAS, GOVERNED BY THE FEDERAL ARBITRATION ACT AND CONDUCTED PURSUANT TO AND IN ACCORDANCE WITH THE NATIONAL RULES FOR THE RESOLUTION OF EMPLOYMENT DISPUTES OF THE AMERICAN ARBITRATION ASSOCIATION. EITHER THE COMPANY OR THE EMPLOYEE MAY REQUEST ARBITRATION BY SENDING WRITTEN NOTICE TO THE OTHER PARTY. IN ANY SUCH ARBITRATION, THE ONLY ISSUES TO BE CONSIDERED AND DETERMINED BY THE ARBITRATOR(S) SHALL BE ISSUES PERTAINING TO LEGAL AND EQUITABLE RIGHTS AND OBLIGATIONS OF THE PARTIES UNDER THIS AGREEMENT AND ANY APPLICABLE LAW. A DECISION AND AWARD OF THE ARBITRATOR(S) SHALL BE FINAL, AND MAY BE ENTERED IN ANY COURT HAVING JURISDICTION THEREOF, AND APPLICATION MAY BE MADE TO SUCH COURT FOR JUDICIAL ACCEPTANCE AND/OR AN ORDER ENFORCING SUCH DECISION AND/OR AWARD. JUDICIAL REVIEW 12

OF ANY DECISION OR AWARD SHALL BE IN ACCORDANCE WITH THE FEDERAL ARBITRATION ACT, EXCEPT THAT REVIEW OF ANY AWARD OF PUNITIVE OR EXEMPLARY DAMAGES SHALL BE CONDUCTED AS IF THE AWARD OF SUCH DAMAGES WERE MADE BY A JURY SITTING IN A FEDERAL DISTRICT COURT IN HOUSTON, TEXAS. IN THE EVENT THE ARBITRATOR(S) DETERMINE THERE IS A PREVAILING PARTY IN THE ARBITRATION, THE PREVAILING PARTY SHALL RECOVER FROM THE LOSING PARTY ALL COSTS OF ARBITRATION, INCLUDING BUT NOT LIMITED TO THE FEES OF THE ARBITRATOR(S) AND REASONABLE ATTORNEYS' FEES INCURRED BY THE PREVAILING PARTY. THE PROVISIONS OF THIS SECTION 26 SHALL NOT BE CONSTRUED TO LIMIT OR TO PRECLUDE EITHER PARTY FROM BRINGING AN ACTION IN ANY COURT OF COMPETENT JURISDICTION FOR INJUNCTIVE RELIEF. IN WITNESS WHEREOF, the parties have executed this Agreement on the day and year first above written. NOBLE AFFILIATES, INC. By: /s/ Robert Kelley ------------------------------------------ Name: Robert Kelley ------------------------------------- Title: Chairman of the Board ------------------------------------ /s/ CHARLES D. DAVIDSON ------------------------------------------ CHARLES D. DAVIDSON 13

EXHIBIT 21 TO FORM 10-K SUBSIDIARIES STATE OF JURISDICTION OF NAME ORGANIZATION REF - -------------------------------------------- ------------------------ --- Noble Trading, Inc. Delaware (1) NPM, Inc. Delaware (1) Noble Gas Marketing, Inc. Delaware (1) Noble Gas Pipeline, Inc. Delaware (2) Samedan Oil Corporation Delaware (1) Samedan Oil of Canada, Inc. Delaware (3) Samedan of North Africa, Inc. Delaware (3) Samedan North Sea, Inc. Delaware (3) Samedan Oil of Indonesia, Inc. Delaware (3) Samedan Pipe Line Corporation Delaware (3) Samedan Royalty Corporation Delaware (3) Samedan of Tunisia, Inc. Delaware (3) Samedan, Mediterranean Sea, Inc. Delaware (3) EDC Ireland Cayman Islands (4) Samedan International Cayman Islands (4) Samedan Vietnam Limited Cayman Islands (4) Machalapower Cia. Ltda. Cayman Islands (5) Samedan, Mediterranean Sea Cayman Islands (5) Samedan Transfer Sub Cayman Islands (5) Atlantic Methanol Capital Company Cayman Islands (7) Samedan Methanol Cayman Islands (8) Atlantic Methanol Associates LLC Cayman Islands (9) Atlantic Methanol Production Company LLC Cayman Islands (10) AMPCO Marketing, L.L.C. Michigan (7) AMPCO Services, L.L.C. Michigan (7) Alba Associates LLC Cayman Islands (11) Alba Plant LLC Cayman Islands (12) Energy Development Corporation Delaware (3) Energy Development Corporation (Argentina), Inc. Delaware (6) Energy Development Corporation (China), Inc. Delaware (6) Energy Development Corporation (HIPS), Inc. Delaware (6) EDC Ecuador Ltd. Delaware (6) EDC Ecuador Limited Cayman Islands (16) EDC (Denmark) Inc. Delaware (13) EDC Australia Ltd. Delaware (6) EDC Portugal Ltd. Delaware (6) Gasdel Pipeline System Incorporated New Jersey (6) Producers Service, Inc. New Jersey (6) HGC, Inc. Delaware (6) EDC (UK) Limited Delaware (6) EDC (Europe) Limited United Kingdom (13) EDC (ISE) Limited United Kingdom (14) Brabant Oil Limited United Kingdom (14) EDC (Oilex) Limited United Kingdom (14) Burnside Overseas Exploration Ltd. United Kingdom (15)

REFERENCES: - ----------- (1) 100% directly owned by Noble Affiliates, Inc. (Registrant) (2) 100% directly owned by Noble Gas Marketing, Inc. (3) 100% directly owned by Samedan Oil Corporation (4) 100% directly owned by Samedan of North Africa, Inc. (5) 100% directly owned by Samedan International (6) 100% directly owned by Energy Development Corporation (7) 50% directly owned by Samedan of North Africa, Inc. (8) 100% directly owned by Atlantic Methanol Capital Company (9) 50% directly owned by Samedan Methanol (10) 90% directly owned by Atlantic Methanol Associates LLC (11) 34.7% directly owned by Samedan International (12) 80% directly owned by Alba Associates LLC (13) 100% directly owned by EDC (UK) Limited (14) 100% directly owned by EDC (Europe) Limited (15) 100% directly owned by Brabant Oil Limited (16) 100% directly owned by EDC Ecuador Ltd.

ARTHUR ANDERSEN CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our report dated January 26, 2001, included on page 31 of the Company's 2000 Form 10-K, into the previously filed Registration Statements on Form S-3 (File Nos. 333-18929 aned 333-82953) and on Form S-8 (File Nos. 333-39299, 2-64600, 2-81590, 33-32692, 2-66654 and 33-54084). /s/ Arthur Andersen LLP Arthur Andersen LLP Oklahoma City, Oklahoma March 12, 2001