-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, V/rwgGM/a/OyXCxsf+q/yJd8BgemPkQsoPNrh8G5mmqA/8XPQXONquCqoERbv16j QH4jMiKD18AHsMN+vbDsKw== 0000821189-01-500007.txt : 20010326 0000821189-01-500007.hdr.sgml : 20010326 ACCESSION NUMBER: 0000821189-01-500007 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 11 CONFORMED PERIOD OF REPORT: 20001231 FILED AS OF DATE: 20010323 FILER: COMPANY DATA: COMPANY CONFORMED NAME: EOG RESOURCES INC CENTRAL INDEX KEY: 0000821189 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 470684736 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-09743 FILM NUMBER: 1577563 BUSINESS ADDRESS: STREET 1: 1200 SMITH ST STREET 2: SUITE 300 CITY: HOUSTON STATE: TX ZIP: 77002-7361 BUSINESS PHONE: 7136517000 MAIL ADDRESS: STREET 1: 1200 SMITH STREET CITY: HOUSTON STATE: TX ZIP: 77002-7361 FORMER COMPANY: FORMER CONFORMED NAME: ENRON OIL & GAS CO DATE OF NAME CHANGE: 19920703 10-K 1 form10k2000.txt FORM 10-K SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 ------------------ Form 10-K ------------------ [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 [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission file number: 1-9743 EOG RESOURCES, INC. (Exact name of registrant as specified in its charter) Delaware 47-0684736 (State or other jurisdiction (I.R.S. Employer Identification No.) of incorporation or organization) 1200 Smith Street, Suite 300, Houston, Texas 77002-7361 (Address of principal executive offices) (zip code) Registrant's telephone number, including area code: 713-651-7000 Securities registered pursuant to Section 12(b) of the Act: Title of each class Name of each exchange on which registered ------------------- ----------------------------------------- Common Stock, $.01 par value New York Stock Exchange Preferred Share Purchase Rights New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None. Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (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 registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K [X]. Aggregate market value of the voting stock held by nonaffiliates of the registrant, based on the closing sale price in the daily composite list for transactions on the New York Stock Exchange on March 12, 2001 was $47.50. As of March 12, 2001, there were 116,731,591 shares of the registrant's Common Stock, $.01 par value, outstanding. Documents incorporated by reference. Portions of the following documents are incorporated by reference into the indicated parts of this report: 2000 Annual Report to Stockholders - Part I, II and IV; and Proxy Statement for the May 8, 2001 Annual Meeting of Shareholders to be filed within 120 days after December 31, 2000 ("Proxy Statement") - Part III. TABLE OF CONTENTS Page PART I Item 1. Business ..................................................... 1 General ..................................................... 1 Business Segments ........................................... 1 Exploration and Production .................................. 1 Marketing ................................................... 3 Wellhead Volumes and Prices,and Lease and Well Expenses ..... 4 Competition ................................................. 5 Regulation .................................................. 5 Relationship Between EOG and Enron Corp. .................... 7 Other Matters ............................................... 7 Current Executive Officers of the Registrant ................ 10 Item 2. Properties Oil and Gas Exploration and Production Properties and Reserves .................................................... 11 Item 3. Legal Proceedings ............................................ 14 Item 4. Submission of Matters to a Vote of Security Holders .......... 14 PART II Item 5. Market for the Registrant's Common Equity and Related Shareholder Matters ......................................... 14 Item 6. Selected Financial Data ...................................... 14 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations ................................... 14 Item 7A. Quantitative and Qualitative Disclosures About Market Risk ... 14 Item 8. Financial Statements and Supplementary Data .................. 15 Item 9. Disagreements on Accounting and Financial Disclosure.......... 15 PART III Item 10. Directors and Executive Officers of the Registrant ........... 15 Item 11. Executive Compensation ....................................... 15 Item 12. Security Ownership of Certain Beneficial Owners and Management .............................................. 15 Item 13. Certain Relationships and Related Transactions ............... 15 PART IV Item 14. Financial Statements and Financial Statement Schedule, Exhibits and Reports on Form 8-K ............................ 16 1 PART I ITEM 1. Business General EOG Resources, Inc., a Delaware corporation organized in 1985 ("EOG"), together with its subsidiaries, explores for, develops, produces and markets natural gas and crude oil primarily in major producing basins in the United States, as well as in Canada and Trinidad and, to a lesser extent, selected other international areas. EOG's principal producing areas are further described under "Exploration and Production" below. At December 31, 2000, EOG's estimated net proved natural gas reserves were 3,381 billion cubic feet ("Bcf") and estimated net proved crude oil, condensate and natural gas liquids reserves were 73 million barrels ("MMBbl") (see "Supplemental Information to Consolidated Financial Statements" on page 43 of EOG's 2000 Annual Report to Shareholders ("Annual Report to Shareholders")). At such date, approximately 56% of EOG's reserves (on a natural gas equivalent basis) was located in the United States, 15% in Canada and 29% in Trinidad. As of December 31, 2000, EOG employed approximately 850 persons, including foreign national employees. EOG's business strategy is to maximize the rate of return on investment of capital by controlling all operating and capital costs. This strategy is intended to enhance the generation of cash flow and earnings from each unit of production on a cost-effective basis. EOG focuses its drilling activity toward natural gas deliverability in addition to natural gas reserve replacement and to a lesser extent crude oil exploitation. EOG focuses on the cost-effective utilization of advances in technology associated with the gathering, processing and interpretation of three-dimensional seismic data, developing reservoir simulation models and drilling operations through the use of new and/or improved drill bits, mud motors, mud additives, formation logging techniques and reservoir fracturing methods. These advanced technologies are used, as appropriate, throughout EOG to reduce the risks associated with all aspects of oil and gas reserve exploration, exploitation and development. EOG implements its strategy by emphasizing the drilling of internally generated prospects in order to find and develop low cost reserves. EOG also makes selected tactical acquisitions that result in additional economies of scale or land positions with significant additional prospects. Achieving and maintaining the lowest possible operating cost structure that is consistent with prudent and safe operations are also important goals in the implementation of EOG's strategy. With respect to information on EOG's working interest in wells or acreage, "net" oil and gas wells or acreage are determined by multiplying "gross" oil and gas wells or acreage by EOG's working interest in the wells or acreage. Unless otherwise defined, all references to wells are gross. Business Segments EOG's operations are all natural gas and crude oil exploration and production related. Exploration and Production North America Operations EOG's North American operations are organized into eight largely autonomous business units or divisions, each focusing on one or more basins, utilizing personnel who have developed experience and expertise unique to the geology of the region, thereby leveraging EOG's knowledge and cost structure into enhanced returns on invested capital. At December 31, 2000, 85% of EOG's proved United States reserves (on a natural gas equivalent basis) was natural gas and 15% was crude oil, condensate and natural gas liquids. A substantial portion of EOG's United States natural gas reserves is in long-lived fields with well-established production histories. EOG believes that opportunities exist to increase production in many of these fields through continued infill and other development drilling. The following is a summary of significant developments during 2000 and certain drilling plans for 2001 for EOG's North American operating divisions. Midland, Texas Division. The division's operations primarily focus on the Southeastern New Mexico area, Val Verde Basin and Midland Basin of West Texas. During 2000, the Midland Division increased average daily production 31% from 111 million cubic feet equivalent ("MMcfe") per day in 1999 to 145 MMcfe per day in 2000. The division drilled 67 gross wells in 2000. In early 2000, the division completed a property trade with Burlington Resources Oil & Gas Company, which added approximately 170,000 acres in the Permian Basin to the division's net acreage. During 2000, three new exploration trends in the Permian Basin were defined and over 200,000 acres of new leasehold and seismic options were added in these areas. Plans for 2001 include drilling over 90 wells in the Permian Basin and acquiring new leasehold and new three-dimensional seismic in high potential trends. 2 Denver, Colorado Division. Key producing areas for the Denver Division are the Big Piney - LaBarge Platform; Vernal - Chapita/Natural Buttes; California - North Shafter; and Southwest Wyoming - Cepo/Cedar Chest. Net production in the division averaged 133 million cubic feet ("MMcf") per day of natural gas and 5.7 thousand barrels ("MBbl") per day of crude oil, condensate, and natural gas liquids in 2000. At December 31, 2000, natural gas deliverability net to EOG was approximately 140 MMcf per day. During 2000, the division drilled twelve successful wells in North Shafter. For 2001, the division plans to drill more wells in this area to continue to gather information and ultimately determine the size and potential of the oil field. During 2000, the division also integrated and merged 520 square miles of three-dimensional seismic data, covering the LaBarge Platform in Big Piney, Wyoming to identify and develop both shallow and deep exploratory prospects. The division plans to drill more than 200 wells during 2001. Oklahoma City/Mid-Continent Division. The Mid-Continent division's activities are concentrated in the Oklahoma and Texas panhandles and in the deeper Anadarko Basin. Production from the division is primarily from the Morrow, Toronto, and Council Grove formations. During 2000, the division drilled 105 gross wells replacing reserves by over 150%. During 2000, net production for the division averaged approximately 70 MMcf per day of natural gas and 0.7 MBbl per day of crude oil and condensate. The division assembled an additional 400,000 acres in the panhandle areas during 2000, and plans to drill over 150 wells during 2001. EOG anticipates an active Mid-Continent drilling program for several years. Tyler, Texas Division. The Tyler Division increased average daily production by 35% from 110 MMcfe per day in 1999 to 149 MMcfe per day in 2000. Key areas of production for the division are the Sabine Uplift Region, Upper Texas Coast and Mississippi Salt Basin. During 2000, the division assimilated and exploited properties in the Sabine Uplift Region which were acquired through a December 31, 1999 property trade. Net production for the division averaged approximately 113 MMcf per day of natural gas and 5.9 MBbl per day of crude oil, condensate and natural gas liquids in 2000. Plans are to drill another 50 wells in the Sabine Uplift areas, 20 wells in the Upper Texas and Louisiana Coastal areas, and 30 wells in the Mississippi Salt Basin during 2001. The division also plans to enter several new exploratory areas, including the Bossier play in Louisiana. Corpus Christi, Texas Division. The Corpus Christi Division's activities are focused in the Lobo/Roleta, Frio and Wilcox producing horizons in South Texas. The principal areas of activity are in the Frio trend in Matagorda County and the Lobo/Roleta trend which occurs primarily in Webb and Zapata Counties. Early in 2000, the division made a discovery of over 100 billion cubic feet equivalent ("Bcfe") in the Roleta trend. Two to three rigs drilled in the Roleta throughout the year, drilling 39 gross wells with a success rate of approximately 90%. The division exceeded 100% reserve replacement while increasing average daily production 21% from 152 MMcfe per day in 1999 to 184 MMcfe per day in 2000. The growth came from significant acreage that was added in three trends: the Lobo and Wilcox in South Texas and the Geopressured Frio along the Texas Gulf Coast. During 2000, the division identified seven fields with upside potential: Zwebb - Webb and Zapata Counties; El Huerfano - Zapata County; Pok-A-Dot - Zapata County; Tiffany - Webb County; Rosita - Duval County; Bucks Bayou North - Matagorda County; and Bay City Area - Matagorda County. Pittsburgh, Pennsylvania Division. This newest EOG division was added in late 2000 following the purchase of Somerset Oil & Gas Company, Inc., a small independent oil and gas operator in Appalachia with assets located primarily in Western Pennsylvania. The acquisition added approximately 150 Bcf of reserves and 400 Devonian drilling locations to EOG's portfolio. For 2001, the division plans to assemble a substantial acreage position for exploration plays, shoot additional two-dimensional seismic and drill at least four exploratory wells. In addition, the division will focus on completing its staffing to become a fully operational exploitation and exploration unit. Houston, Texas/Offshore Division. The Offshore Division focuses on the Gulf of Mexico Shelf in Texas and Louisiana. Two fields, Eugene Island 135 and Matagorda Island 623, account for a significant portion of the division's production. During 2000, total daily production averaged 91 MMcfe per day compared to 133 MMcfe per day in 1999 due primarily to approximately 28 MMcf per day of natural gas production that was traded on December 31, 1999. By year-end 2000, the division had replaced, through successful drilling, the reduction in volumes related to the property trade. During 2000, the division drilled or participated in five wells that resulted in an increase in production, including one exploratory discovery at Matagorda Island 704 which added 5 MMcf per day. Calgary, Canada Division. The Calgary Division is engaged in the exploration for and the development, production and marketing of natural gas, natural gas liquids and crude oil in Western Canada, principally in the provinces of Alberta, Saskatchewan, and Manitoba. The division conducts operations from offices in Calgary, Alberta. During 2000, the division was again successful with its strategy of drilling a large number of shallow gas wells in Western Canada, adding both production and reserves. The division increased production from 134 MMcfe per day in 1999 to 146 MMcfe per day in 2000 and set a division record by drilling 434 wells, most of which were shallow gas. Key producing areas were Sandhills, Blackfoot and Grande Prairie (Wapiti). Also in 2000, the division acquired a small Canadian producer, Q Energy Limited, which had assets adjacent to the division's existing Sandhills operation. For 2001, the division plans to drill at least 375 shallow gas wells in the Sandhills and 3 Blackfoot areas and carry out further seismic and aeromagnetic surveys on the Northwest Territories acreage where drilling is planned for early 2002. Outside North America Operations EOG has producing operations offshore Trinidad and is evaluating exploration, exploitation and development opportunities in selected other international areas. Trinidad. In November 1992, EOG was awarded a 95% working interest concession in the South East Coast Consortium ("SECC") Block offshore Trinidad, encompassing three undeveloped fields previously held by three government-owned energy companies. The Kiskadee and Ibis fields have since been developed, and the Oilbird field is anticipated to be developed within the next several years. Existing surplus processing and transportation capacity at the Pelican field facilities owned and operated by Trinidad and Tobago government-owned companies is being used to process and transport the production. Natural gas is being sold into the local market under a take-or-pay agreement with the National Gas Company of Trinidad and Tobago. In 2000, deliveries net to EOG averaged 125 MMcf per day of natural gas and 2.6 MBbl per day of crude oil and condensate. In 1996, EOG signed a production sharing contract with the Government of Trinidad and Tobago for the Modified U(a) Block where EOG holds a 100% working interest. The contract committed EOG to the acquisition of three-dimensional seismic data and the drilling of three wells. The first well, Osprey, was drilled in 1998 and was successful, encountering over 400 feet of net pay. This is the largest exploration discovery in EOG's history. During the fourth quarter of 1999, EOG drilled an unsuccessful exploration well, the Motmot, and in the first quarter of 2000, the Tanager well was determined to be unsuccessful. These wells fulfilled the drilling obligations on the block. In 2000, EOG drilled the successful appraisal development OA2 well, which resulted in an increase of booked reserves by 71 Bcfe to a field total of 746 Bcfe. At December 31, 2000, EOG held approximately 71,000 net undeveloped acres in Trinidad. In January 2000, EOG signed a 15-year natural gas supply contract for approximately 60 MMcf per day with the National Gas Company of Trinidad and Tobago. This natural gas will supply a 1,850 metric ton per day anhydrous ammonia plant that is to be constructed by Caribbean Nitrogen Company Limited, a Trinidadian company in which EOG has a 16% interest. Other International. EOG continues to evaluate other selected conventional natural gas and crude oil opportunities outside North America primarily by pursuing exploitation opportunities in countries where indigenous natural gas and crude oil reserves have been identified. Marketing Wellhead Marketing. EOG's North America wellhead natural gas production is currently being sold on the spot market and under long-term natural gas contracts at market responsive prices. In many instances, the long-term contract prices closely approximate the prices received for natural gas being sold on the spot market. Wellhead natural gas volumes from Trinidad are sold at prices that are based on a fixed price schedule with annual escalations. Prior to the Share Exchange (as described in "Relationship Between EOG and Enron Corp." on page 7) and under terms of the production sharing contracts, natural gas volumes in India were sold to a nominee of the Government of India at a price linked to a basket of world market fuel oil quotations with floor and ceiling limits. Substantially all of EOG's wellhead crude oil and condensate is sold under various terms and arrangements at market responsive prices. Other Marketing. EOG Resources Marketing, Inc. ("EOGM"), a wholly owned subsidiary of EOG, is a marketing company engaging in various marketing activities. Both EOG and EOGM contract to provide, under short and long-term agreements, natural gas to various purchasers and then aggregate the necessary supplies for the sales with purchases from various sources including third-party producers, marketing companies, pipelines or from EOG's own production and arrange for any necessary transportation to the points of delivery. In addition, EOGM has purchased and constructed several small gas gathering systems in order to facilitate its entry into the gas gathering business on a limited basis. Both EOG and EOGM utilize other short and long-term hedging and trading mechanisms including sales and purchases utilizing NYMEX-related commodity market transactions from time to time. These marketing activities have provided an effective balance in managing a portion of EOG's exposure to commodity price risks for both natural gas and crude oil and condensate wellhead prices. (See "Other Matters- Risk Management"). 4 Wellhead Volumes and Prices, and Lease and Well Expenses The following table sets forth certain information regarding EOG's wellhead volumes of and average prices for natural gas per thousand cubic feet ("Mcf"), crude oil and condensate, and natural gas liquids per barrel ("Bbl"), and average lease and well expenses per thousand cubic feet equivalent ("Mcfe"-natural gas equivalents are determined using the ratio of 6.0 Mcf of natural gas to 1.0 Bbl of crude oil, condensate or natural gas liquids) delivered during each of the three years in the period ended December 31, 2000. As a result of the consensus of Emerging Issues Task Force Issue 00-10, "Accounting for Shipping and Handling Fees and Costs," EOG reclassified all prior periods to reflect certain transportation expenses incurred as lease and well expenses, instead of deductions from revenues as previously reported. Year Ended December 31, --------------------------- 2000 1999 1998 ------ ------ ------ Natural Gas Volumes (MMcf per day) United States............................. 654 654 671(1) Canada..................................... 129 115 105 Trinidad................................... 125 123 139 India(2)................................... - 46 56 ----- ----- ----- Total.................................... 908 938 971 ===== ===== ===== Crude Oil and Condensate Volumes (MBbl per day) United States.............................. 22.8 14.4 14.0 Canada..................................... 2.1 2.6 2.6 Trinidad................................... 2.6 2.4 3.0 India(2)................................... - 4.1 5.1 ----- ----- ----- Total.................................... 27.5 23.5 24.7 ===== ===== ===== Natural Gas Liquids Volumes (MBbl per day) United States.............................. 4.0 2.6 2.9 Canada..................................... 0.7 0.8 1.0 ----- ----- ----- Total.................................... 4.7 3.4 3.9 ===== ===== ===== Average Natural Gas Prices ($/Mcf) United States.............................. $ 3.96 $ 2.20 $ 2.01(3) Canada..................................... 3.33 1.88 1.48 Trinidad................................... 1.17 1.08 1.06 India(2)................................... - 2.09 2.57 Composite................................ 3.49 2.01 1.85 Average Crude Oil and Condensate Prices ($/Bbl) United States.............................. $29.68 $18.55 $12.89 Canada..................................... 27.76 16.77 11.82 Trinidad................................... 30.14 16.21 12.26 India(2)................................... - 12.80 12.86 Composite................................ 29.57 17.12 12.69 Average Natural Gas Liquids Prices ($/Bbl) United States.............................. $20.45 $13.41 $ 9.50 Canada..................................... 16.75 8.23 5.32 Composite................................ 19.87 12.24 8.38 Lease and Well Expenses ($/Mcfe) United States.............................. $ .35 $ .33 $ .34 Canada..................................... .52 .46 .44 Trinidad................................... .16 .13 .12 India(2)................................... - .35 .34 Composite................................ .35 .33 .33 _______________________________________________________________________________ (1) Includes 48 MMcf per day delivered under the terms of a volumetric production payment agreement effective October 1, 1992, as amended. Delivery obligations were terminated in December 1998. (2) See "Relationship Between EOG and Enron Corp." regarding the Share Exchange Agreement on Page 7. (3) Includes an average equivalent wellhead value of $1.88 per Mcf for the volumes described in note (1).
5 Competition EOG actively competes for reserve acquisitions and exploration/exploitation leases, licenses and concessions, frequently against companies with substantially larger financial and other resources. To the extent EOG's exploration budget is lower than that of certain of its competitors, EOG may be disadvantaged in effectively competing for certain reserves, leases, licenses and concessions. Competitive factors include price, contract terms, and quality of service, including pipeline connection times and distribution efficiencies. In addition, EOG faces competition from other producers and suppliers, including competition from other world wide energy supplies, such as natural gas from Canada. Regulation United States Regulation of Natural Gas and Crude Oil Production. Natural gas and crude oil production operations are subject to various types of regulation, including regulation in the United States by state and federal agencies. United States legislation affecting the oil and gas industry is under constant review for amendment or expansion. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue and have issued rules and regulations which, among other things, require permits for the drilling of wells, regulate the spacing of wells, prevent the waste of natural gas and liquid hydrocarbon resources through proration and restrictions on flaring, require drilling bonds and regulate environmental and safety matters. The regulatory burden on the oil and gas industry increases its cost of doing business and, consequently, affects its profitability. A substantial portion of EOG's oil and gas leases in the Big Piney area and in the Gulf of Mexico, as well as some in other areas, are granted by the federal government and administered by the Bureau of Land Management (the "BLM") and the Minerals Management Service (the "MMS"), both federal agencies. Operations conducted by EOG on federal oil and gas leases must comply with numerous statutory and regulatory restrictions concerning the above and other matters. Certain operations must be conducted pursuant to appropriate permits issued by the BLM and the MMS. BLM and MMS leases contain relatively standardized terms requiring compliance with detailed regulations and, in the case of offshore leases, orders pursuant to the Outer Continental Shelf Lands Act (which are subject to change by the MMS). Such offshore operations are subject to numerous regulatory requirements, including the need for prior MMS approval for exploration, development, and production plans, stringent engineering and construction specifications applicable to offshore production facilities, regulations restricting the flaring or venting of production, and regulations governing the plugging and abandonment of offshore wells and the removal of all production facilities. Under certain circumstances, the MMS may require operations on federal leases to be suspended or terminated. Any such suspension or termination could adversely affect EOG's interests. The MMS amended the regulations governing the calculation of royalties and the valuation of crude oil produced from federal leases, effective June 1, 2000. The new rules modified the valuation procedures for both arm's-length and non-arm's-length crude oil transactions to decrease reliance on oil posted prices and assign a value to crude oil that, in the opinion of MMS, better reflects its market value. Two industry trade associations have sought judicial review of the new rules in federal district court. EOG cannot predict what effect the outcome of the litigation will be or what effect, if any, it will have on EOG's operations. In March 2000, a federal district court vacated MMS regulations which sought to clarify the types of costs that are deductible transportation costs for purposes of royalty valuation of production sold off the lease. In particular, MMS disallowed deduction of costs associated with marketer fees, cash out and other pipeline imbalance penalties, or long-term storage fees. The United States has appealed the district court ruling. EOG cannot predict what the outcome of the appeal will be or what effect, if any, it will have on EOG's operations. Sales of crude oil, condensate and natural gas liquids by EOG are made at unregulated market prices. The transportation and sale for resale of natural gas in interstate commerce are regulated pursuant to the Natural Gas Act of 1938 (the "NGA") and the Natural Gas Policy Act of 1978 (the "NGPA"). These statutes are administered by the Federal Energy Regulatory Commission (the "FERC"). Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act of 1989 deregulated natural gas prices for all "first sales" of natural gas, which includes all sales by EOG of its own production. All other sales of natural gas by EOG, such as those of natural gas purchased from third parties, remain jurisdictional sales subject to a blanket sales certificate under the NGA, which has flexible terms and conditions. Consequently, all of EOG's sales of natural gas currently may be made at market prices, subject to applicable contract provisions. EOG's jurisdictional sales, however, are subject to the future possibility of greater federal oversight, including the possibility the FERC might prospectively impose more restrictive conditions on such sales. 6 Since 1985, the FERC has endeavored to enhance competition in natural gas markets by making natural gas transportation more accessible to natural gas buyers and sellers on an open and nondiscriminatory basis. These efforts culminated in Order No. 636 and various rehearing orders ("Order No. 636"), which mandate a fundamental restructuring of interstate natural gas pipeline sales and transportation services, including the "unbundling" by interstate natural gas pipelines of the sales, transportation, storage, and other components of their service, and to separately state the rates for each unbundled service. Order No. 636 does not directly regulate EOG's activities, but has an indirect effect because of its broad scope. Order No. 636 has ended interstate pipelines' traditional role as wholesalers of natural gas, and substantially increased competition in natural gas markets. In spite of this uncertainty, Order No. 636 may enhance EOG's ability to market and transport its natural gas production, although it may also subject EOG to more restrictive pipeline imbalance tolerances and greater penalties for violation of such tolerances. EOG owns, directly or indirectly, certain natural gas pipelines that it believes meet the traditional tests the FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction under the NGA. State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels as a result of pipeline restructuring under Order No. 636. For example, the Texas Railroad Commission has approved changes to its regulations governing transportation and gathering services performed by intrastate pipelines and gatherers, which prohibit such entities from unduly discriminating in favor of their affiliates. EOG's gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. EOG's natural gas gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement, and management of facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. EOG cannot predict what effect, if any, such legislation might have on its operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes. The FERC recently began a broad review of its transportation regulations, including how they operate in conjunction with state proposals for retail gas marketing restructuring, whether to eliminate cost-of-service rates for short-term transportation, whether to allocate all short-term capacity on the basis of competitive auctions, and whether changes to its long-term transportation policies may also be appropriate to alleviate a market bias toward short-term contracts. This review culminated in part with the FERC's issuance of Order No. 637 on February 9, 2000. Order No. 637 revises the FERC's current regulatory framework for purposes of improving the efficiency of the market and providing captive pipeline customers with the opportunity to reduce their cost of holding long-term pipeline capacity while continuing to protect against the exercise of market power. Order No. 637 revises FERC pricing policy by waiving price ceilings for short-term released capacity for a two year period and permitting pipelines to file for peak/off-peak and term differentiated rate structures. Order No. 637 does not, however, require the allocation of all short-term capacity on the basis of competitive auctions--as had been proposed by the FERC. Order No. 637 adopts changes in regulations relating to scheduling procedures, capacity segmentation and pipeline penalties to improve the competitiveness and efficiency of the interstate pipeline grid. It also narrows pipeline customers' right of first refusal to remove economic biases in the current rule, while still protecting captive customers' ability to resubscribe to long-term capacity. Finally, it improves the FERC's reporting requirements to provide more transparent pricing information and permit more effective monitoring of the market. Appeals of Order No. 637 are pending court review. EOG cannot predict what the outcome of that review will be or what effect it will have on EOG's operations. While Order No. 637, and any subsequent FERC action will affect EOG only indirectly, the Order and related inquiries are intended to further enhance competition in natural gas markets, while maintaining adequate consumer protections. EOG cannot predict the effect that any of the aforementioned orders or the challenges to such orders will ultimately have on EOG's operations. Additional proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, the FERC and the courts. EOG cannot predict when or whether any such proposals or proceedings may become effective. It should also be noted that the natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less regulated approach currently being pursued by the FERC will continue indefinitely. Environmental Regulation. Various federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, affect EOG's operations and costs as a result of their effect on natural gas and crude oil exploration, development and production operations and could cause EOG to incur remediation or other corrective action costs in connection with a release of regulated substances, including crude oil, into the environment. In addition, EOG has acquired certain oil and gas properties from third parties whose actions with respect to the management and disposal or release of hydrocarbons or other wastes were not under EOG's control. Under environmental laws and regulations, EOG could be required to remove or remediate wastes disposed of or released by prior owners or operators. 7 Compliance with such laws and regulations increases EOG's overall cost of business, but has not had a material adverse effect on EOG's operations or financial condition. It is not anticipated, based on current laws and regulations, that EOG will be required in the near future to expend amounts that are material in relation to its total exploration and development expenditure program in order to comply with each environmental law and regulation, but inasmuch as such laws and regulations are frequently changed, EOG is unable to predict the ultimate cost of compliance. Canadian Regulation. In Canada, the petroleum industry is subject to extensive controls and operates under various provincial and federal legislation and regulations governing land tenure, royalties, taxes, production rates, operational standards, environmental protection, health and safety, exports and other matters. EOG operates within this regulatory framework and continues to monitor and evaluate the impact of the regulatory regime when determining parameters for engaging in oil and gas activities and investments in Canada. The price of natural gas and crude oil in Canada has been deregulated and is determined by market conditions and negotiations between buyers and sellers in a North American market place. The North American Free Trade Agreement supports the on-going cross-border commercial transactions of the natural gas and crude oil business. Various matters relating to the transportation and export of natural gas continue to be subject to regulation by provincial agencies and federally, by the National Energy Board; however, the North American Free Trade Agreement may have reduced the risk of altering existing cross-border commercial transactions through the assurance of fair implementation of regulatory changes, minimal disruption of contractual arrangements and the prohibition of discriminatory order restrictions and export taxes. Canadian governmental regulations may have a material effect on the economic parameters for engaging in oil and gas activities in Canada and may have a material effect on the advisability of investments in Canadian oil and gas drilling activities. EOG is monitoring political, regulatory and economic developments in Canada. Other International Regulation. EOG's exploration and production operations outside North America are subject to various types of regulations imposed by the respective governments of the countries in which EOG's operations are conducted, and may affect EOG's operations and costs within that country. EOG currently has operations offshore Trinidad. Relationship Between EOG and Enron Corp. On August 16, 1999, EOG and Enron Corp. closed the Share Exchange Agreement in which EOG acquired 62,270,000 shares of EOG's common stock out of 82,270,000 shares then owned by Enron Corp., and in return Enron Corp. received all of the stock of EOGI-India, Inc., a subsidiary of EOG ("Share Exchange"). EOGI-India, Inc. owned, through subsidiaries, all of EOG's assets and operations in India and China, and had received from EOG an indirect $600 million cash capital contribution, plus certain intercompany receivables, prior to the Share Exchange. EOG recognized a $575 million tax-free gain on the Share Exchange based on the fair value of the shares received, net of transaction fees of $14 million. On the closing of the Share Exchange, all of Enron Corp.'s officers and directors then serving as Company directors resigned from EOG's board. Following the closing of the Share Exchange, Enron Corp. sold 8,500,000 shares of Company stock pursuant to a public offering in which EOG also sold 27,000,000 shares of its common stock. Subsequent to the closing of the Share Exchange and the common stock offering, Enron Corp. sold securities that are mandatorily exchangeable at maturity into a minimum of 9,746,250 EOG shares and a maximum of 11,500,000 EOG shares, the latter being an amount equal to all of Enron Corp.'s remaining shares in EOG. The maturity date for these securities is July 31, 2002. EOG and Enron Corp. have in the past entered into material transactions and agreements incident to their respective businesses. Such transactions and agreements have related to, among other things, the purchase and sale of natural gas and crude oil, hedging and trading activities and the provision of certain corporate services. Many of these agreements are still in place, and EOG and Enron Corp. may enter into similar types of transactions and agreements in the future. EOG intends that the terms of any future transactions and agreements with Enron Corp. will be at least as favorable to EOG as could be obtained from other third parties. Other Matters Energy Prices. Since EOG is primarily a natural gas company, it is more significantly impacted by changes in natural gas prices than in the prices for crude oil, condensate or natural gas liquids. Average North America wellhead natural gas prices have fluctuated, at times rather dramatically, during the last three years. These fluctuations resulted in a 15% decrease in the average wellhead natural gas price for North America received by EOG from 1997 to 1998, an increase of 11% from 1998 to 1999, and an increase of 80% from 1999 to 2000. Wellhead natural gas volumes from Trinidad are sold at prices that are based on a fixed schedule with annual escalations. Due to the many uncertainties associated with the world political environment, the availabilities of other world wide energy supplies and the relative competitive relationships of the various energy sources in the view of the consumers, EOG is unable to predict what changes may occur in natural gas prices in the future. 8 Substantially all of EOG's wellhead crude oil and condensate is sold under various terms and arrangements at market responsive prices. Crude oil and condensate prices also have fluctuated during the last three years. Due to the many uncertainties associated with the world political environment, the availabilities of other world wide energy supplies and the relative competitive relationships of the various energy sources in the view of the consumers, EOG is unable to predict what changes may occur in crude oil and condensate prices in the future. Risk Management. EOG engages in price risk management activities from time to time primarily for non-trading and to a lesser extent for trading purposes. Derivative financial instruments (primarily price swaps and costless collars) are utilized for non-trading purposes to hedge the impact of market fluctuations of natural gas and crude oil market prices on net income and cash flow. At December 31, 2000, EOG had outstanding swap contracts covering notional volumes of approximately 0.7 million barrels ("MMBbl") of crude oil and condensate for 2001. EOG elected not to designate these crude oil swap contracts as a hedge of its 2001 crude oil production, and accordingly, is accounting for these swap contracts under mark-to- market accounting. At December 31, 2000, the fair value of these swap contracts was $0.4 million. In February 2001, EOG entered into price swap agreements covering notional volumes of 0.6 MMBbl of oil for the period March 2001 to December 2001 at an average price of $28.09 per Bbl and notional volumes of 100,000 million British thermal units of natural gas per day (MMBtu/d) for the months of April and May 2001 at an average price of $5.16 per MMBtu. EOG will account for these swap contracts under mark-to-market accounting. In February 2001, a Canadian subsidiary of EOG priced certain natural gas physical agreements for approximately 47,000 MMBtu/d for the months of April and May 2001 at an average NYMEX price of US$5.16 per MMBtu less applicable basis (location) adjustments. At December 31, 2000, based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2001 for which prices have not, in effect, been hedged using NYMEX-related commodity market transactions and long-term marketing contracts, EOG's price sensitivity for each $.10 per Mcf change in average wellhead natural gas prices is $19 million (or $0.16 per share) for net income and $19 million for current operating cash flow. EOG is not impacted as significantly by changing crude oil prices for those volumes not otherwise hedged. EOG's price sensitivity for each $1.00 per barrel change in average wellhead crude oil prices is $6 million (or $0.05 per share) for net income and $6 million for current operating cash flow. Tight Gas Sand Tax Credits(Section 29) and Severance Tax Exemption. United States federal tax law provides a tax credit for production of certain fuels produced from nonconventional sources (including natural gas produced from tight formations), subject to a number of limitations. Fuels qualifying for the credit must be produced from a well drilled or a facility placed in service after November 5, 1990 and before January 1, 1993, and must be sold before January 1, 2003. The credit, which is currently approximately $.52 per million British thermal units of natural gas, is computed by reference to the price of crude oil, and is phased out as the price of crude oil exceeds $23.50 in 1980 dollars (adjusted for inflation) with complete phaseout if such price exceeds $29.50 in 1980 dollars (similarly adjusted). Under this formula, the commencement of phaseout would be triggered if the average price for crude oil rose above approximately $47 per barrel in current dollars. Significant benefits from the tax credit have accrued and continue to accrue to EOG since a portion (and in some cases a substantial portion) of EOG's natural gas production from new wells drilled after November 5, 1990, and before January 1, 1993, on EOG's leases in several of EOG's significant producing areas qualify for this tax credit. In 1999 and 2000, EOG entered into arrangements with a third party whereby certain Section 29 credits were sold by EOG to the third party, and payments for such credits will be received on an as-generated basis. Natural gas production from wells spudded or completed after May 24, 1989 and before September 1, 1996 in tight formations in Texas qualifies for a ten-year exemption from severance taxes, subject to certain limitations, during the period beginning September 1, 1991 and ending August 31, 2001. In addition, natural gas production from qualifying wells spudded or completed after August 31, 1996 and before September 1, 2010 is entitled to use of a reduced severance tax rate. However, the cumulative value of the tax reduction cannot exceed 50 percent of the drilling and completion costs incurred on a well by well basis. Other. All of EOG's natural gas and crude oil activities are subject to the risks normally incident to the exploration for and development and production of natural gas and crude oil, including blowouts, cratering and fires, each of which could result in damage to life and property. Offshore operations are subject to usual marine perils, including hurricanes and other adverse weather conditions. EOG's activities are also subject to governmental regulations as well as interruption or termination by governmental authorities based on environmental and other considerations. In accordance with customary industry practices, 9 insurance is maintained by EOG against some, but not all, of the risks. Losses and liabilities arising from such events could reduce revenues and increase costs to EOG to the extent not covered by insurance. EOG's operations outside of North America are subject to certain risks, including expropriation of assets, risks of increases in taxes and government royalties, renegotiation of contracts with foreign governments, political instability, payment delays, limits on allowable levels of production and currency exchange and repatriation losses, as well as changes in laws, regulations and policies governing operations of foreign companies generally. 10 Current Executive Officers of the Registrant The current executive officers of EOG and their names and ages are as follows: Name Age Position Mark G. Papa............ 54 Chairman of the Board and Chief Executive Officer; Director Edmund P. Segner, III..... 47 President and Chief of Staff; Director Loren M. Leiker.......... 47 Executive Vice President, Exploration and Development Gary L. Thomas.......... 51 Executive Vice President, North America Operations Barry Hunsaker, Jr...... 50 Senior Vice President and General Counsel Timothy K. Driggers...... 39 Vice President, Accounting and Land Administration David R. Looney........... 44 Vice President, Finance Mark G. Papa was elected Chairman of the Board and Chief Executive Officer in August 1999, President and Chief Executive Officer and Director of EOG in September 1998, President and Chief Operating Officer in September 1997, President in December 1996 and was President--North America Operations from February 1994 to September 1998. From May 1986 through January 1994, Mr. Papa served as Senior Vice President--Operations. Mr. Papa joined Belco Petroleum Corporation, a predecessor of EOG, in 1981. Edmund P. Segner, III became President and Chief of Staff and Director of EOG in August 1999. He became Vice Chairman and Chief of Staff of EOG in September 1997. Mr. Segner was a director of EOG from January 1997 to October 1997. Prior to joining EOG, Mr. Segner was Executive Vice President and Chief of Staff of Enron Corp. Loren M. Leiker joined EOG in April 1989 as Senior Vice President, Exploration. He was elected Executive Vice President, Exploration in May 1998 and Executive Vice President, Exploration and Development in February 2000. Gary L. Thomas was elected Executive Vice President, North America Operations in May 1998. He was previously Senior Vice President and General Manager of EOG's Midland Division. Mr. Thomas joined a predecessor of EOG in July 1978. Barry Hunsaker, Jr. has been Senior Vice President and General Counsel since he joined EOG in May 1996. Prior to joining EOG, Mr. Hunsaker was a partner in the law firm of Vinson & Elkins L.L.P. Timothy K. Driggers was elected Vice President and Controller of EOG in October 1999 and was subsequently named Vice President, Accounting and Land Administration. He was Assistant Controller of Enron Corp. from October 1998 through September 1999. Mr. Driggers held management positions in the Financial Planning and Reporting Department of EOG from August 1995 through September 1998. Prior to joining EOG, Mr. Driggers was a Senior Audit Manager at Arthur Andersen LLP. David R. Looney was elected Vice President, Finance of EOG in August 1999. He joined EOG as Assistant Treasurer in February 1998. Prior to joining EOG, Mr. Looney spent over 17 years in the commercial banking industry, specializing in capital formation for companies involved in the energy industry. There are no family relationships among the officers listed, and there are no arrangements or understandings pursuant to which any of them were elected as officers. Officers are appointed or elected annually by the Board of Directors at its first meeting following the Annual Meeting of Shareholders, each to hold office until the corresponding meeting of the Board in the next year or until a successor shall have been elected, appointed or shall have qualified. 11 ITEM 2. Properties Oil and Gas Exploration and Production Properties and Reserves Reserve Information. For estimates of EOG's net proved and proved developed reserves of natural gas and liquids, including crude oil, condensate and natural gas liquids, see "Supplemental Information to Consolidated Financial Statements" in the Annual Report to Shareholders. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth in Supplemental Information to Consolidated Financial Statements represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and liquids, including crude oil, condensate and natural gas liquids, that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the amount and quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers normally vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities ultimately recovered. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based. In general, the volume of production from oil and gas properties owned by EOG declines as reserves are depleted. Except to the extent EOG acquires additional properties containing proved reserves or conducts successful exploration, exploitation and development activities, the proved reserves of EOG will decline as reserves are produced. Volumes generated from future activities of EOG are therefore highly dependent upon the level of success in finding or acquiring additional reserves and the costs incurred in so doing. EOG's estimates of reserves filed with other federal agencies agree with the information set forth in Supplemental Information to Consolidated Financial Statements. 12 Acreage. The following table summarizes EOG's developed and undeveloped acreage at December 31, 2000. Excluded is acreage in which EOG's interest is limited to owned royalty, overriding royalty and other similar interests. Developed Undeveloped Total --------------------- ---------------------- ---------------------- Gross Net Gross Net Gross Net ---------- ---------- ---------- ---------- ---------- ---------- United States Texas..................... 466,616 309,737 684,492 520,044 1,151,108 829,781 Wyoming................... 288,597 175,764 564,256 365,041 852,853 540,805 Offshore Gulf of Mexico... 290,890 80,827 382,525 249,452 673,415 330,279 Montana................... 119,566 560 268,313 209,702 387,879 210,262 New Mexico................ 112,863 55,799 222,803 121,575 335,666 177,374 Utah...................... 217,087 76,287 142,181 83,642 359,268 159,929 Pennsylvania.............. 67,637 67,637 82,500 82,500 150,137 150,137 Oklahoma.................. 120,012 66,442 147,082 79,650 267,094 146,092 California................ 2,801 1,549 90,741 81,012 93,542 82,561 South Dakota.............. - - 52,238 52,238 52,238 52,238 Kansas.................... 12,412 10,596 37,045 32,836 49,457 43,432 Mississippi............... 8,222 7,965 37,684 34,595 45,906 42,560 Colorado.................. 24,884 1,425 100,227 40,943 125,111 42,368 Louisiana................. 11,517 9,446 26,115 16,499 37,632 25,945 New York.................. - - 28,260 24,258 28,260 24,258 North Dakota.............. 3,170 976 3,490 3,227 6,660 4,203 Arkansas.................. 7,922 1,095 2,010 639 9,932 1,734 Other..................... 240 - 211 193 451 193 --------- --------- --------- --------- --------- --------- Total United States...... 1,754,436 866,105 2,872,173 1,998,046 4,626,609 2,864,151 Canada Saskatchewan.............. 354,506 321,788 205,567 196,248 560,073 518,036 Alberta................... 447,522 312,547 346,124 288,878 793,646 601,425 Manitoba.................. 12,103 10,269 21,849 20,649 33,952 30,918 British Columbia.......... 656 164 14,768 8,909 15,424 9,073 Northwest Territories..... - - 605,053 189,089 605,053 189,089 --------- --------- --------- --------- --------- --------- Total Canada............. 814,787 644,768 1,193,361 703,773 2,008,148 1,348,541 Other International Trinidad.................. 22,856 22,346 74,551 70,823 97,407 93,169 France.................... - - 168,032 168,032 168,032 168,032 Ghana..................... - - 1,899,743 474,936 1,899,743 474,936 --------- --------- --------- --------- --------- --------- Total Other International 22,856 22,346 2,142,326 713,791 2,165,182 736,137 --------- --------- --------- --------- --------- --------- Total................... 2,592,079 1,533,219 6,207,860 3,415,610 8,799,939 4,948,829 ========= ========= ========= ========= ========= =========
Producing Well Summary. The following table reflects EOG's ownership in gas and oil wells located in Texas, the Gulf of Mexico, Oklahoma, New Mexico, Utah, Pennsylvania, Wyoming, and various other states, Canada and Trinidad at December 31, 2000. Gross gas and oil wells include 233 with multiple completions. Productive Wells ---------------- Gross Net ------- ------- Gas ....................................... 7,921 5,881 Oil ....................................... 1,411 1,145 ------ ------ Total.................................... 9,332 7,026 ====== ====== 13 Drilling and Acquisition Activities. During the years ended December 31, 2000, 1999, and 1998 EOG spent approximately $687 million, $461 million and $769 million, respectively, for exploratory and development drilling and acquisition of leases and producing properties. EOG drilled, participated in the drilling of or acquired wells as set out in the table below for the periods indicated: Year Ended December 31, ---------------------------------------------------- 2000 1999 1998 ---------------- ---------------- --------------- Gross Net Gross Net Gross Net ------- -------- ------- ------- ------- ------ Development Wells Completed North America Gas............................... 743 611.93 613 515.64 478 402.80 Oil............................... 93 83.46 53 52.02 38 34.98 Dry............................... 51 44.03 68 58.43 79 62.16 ----- -------- ----- ------ ----- ------ Total........................... 887 739.42 734 626.09 595 499.94 Outside North America Gas............................... - - 6 2.00 - - Oil............................... - - 6 1.90 21 6.30 Dry............................... - - - - - - ----- -------- ----- ------ ----- ------ Total........................... - - 12 3.90 21 6.30 ----- -------- ----- ------ ----- ------ Total Development................ 887 739.42 746 629.99 616 506.24 ----- -------- ----- ------ ----- ------ Exploratory Wells Completed North America Gas............................... 19 11.85 21 14.57 5 4.40 Oil............................... 4 4.00 2 2.00 6 5.50 Dry............................... 26 20.00 19 14.55 22 15.70 ----- -------- ----- ------ ----- ------ Total........................... 49 35.85 42 31.12 33 25.60 Outside North America Gas............................... - - 1 0.30 1 1.00 Oil............................... - - - - 1 .90 Dry............................... 1 1.00 1 1.00 - - ----- -------- ----- ------ ----- ------ Total........................... 1 1.00 2 1.30 2 1.90 ----- -------- ----- ------ ----- ------ Total Exploratory................. 50 36.85 44 32.42 35 27.50 ----- -------- ----- ------ ----- ------ Total........................... 937 776.27 790 662.41 651 533.74 Wells in Progress at end of period.. 46 40.19 25 21.34 28 15.73 ----- -------- ----- ------ ----- ------ Total............................. 983 816.46 815 683.75 679 549.47 ===== ======== ===== ====== ===== ====== Wells Acquired* Gas............................... 1,315 985.37 576 380.01 333 317.23 Oil............................... 168 120.70 422 402.34 - 1.70 ----- -------- ----- ------ ----- ------ Total.......................... 1,483 1,106.07 998 782.35 333 318.93 ===== ======== ===== ====== ===== ======
__________________ *Includes the acquisition of additional interests in certain wells in which EOG previously owned an interest. All of EOG's drilling activities are conducted on a contract basis with independent drilling contractors. EOG owns no drilling equipment. 14 ITEM 3. Legal Proceedings The information required by this item is incorporated by reference from the Contingencies section of Note 7 of Notes to Consolidated Financial Statements included in the Annual Report to Shareholders. 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. PART II ITEM 5. Market for the Registrant's Common Equity and Related Shareholder Matters Information required by this item is incorporated by reference from page 53 of the Annual Report to Shareholders. ITEM 6. Selected Financial Data Information required by this item is incorporated by reference from page 52 of the Annual Report to Shareholders. ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Information required by this item is incorporated by reference from pages 18 through 23 of the Annual Report to Shareholders. Information Regarding Forward-Looking Statements This Annual Report on Form 10-K includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical facts, including, among others, statements regarding EOG's future financial position, business strategy, budgets, reserve information, projected levels of production, projected costs and plans and objectives of management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "strategy," "intend," "plan," "target" and "believe" or the negative of those terms or other variations of them or by comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning future operating results or the ability to increase reserves or to generate income or cash flows are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes its expectations reflected in forward-looking statements are based on reasonable assumptions, no assurance can be given that these expectations will be achieved. Important factors that could cause actual results to differ materially from the expectations reflected in the forward-looking statements include, among others: timing and extent of changes in commodity prices for crude oil, natural gas and related products and interest rates; extent of EOG's success in discovering, developing, marketing and producing reserves and in acquiring oil and gas properties; political developments around the world; and financial market conditions. In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements might not occur. EOG undertakes no obligations to update or revise its forward-looking statements, whether as a result of new information, future events or otherwise. ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk EOG's exposure to interest rate risk and commodity price risk is discussed respectively in the Financing and Outlook sections of the "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Capital Resources and Liquidity," which is incorporated by reference from pages page 22 of the Annual Report to Shareholders. EOG's exposure to foreign currency exchange rate risks and other market risks is insignificant. 15 ITEM 8. Financial Statements and Supplementary Data Information required by this item is incorporated by reference from portions of the Annual Report to Shareholders as indicated: Cross Reference to Applicable Sections Of Annual Report to Shareholders Page -------------------------------------- ---- Report of Independent Public Accountants.......................... 24 Consolidated Financial Statements................................. 26 Notes to Consolidated Financial Statements........................ 30 Supplemental Information to Consolidated Financial Statements..... 43 Unaudited Quarterly Financial Information......................... 51
ITEM 9. Disagreements on Accounting and Financial Disclosure None. PART III ITEM 10. Directors and Executive Officers of the Registrant The information required by this Item regarding directors is incorporated by reference from the Proxy Statement to be filed within 120 days after December 31, 2000, under the caption entitled "Election of Directors." See list of "Current Executive Officers of the Registrant" in Part I located elsewhere herein. ITEM 11. Executive Compensation The information required by this Item is incorporated by reference from the Proxy Statement to be filed within 120 days after December 31, 2000, under the caption "Compensation of Directors and Executive Officers." ITEM 12. Security Ownership of Certain Beneficial Owners and Management The information required by this Item is incorporated by reference from the Proxy Statement to be filed within 120 days after December 31, 2000, under the captions "Election of Directors" and "Compensation of Directors and Executive Officers." ITEM 13. Certain Relationships and Related Transactions The information required by this Item is incorporated by reference from the Proxy Statement to be filed within 120 days after December 31, 2000, under the caption "Certain Transactions." 16 PART IV ITEM 14. Financial Statements and Financial Statement Schedule, Exhibits and Reports on Form 8-K (a)(1) Financial Statements and Supplemental Data Cross Reference to Applicable Sections Of Annual Report to Shareholders Page -------------------------------------- ---- Consolidated Financial Statements............................... 26 Notes to Consolidated Financial Statements...................... 30 Supplemental Information to Consolidated Financial Statements... 43 Unaudited Quarterly Financial Information....................... 51
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To EOG Resources, Inc.: We have audited in accordance with auditing standards generally accepted in the United States, the financial statements included in EOG Resources, Inc.'s Annual Report to Shareholders, incorporated by reference in this Form 10-K, and have issued our report thereon dated February 15, 2001. Our audit was made for the purpose of forming an opinion on those statements taken as a whole. The schedule included in this item is the responsibility of the Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. ARTHUR ANDERSEN LLP Houston, Texas February 15, 2001 17 (a)(2) Financial Statement Schedule Schedule II EOG RESOURCES, INC. VALUATION AND QUALIFYING ACCOUNTS AND RESERVES For the Years Ended December 31, 2000, 1999 and 1998 (In Thousands) - ------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E - ------------------------------------------------------------------------------------------------- Additions Deductions For Balance at Charged to Purpose For Balance at Beginning of Costs and Which Reserves End of Description Year Expenses Were Created Year - ------------------------------------------------------------------------------------------------- 2000 Reserves deducted from assets to which they apply-- Revaluation of Accounts Receivable..... $ 1,060 $ 500 $ 2 $ 1,558 ======= ======= ======= ======= 1999 Reserves deducted from assets to which they apply-- Revaluation of Accounts Receivable..... $11,375 $ 1,972 $12,287 $ 1,060 ======= ======= ======= ======= 1998 Reserves deducted from assets to which they apply-- Revaluation of Accounts Receivable..... $ 7,025 $ 4,350 $ - $11,375 ======= ======= ======= =======
Other financial statement schedules have been omitted because they are inapplicable or the information required therein is included elsewhere in the consolidated financial statements or notes thereto. (a)(3) Exhibits See pages 18 through 22 for a listing of the exhibits. (b) Reports on Form 8-K No Current Reports on Form 8-K were filed by EOG during the three months ended December 31, 2000. 18 EXHIBITS Exhibits not incorporated herein by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated herein by reference to EOG's Form S-1 Registration Statement, Registration No. 33-30678, filed on August 24, 1989 ("Form S-1"), or as otherwise indicated. Exhibit Number Description 3.1(a) -- Restated Certificate of Incorporation (Exhibit 3.1 to Form S-1). 3.1(b) -- Certificate of Amendment of Restated Certificate of Incorporation (Exhibit 4.1(b) to Form S-8 Registration Statement No. 33-52201, filed February 8, 1994). 3.1(c) -- Certificate of Amendment of Restated Certificate of Incorporation (Exhibit 4.1(c) to Form S-8 Registration Statement No. 33-58103, filed March 15, 1995). 3.1(d) -- Certificate of Amendment of Restated Certificate of Incorporation, dated June 11, 1996 (Exhibit 3(d) to Form S-3 Registration Statement No. 333-09919, filed August 9, 1996). 3.1(e) -- Certificate of Amendment of Restated Certificate of Incorporation, dated May 7, 1997 (Exhibit 3(e) to Form S-3 Registration Statement No. 333-44785, filed January 23, 1998). 3.1(f) -- Certificate of Ownership and Merger, dated August 26, 1999 (Exhibit 3.1(f) to EOG's Annual Report on Form 10-K for the year ended December 31, 1999). 3.1(g) -- Certificate of Designations of Series E Junior Participating Preferred Stock, dated February 14, 2000 (Exhibit 2 to Form 8-A Registration Statement, filed February 18, 2000). 3.1(h) -- Certificate of Designation, Preferences and Rights of Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series B, dated July 19, 2000. (Exhibit 3.1(h) to EOG's Registration Statement on Form S-3 Registration Statement No. 333-46858, filed September 28, 2000) 3.1(i) -- Certificate of Designation, Preferences and Rights of the Flexible Money Market Cumulative Preferred Stock, Series D, dated July 25, 2000 (Exhibit 3.1(i) to EOG's Registration Statement on Form S-3 Registration Statement No. 333-46858, filed September 28,2000). 3.1(j) -- Certificate of Elimination of the Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series A, dated September 15, 2000 (Exhibit 3.1(j) to EOG's Registration Statement on Form S-3 Registration Statement No. 333-46858, filed September 28,2000) 3.1(k) -- Certificate of Elimination of the Flexible Money Market Cumulative Preferred Stock, Series C, dated September 15, 2000 (Exhibit 3.1(k) to EOG's Registration Statement on Form S-3 Registration Statement No. 333-46858, filed September 28,2000) 3.2 -- By-laws, dated August 23, 1989, as amended December 12, 1990, February 8, 1994, January 19, 1996, February 13, 1997, May 5, 1998, September 7, 1999 and February 14, 2000 (Exhibit 3.1 to EOG's Current Report on Form 8-K, filed February 18, 2000). 4.1(a) -- Specimen of Certificate evidencing the Common Stock (Exhibit 3.3 to EOG's Annual Report on Form 10-K for the year ended December 31, 1999). 4.1(b) -- Specimen of Certificate Evidencing Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series B (Exhibit 4.3(g) to EOG's Registration Statement on Form S-4 Registration Statement No. 333-36056, filed June 7, 2000).
19 Exhibit Number Description 4.1(c) -- Specimen of Certificate Evidencing Flexible Money Market Cumulative Preferred Stock, Series D (Exhibit 4.3(g) to EOG's Registration Statement on Form S-4 Registration Statement No. 333-36416, filed June 12, 2000). 4.2 -- Rights Agreement, dated as of February 14, 2000, between EOG and First Chicago Trust Company of New York, which includes the form of Rights Certificate as Exhibit B and the Summary of Rights to Purchase Preferred Shares as Exhibit C (Exhibit 1 to EOG's Registration Statement on Form 8-A, filed February 18, 2000). 4.3(a) -- Amended and Restated 1994 Stock Plan (Exhibit 4.3 to Form S-8 Registration Statement No. 33-58103, filed March 15, 1995). 4.3(b) -- Amendment to Amended and Restated 1994 Stock Plan, dated effective as of December 12, 1995 (Exhibit 4.3(a) to EOG's Annual Report on Form 10-K for the year ended December 31, 1995). 4.3(c) -- Amendment to Amended and Restated 1994 Stock Plan, dated effective as of December 10, 1996 (Exhibit 4.3(a) to Form S-8 Registration Statement No. 333-20841, filed January 31, 1997). 4.3(d) -- Third Amendment to Amended and Restated 1994 Stock Plan, dated effective as of December 9, 1997 (Exhibit 4.3(d) to EOG's Annual Report on Form 10-K for the year ended December 31, 1997). 4.3(e) -- Fourth Amendment to Amended and Restated 1994 Stock Plan, dated effective as of May 5, 1998 (Exhibit 4.3(e) to EOG's Annual Report on Form 10-K for the year ended December 31, 1998). 4.3(f) -- Fifth Amendment to Amended and Restated 1994 Stock Plan, dated effective as of December 8, 1998 (Exhibit 4.3(f) to EOG's Annual Report on Form 10-K for the year ended December 31, 1998). 4.4 -- Form of Rights Certificate (Exhibit 3 to EOG's Registration Statement on Form 8-A, filed February 18, 2000). 4.5 -- Indenture dated as of September 1, 1991, between EOG and Chase Bank of Texas National Association (formerly, Texas Commerce Bank National Association) (Exhibit 4(a) to EOG's Registration Statement on Form S-3 Registration Statement No. 33-42640, filed September 6, 1991). 4.6 -- Indenture dated as of _________, 2000, between EOG and The Bank of New York (Exhibit 4.6 to EOG's Registration Statement on Form S-3 Registration Statement No. 333-46858, filed September 28, 2000). 10.2(a) -- Stock Restriction and Registration Agreement dated as of August 23, 1989 (Exhibit 10.2 to Form S-1). 10.2(b) -- Amendment to Stock Restriction and Registration Agreement, dated December 9, 1997, between EOG and Enron Corp. (Exhibit 10.2(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 1997). 10.3 -- Tax Allocation Agreement, entered into effective as of the Deconsolidation Date, between Enron Corp., EOG, and the subsidiaries of EOG listed therein as additional parties (Exhibit 10.3 to EOG's Annual Report on Form 10-K for the year ended December 31, 1998). 10.4(a) -- Share Exchange Agreement, dated as of July 19, 1999, between Enron Corp. and EOG (Exhibit 2 to Form S-3 Registration Statement No. 333-83533, filed July 23, 1999).
20 Exhibit Number Description 10.4(b) -- Letter Amendment, dated July 30, 1999, to Share Exchange Agreement, between Enron Corp. and EOG (Exhibit 2.2 to EOG's Current Report on Form 8-K, filed August 31, 1999). 10.4(c) -- Letter Amendment, dated August 10, 1999, to Share Exchange Agreement, between Enron Corp. and EOG (Exhibit 2.3 to EOG's Current Report on Form 8-K, filed August 31, 1999). *10.4(d) -- Consent Agreement between EOG, Enron Corp., Enron Finance Partners, LLC, Enron Intermediate Holdings, LLC, Enron Asset Holdings, LLC and Aeneas, LLC, dated November 28, 2000. 10.14(a) -- 1993 Nonemployee Directors' Stock Option Plan (Exhibit 10.14 to EOG's Annual Report on Form 10-K for the year ended December 31, 1992). 10.14(b) -- First Amendment to 1993 Nonemployee Directors' Stock Option Plan (Exhibit 10.14(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 1996). 10.16 -- Interest Rate and Currency Exchange Agreement, dated as of June 1, 1991, between Enron Risk Management Services Corp. and Enron Oil & Gas Marketing, Inc. (Exhibit 10.17 to EOG's Annual Report on Form 10-K for the year ended December 31, 1991), Confirmation dated June 14, 1992 (Exhibit 10.17 to Form S-1 Registration Statement, No. 33-50462, filed August 5, 1992) and Confirmations dated March 25, 1991, April 25, 1991, and September 23, 1992 (assigned to Enron Risk Management Services Corp. by Enron Finance Corp. pursuant to an Assignment and Assumption Agreement, dated as of November 1, 1993, by and between Enron Finance Corp., Enron Risk Management Services Corp. and Enron Oil & Gas Marketing, Inc.). (Exhibit 10.16 to EOG's Annual Report on Form 10-K for the year ended December 31, 1993). 10.17 -- Assignment and Assumption Agreement, dated as of November 1, 1993, by and between Enron Oil & Gas Marketing, Inc., EOG and Enron Risk Management Services Corp. (Exhibit 10.17 to EOG's Annual Report on Form 10-K for the year ended December 31, 1993). 10.18 -- ISDA Master Agreement, dated as of November 1, 1993, between EOG and Enron Risk Management Services Corp., and Confirmation Nos. 1268.0, 1286.0, 1291.0, 1292.0, 1304.0, 1305.0, 1321.0, 1335.0, 1338.0, 1370.0, 1471.0, 1485.0, 1486.0, 1494.0, 1495.0, 1509.0, 1514.0, 1533.01, 1569.0, 1986.0, 2217.0, 2227.0, 2278.0, 2299.0, 2372.0, 2647.0 (Exhibit 10.18 to EOG's Annual Report on Form 10-K for the year ended December 31, 1993). 10.25 -- Enron Corp. 1991 Stock Plan (Exhibit 10.08 to Enron Corp. Annual Report on Form 10-K for the year ended December 31, 1991). 10.26 -- Enron Corp. 1988 Deferral Plan (Exhibit 10.49 to Form S-1). 10.28 -- Enron Executive Supplemental Survivor Benefits Plan Effective January 1, 1987 (Exhibit 10.51 to Form S-1). 10.34 -- 1992 Stock Plan (As Amended and Restated Effective June 28, 1999) (Exhibit A to EOG's Proxy Statement, dated June 4, 1999, with respect to EOG's Annual Meeting of Shareholders). 10.60 -- Services Agreement, dated January 1, 1997, between Enron Corp. and EOG (Exhibit 10.60 to EOG's Annual Report on Form 10-K for the year ended December 31, 1997). 10.61 -- Equity Participation and Business Opportunity Agreement, dated December 9, 1997, between EOG and Enron Corp. (Exhibit 10 to Form S-3 Registration Statement No. 333-44785, filed January 23, 1998).
21 Exhibit Number Description 10.63(a) -- 1996 Deferral Plan (Exhibit 10.63(a) to EOG's Annual Report on Form 10-K for the year ended December 31, 1997). 10.63(b) -- First Amendment to 1996 Deferral Plan, dated effective as of December 9, 1997 (Exhibit 10.63(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 1997). 10.63(c) -- Second Amendment to 1996 Deferral Plan, dated effective as of December 8, 1998 (Exhibit 10.63(c) to EOG's Annual Report on Form 10-K for the year ended December 31, 1998). 10.64(a) -- Executive Employment Agreement between EOG and Mark G. Papa, effective as of November 1, 1997 (Exhibit 10.64 to EOG's Annual Report on Form 10-K for the year ended December 31, 1997). 10.64(b) -- First Amendment to Executive Employment Agreement between EOG and Mark G. Papa, effective as of February 1, 1999 (Exhibit 10.64(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 1998). 10.64(c) -- Second Amendment to Executive Agreement between EOG and Mark G. Papa, effective as of June 28, 1999 (Exhibit 10.64(c) to EOG's Annual Report on Form 10-K for the year ended December 31, 1999). 10.65(a) -- Executive Employment Agreement between EOG and Edmund P. Segner, III, effective as of September 1, 1998 (Exhibit 10.65(a) to EOG's Annual Report on Form 10-K for the year ended December 31, 1998). 10.65(b) -- First Amendment to Executive Employment Agreement between EOG and Edmund P. Segner, III, effective as of February 1, 1999 (Exhibit 10.65(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 1998). 10.65(c) -- Second Amendment to Executive Employment Agreement between EOG and Edmund P. Segner, III, effective as of June 28, 1999 (Exhibit 10.65(c) to EOG's Annual Report on Form 10-K for the year ended December 31, 1999). 10.66(a) -- Executive Employment Agreement between EOG and Barry Hunsaker, Jr., effective as of September 1, 1998 (Exhibit 10.66(a) to EOG's Annual Report on Form 10-K for the year ended December 31, 1999). 10.66(b) -- First Amendment to Executive Employment Agreement between EOG and Barry Hunsaker, Jr., effective as of December 21, 1998 (Exhibit 10.66(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 1999). 10.66(c) -- Second Amendment to Executive Employment Agreement between EOG and Barry Hunsaker, Jr., effective as of February 1, 1999 (Exhibit 10.66(c) to EOG's Annual Report on Form 10-K for the year ended December 31, 1999). 10.67(a) -- Executive Employment Agreement between EOG and Loren M Leiker, effective as of March 1, 1998 (Exhibit 10.67(a) to EOG's Annual Report on Form 10-K for the year ended December 31, 1999). 10.67(b) -- First Amendment to Executive Employment Agreement between EOG and Loren M. Leiker, effective as of February 1, 1999 (Exhibit 10.67(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 1999). 10.68(a) -- Executive Employment Agreement between EOG and Gary L. Thomas, effective as of September 1, 1998 (Exhibit 10.68(a) to EOG's Annual Report on Form 10-K for the year ended December 31, 1999). 10.68(b) -- First Amendment to Executive Employment Agreement between EOG and Gary L. Thomas, effective as of February 1, 1999 (Exhibit 10.68(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 1999).
22 Exhibit Number Description *12 -- Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Dividends. *13 -- Annual Report to Shareholders *21 -- List of subsidiaries. *23.1 -- Consent of DeGolyer and MacNaughton. 23.2 -- Opinion of DeGolyer and MacNaughton dated February 8, 2000 (Exhibit 23.2 to EOG's Current Report on Form 8-K, filed on February 27, 2001). *23.3 -- Consent of Arthur Andersen LLP. *24 -- Powers of Attorney.
23 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, on the 23rd day of March, 2001. EOG RESOURCES, INC. (Registrant) By /s/TIMOTHY K. DRIGGERS --------------------------- (Timothy K. Driggers) Vice President Accounting and Land Administration (Principal Accounting Officer) Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of registrant and in the capacities with EOG Resources, Inc. indicated and on the 23rd day of March, 2001. Signature Title /s/ MARK G. PAPA Chairman and Chief Executive Officer and - --------------------------------- Director (Principal Executive Officer) (Mark G. Papa) /s/ TIMOTHY K. DRIGGERS Vice President Accounting - --------------------------------- and Land Administration (Timothy K. Driggers) (Principal Accounting Officer) /s/ DAVID R. LOONEY Vice President Finance - --------------------------------- (Principal Financial Officer) (David R. Looney) *EDMUND P. SEGNER, III President and Chief of Staff and Director - --------------------------------- (Edmund P. Segner, III) *FRED C. ACKMAN Director - --------------------------------- (Fred C. Ackman) *GEORGE A. ALCORN Director - --------------------------------- (George A. Alcorn) *EDWARD RANDALL, III Director - --------------------------------- (Edward Randall, III) *DONALD F. TEXTOR Director - --------------------------------- (Donald F. Textor) *FRANK G. WISNER Director - --------------------------------- (Frank G. Wisner) *By /s/ PATRICIA L. EDWARDS ------------------------------ (Patricia L. Edwards) (Attorney-in-fact for persons indicated)
EX-20 2 exhibitindex.txt INDEX OF EXHIBITS EOG RESOURCES, INC. AND SUBSIDIARIES EXHIBITS TO FORM 10-K For the Fiscal Year Ended December 31, 2000 EOG RESOURCES, INC. AND SUBSIDIARIES INDEX TO EXHIBITS Exhibit Number Description 3.1(a) -- Restated Certificate of Incorporation (Exhibit 3.1 to Form S-1). 3.1(b) -- Certificate of Amendment of Restated Certificate of Incorporation (Exhibit 4.1(b) to Form S-8 Registration Statement No. 33-52201, filed February 8, 1994). 3.1(c) -- Certificate of Amendment of Restated Certificate of Incorporation (Exhibit 4.1(c) to Form S-8 Registration Statement No. 33-58103, filed March 15, 1995). 3.1(d) -- Certificate of Amendment of Restated Certificate of Incorporation, dated June 11, 1996 (Exhibit 3(d) to Form S-3 Registration Statement No. 333-09919, filed August 9, 1996). 3.1(e) -- Certificate of Amendment of Restated Certificate of Incorporation, dated May 7, 1997 (Exhibit 3(e) to Form S-3 Registration Statement No. 333-44785, filed January 23, 1998). 3.1(f) -- Certificate of Ownership and Merger, dated August 26, 1999 (Exhibit 3.1(f) to EOG's Annual Report on Form 10-K for the year ended December 31, 1999). 3.1(g) -- Certificate of Designations of Series E Junior Participating Preferred Stock, dated February 14, 2000 (Exhibit 2 to Form 8-A Registration Statement, filed February 18, 2000). 3.1(h) -- Certificate of Designation, Preferences and Rights of Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series B, dated July 19, 2000. (Exhibit 3.1(h) to EOG's Registration Statement on Form S-3 Registration Statement No. 333-46858, filed September 28, 2000) 3.1(i) -- Certificate of Designation, Preferences and Rights of the Flexible Money Market Cumulative Preferred Stock, Series D, dated July 25, 2000 (Exhibit 3.1(i) to EOG's Registration Statement on Form S-3 Registration Statement No. 333-46858, filed September 28,2000). 3.1(j) -- Certificate of Elimination of the Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series A, dated September 15, 2000 (Exhibit 3.1(j) to EOG's Registration Statement on Form S-3 Registration Statement No. 333-46858, filed September 28,2000) 3.1(k) -- Certificate of Elimination of the Flexible Money Market Cumulative Preferred Stock, Series C, dated September 15, 2000 (Exhibit 3.1(k) to EOG's Registration Statement on Form S-3 Registration Statement No. 333- 46858, filed September 28,2000) 3.2 -- By-laws, dated August 23, 1989, as amended December 12, 1990, February 8, 1994, January 19, 1996, February 13, 1997, May 5, 1998, September 7, 1999 and February 14, 2000 (Exhibit 3.1 to EOG's Current Report on Form 8-K, filed February 18, 2000). 4.1(a) -- Specimen of Certificate evidencing the Common Stock (Exhibit 3.3 to EOG's Annual Report on Form 10-K for the year ended December 31, 1999). 4.1(b) -- Specimen of Certificate Evidencing Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series B (Exhibit 4.3(g) to EOG's Registration Statement on Form S- 4 Registration Statement No. 333-36056, filed June 7, 2000). INDEX TO EXHIBITS (Continued) Exhibit Number Description 4.1(c) -- Specimen of Certificate Evidencing Flexible Money Market Cumulative Preferred Stock, Series D (Exhibit 4.3(g) to EOG's Registration Statement on Form S-4 Registration Statement No. 333-36416, filed June 12, 2000). 4.2 -- Rights Agreement, dated as of February 14, 2000, between EOG and First Chicago Trust Company of New York, which includes the form of Rights Certificate as Exhibit B and the Summary of Rights to Purchase Preferred Shares as Exhibit C (Exhibit 1 to EOG's Registration Statement on Form 8-A, filed February 18, 2000). 4.3(a) -- Amended and Restated 1994 Stock Plan (Exhibit 4.3 to Form S-8 Registration Statement No. 33-58103, filed March 15, 1995). 4.3(b) -- Amendment to Amended and Restated 1994 Stock Plan, dated effective as of December 12, 1995 (Exhibit 4.3(a) to EOG's Annual Report on Form 10-K for the year ended December 31, 1995). 4.3(c) -- Amendment to Amended and Restated 1994 Stock Plan, dated effective as of December 10, 1996 (Exhibit 4.3(a) to Form S-8 Registration Statement No. 333-20841, filed January 31, 1997). 4.3(d) -- Third Amendment to Amended and Restated 1994 Stock Plan, dated effective as of December 9, 1997 (Exhibit 4.3(d) to EOG's Annual Report on Form 10-K for the year ended December 31, 1997). 4.3(e) -- Fourth Amendment to Amended and Restated 1994 Stock Plan, dated effective as of May 5, 1998 (Exhibit 4.3(e) to EOG's Annual Report on Form 10-K for the year ended December 31, 1998). 4.3(f) -- Fifth Amendment to Amended and Restated 1994 Stock Plan, dated effective as of December 8, 1998 (Exhibit 4.3(f) to EOG's Annual Report on Form 10-K for the year ended December 31, 1998). 4.4 -- Form of Rights Certificate (Exhibit 3 to EOG's Registration Statement on Form 8-A, filed February 18, 2000). 4.5 -- Indenture dated as of September 1, 1991, between EOG and Chase Bank of Texas National Association (formerly, Texas Commerce Bank National Association) (Exhibit 4(a) to EOG's Registration Statement on Form S-3 Registration Statement No. 33-42640, filed September 6, 1991). 4.6 -- Indenture dated as of _________, 2000, between EOG and The Bank of New York (Exhibit 4.6 to EOG's Registration Statement on Form S-3 Registration Statement No. 333-46858, filed September 28, 2000). 10.2(a) -- Stock Restriction and Registration Agreement dated as of August 23, 1989 (Exhibit 10.2 to Form S-1). 10.2(b) -- Amendment to Stock Restriction and Registration Agreement, dated December 9, 1997, between EOG and Enron Corp. (Exhibit 10.2(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 1997). 10.3 -- Tax Allocation Agreement, entered into effective as of the Deconsolidation Date, between Enron Corp., EOG, and the subsidiaries of EOG listed therein as additional parties (Exhibit 10.3 to EOG's Annual Report on Form 10-K for the year ended December 31, 1998). 10.4(a) -- Share Exchange Agreement, dated as of July 19, 1999, between Enron Corp. and EOG (Exhibit 2 to Form S-3 Registration Statement No. 333-83533, filed July 23, 1999). 10.4(b) -- Letter Amendment, dated July 30, 1999, to Share Exchange Agreement, between Enron Corp. and EOG (Exhibit 2.2 to EOG's Current Report on Form 8-K, filed August 31, 1999). 10.4(c) -- Letter Amendment, dated August 10, 1999, to Share Exchange Agreement, between Enron Corp. and EOG (Exhibit 2.3 to EOG's Current Report on Form 8-K, filed August 31, 1999). INDEX TO EXHIBITS (Continued) Exhibit Number Description *10.4(d) -- Consent Agreement between EOG, Enron Corp., Enron Finance Partners, LLC, Enron Intermediate Holdings, LLC, Enron Asset Holdings, LLC and Aeneas, LLC, dated November 28, 2000. 10.14(a) -- 1993 Nonemployee Directors' Stock Option Plan (Exhibit 10.14 to EOG's Annual Report on Form 10-K for the year ended December 31, 1992). 10.14(b) -- First Amendment to 1993 Nonemployee Directors' Stock Option Plan (Exhibit 10.14(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 1996). 10.16 -- Interest Rate and Currency Exchange Agreement, dated as of June 1, 1991, between Enron Risk Management Services Corp. and Enron Oil & Gas Marketing, Inc. (Exhibit 10.17 to EOG's Annual Report on Form 10-K for the year ended December 31, 1991), Confirmation dated June 14, 1992 (Exhibit 10.17 to Form S-1 Registration Statement, No. 33-50462, filed August 5, 1992) and Confirmations dated March 25, 1991, April 25, 1991, and September 23, 1992 (assigned to Enron Risk Management Services Corp. by Enron Finance Corp. pursuant to an Assignment and Assumption Agreement, dated as of November 1, 1993, by and between Enron Finance Corp., Enron Risk Management Services Corp. and Enron Oil & Gas Marketing, Inc.). (Exhibit 10.16 to EOG's Annual Report on Form 10-K for the year ended December 31, 1993). 10.17 -- Assignment and Assumption Agreement, dated as of November 1, 1993, by and between Enron Oil & Gas Marketing, Inc., EOG and Enron Risk Management Services Corp. (Exhibit 10.17 to EOG's Annual Report on Form 10-K for the year ended December 31, 1993). 10.18 -- ISDA Master Agreement, dated as of November 1, 1993, between EOG and Enron Risk Management Services Corp., and Confirmation Nos. 1268.0, 1286.0, 1291.0, 1292.0, 1304.0, 1305.0, 1321.0, 1335.0, 1338.0, 1370.0, 1471.0, 1485.0, 1486.0, 1494.0, 1495.0, 1509.0, 1514.0, 1533.01, 1569.0, 1986.0, 2217.0, 2227.0, 2278.0, 2299.0, 2372.0, 2647.0 (Exhibit 10.18 to EOG's Annual Report on Form 10-K for the year ended December 31, 1993). 10.25 -- Enron Corp. 1991 Stock Plan (Exhibit 10.08 to Enron Corp. Annual Report on Form 10-K for the year ended December 31, 1991). 10.26 -- Enron Corp. 1988 Deferral Plan (Exhibit 10.49 to Form S-1). 10.28 -- Enron Executive Supplemental Survivor Benefits Plan Effective January 1, 1987 (Exhibit 10.51 to Form S-1). 10.34 -- 1992 Stock Plan (As Amended and Restated Effective June 28, 1999) (Exhibit A to EOG's Proxy Statement, dated June 4, 1999, with respect to EOG's Annual Meeting of Shareholders). 10.60 -- Services Agreement, dated January 1, 1997, between Enron Corp. and EOG (Exhibit 10.60 to EOG's Annual Report on Form 10-K for the year ended December 31, 1997). 10.61 -- Equity Participation and Business Opportunity Agreement, dated December 9, 1997, between EOG and Enron Corp. (Exhibit 10 to Form S-3 Registration Statement No. 333-44785, filed January 23, 1998). 10.63(a) -- 1996 Deferral Plan (Exhibit 10.63(a) to EOG's Annual Report on Form 10-K for the year ended December 31, 1997). 10.63(b) -- First Amendment to 1996 Deferral Plan, dated effective as of December 9, 1997 (Exhibit 10.63(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 1997). 10.63(c) -- Second Amendment to 1996 Deferral Plan, dated effective as of December 8, 1998 (Exhibit 10.63(c) to EOG's Annual Report on Form 10-K for the year ended December 31, 1998). INDEX TO EXHIBITS (Continued) Exhibit Number Description 10.64(a) -- Executive Employment Agreement between EOG and Mark G. Papa, effective as of November 1, 1997 (Exhibit 10.64 to EOG's Annual Report on Form 10-K for the year ended December 31, 1997). 10.64(b) -- First Amendment to Executive Employment Agreement between EOG and Mark G. Papa, effective as of February 1, 1999 (Exhibit 10.64(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 1998). 10.64(c) -- Second Amendment to Executive Agreement between EOG and Mark G. Papa, effective as of June 28, 1999 (Exhibit 10.64(c) to EOG's Annual Report on Form 10-K for the year ended December 31, 1999). 10.65(a) -- Executive Employment Agreement between EOG and Edmund P. Segner, III, effective as of September 1, 1998 (Exhibit 10.65(a) to EOG's Annual Report on Form 10-K for the year ended December 31, 1998). 10.65(b) -- First Amendment to Executive Employment Agreement between EOG and Edmund P. Segner, III, effective as of February 1, 1999 (Exhibit 10.65(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 1998). 10.65(c) -- Second Amendment to Executive Employment Agreement between EOG and Edmund P. Segner, III, effective as of June 28, 1999 (Exhibit 10.65(c) to EOG's Annual Report on Form 10-K for the year ended December 31, 1999). 10.66(a) -- Executive Employment Agreement between EOG and Barry Hunsaker, Jr., effective as of September 1, 1998 (Exhibit 10.66(a) to EOG's Annual Report on Form 10-K for the year ended December 31, 1999). 10.66(b) -- First Amendment to Executive Employment Agreement between EOG and Barry Hunsaker, Jr., effective as of December 21, 1998 (Exhibit 10.66(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 1999). 10.66(c) -- Second Amendment to Executive Employment Agreement between EOG and Barry Hunsaker, Jr., effective as of February 1, 1999 (Exhibit 10.66(c) to EOG's Annual Report on Form 10-K for the year ended December 31, 1999). 10.67(a) -- Executive Employment Agreement between EOG and Loren M Leiker, effective as of March 1, 1998 (Exhibit 10.67(a) to EOG's Annual Report on Form 10-K for the year ended December 31, 1999). 10.67(b) -- First Amendment to Executive Employment Agreement between EOG and Loren M. Leiker, effective as of February 1, 1999 (Exhibit 10.67(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 1999). 10.68(a) -- Executive Employment Agreement between EOG and Gary L. Thomas, effective as of September 1, 1998 (Exhibit 10.68(a) to EOG's Annual Report on Form 10-K for the year ended December 31, 1999). 10.68(b) -- First Amendment to Executive Employment Agreement between EOG and Gary L. Thomas, effective as of February 1, 1999 (Exhibit 10.68(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 1999). *12 -- Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Dividends. *13 -- Annual Report to Shareholders *21 -- List of subsidiaries. *23.1 -- Consent of DeGolyer and MacNaughton. 23.2 -- Opinion of DeGolyer and MacNaughton dated February 8, 2000 (Exhibit 23.2 to EOG's Current Report on Form 8-K, filed on February 27, 2001). INDEX TO EXHIBITS (Continued) Exhibit Number Description *23.3 -- Consent of Arthur Andersen LLP. *24 -- Powers of Attorney. EX-23 3 exhibit10-4d.txt CONSENT AGREEMENT EXHIBIT 10.4(d) CONSENT AGREEMENT This CONSENT AGREEMENT (this "Agreement"), dated as of November 28, 2000, is entered into by and among EOG Resources, Inc., a Delaware corporation ("EOG"), Enron Corp., an Oregon corporation ("Enron"), Enron Finance Partners, LLC, a Delaware limited liability company ("EFP"), Enron Intermediate Holdings, LLC, a Delaware limited liability company ("EIH"), Enron Asset Holdings, LLC, a Delaware limited liability company ("EAH"), and Aeneas, LLC, a Delaware limited liability company ("Aeneas"). PRELIMINARY STATEMENTS A) EFP, EIH and EAH were recently formed by Enron for the purpose of owning assets theretofore held by Enron and its affiliates and to provide a vehicle to raise capital through the sale of minority common and/or preferred interests to institutional investors. Enron, EFP, EIH and/or EAH may also utilize the EOG Stock (as defined below) or a portion thereof in one or more subsequent transactions that are structured finance transactions (the "Financial Transactions"). B) Enron and certain wholly-owned affiliates of Enron have been admitted to EFP as members. Enron Finance Management, LLC, a Delaware limited liability company ("EFM") and a wholly-owned affiliate of Enron, is the managing member of EFP. C) EFP is the sole member of EIH. EFM is the Class A managing member and EIH is the Class B member of EAH. EAH is currently the sole member of Aeneas, which entity is being utilized in connection with a Financial Transaction. D) Enron has transferred Eleven Million Five Hundred Thousand (11,500,000) shares of common stock, $0.01 par value per share, of EOG (the "EOG Stock"), which it previously held, to EFP as a capital contribution. Immediately following such transfer, Enron caused the transfer and contribution of the EOG Stock from EFP to EIH, from EIH to EAH, and from EAH to Aeneas. E) Section 6.2 of the Share Exchange Agreement, entered into as of July 19, 1999, by and between Enron and EOG (formerly known as Enron Oil & Gas Company) (the "Share Exchange Agreement") requires, under certain circumstances, that Enron obtain the prior written consent of EOG to transfer any shares of EOG Stock retained by Enron pursuant to the Share Exchange Agreement. F) EOG is willing to consent to Enron's transfer of all or a portion of the EOG Stock (I) from Enron to EFP, (ii) from EFP to EIH, (iii) from EIH to EAH, and (iv) from EAH to Aeneas. EOG is also willing to consent to any subsequent transfers of the EOG Stock occurring in connection with the Financial Transactions, subject to the terms and conditions of this Agreement. The parties make no admission or assertion, whether express or implied, as to whether any of the foregoing transfers required or would require consent or approval of EOG under the Share Exchange Agreement.
G) This Agreement and the transactions contemplated hereby have been approved by the Board of Directors of EOG. In consideration of the premises and intending to be legally bound by this Agreement, the parties hereby agree as follows:
SECTION 1 AGREEMENTS 1.1 Definitions. Capitalized terms used but not defined in this Agreement shall have the meanings given them in the Share Exchange Agreement. 1.2 EOG Consent. a) EOG hereby consents, confirms and approves, pursuant to Section 6.2 of the Share Exchange Agreement and notwithstanding any other provision of the Share Exchange Agreement, to (I) Enron's transfer of the EOG Stock (or any portion thereof) to EFP, (ii) EFP's transfer of the EOG Stock (or any portion thereof) to EIH, (iii) EIH's transfer of the EOG Stock (or any portion thereof) to EAH, (iv) EAH's transfer of the EOG Stock (or any portion thereof) to Aeneas, (v) any subsequent transfers of the EOG Stock (or any portion thereof) to EAH, EIH, EFP or Enron upon the dissolution of Aeneas, EAH, EIH, or EFP, or otherwise, and (vi) any other transfers occurring upon the consummation of, or in connection with, the Financial Transactions (including, without limitation, any transfer occurring upon the termination or restructuring of such Financial Transactions), provided such transfers are effected in a manner permitted by Section 6.2(c) of the Share Exchange Agreement. EOG acknowledges and agrees that the consent granted by EOG herein is applicable whether or not EFP, EIH, EAH or Aeneas remains as a wholly- owned affiliate of Enron. b) Enron, EFP, EIH, EAH and Aeneas have advised EOG that they may make or cause to be made one or more Schedule 13D filings with the Securities and Exchange Commission (or any amendment to a previously filed or hereafter filed Schedule 13D) to reflect the transfers of the EOG Stock and any transfer occurring upon the consummation of, or in connection with, the Financial Transactions. 1.3 Certain Covenants. Enron hereby agrees as follows: (a) Enron will maintain, directly or indirectly, sole management control of EFP, EIH, EAH and Aeneas, respectively, during the periods of time when each such entity holds any of the EOG Stock. (b) In addition to Enron's obligations under the last sentence of Section 6.3 of the Share Exchange Agreement, during the period from the date hereof through the maturity date of Enron's 7% Exchangeable Notes due July 31, 2002, at any meeting of EOG stockholders with respect to which Enron, EFP, EIH, EAH or Aeneas owns any EOG Stock entitled to vote, Enron will attend (or cause such entity to attend) such meeting in person or by proxy and will vote, or
will cause to be voted, all of such EOG Stock in the manner, if any, recommended by the board of directors of EOG. (c) Subject to the terms and conditions of Section 10.4 of the Share Exchange Agreement, which shall apply to the obligations of Enron under this Section 1.3(c) Enron shall be liable for and shall indemnify and hold harmless EOG and its Subsidiaries from and against any Taxes imposed on EOG or EOG International with respect to the Share Exchange resulting from the transfers of the EOG Stock pursuant to the transactions consented to by EOG in this Agreement. (d) Notwithstanding the provisions of Section 10.3(b)(iv) of the Share Exchange Agreement, Enron agrees that EOG shall not be liable for and shall not indemnify and hold harmless Enron from any Taxes referred to in Section 10.3(b)(iv) of the Share Exchange Agreement if EOG shall prove by clear and convincing evidence that any of the transactions consented to by EOG in this Agreement that were or are effected by Enron were a contributing cause of the failure to maintain continuity of interest within the meaning of Treas. Reg. 1.355-2(c). 1.4 Additional Consideration. As additional consideration to EOG for entering into and performing this Agreement, Enron hereby agrees, as of the date hereof, to forgive indebtedness owing from EOG and/or its affiliates to Enron with respect to telecommunication services, treasury services and banking services provided by Enron and its affiliates to EOG and its affiliates prior to the date hereof, such amount in the aggregate not to exceed One Million Dollars (US$1,000,000). 1.5 Expenses. All costs and expenses incurred in connection with the transactions contemplated by this Agreement shall be paid by the party incurring such cost or expense, provided that Enron shall, within sixty (60) days following the receipt from EOG of an invoice therefor, reimburse EOG for all reasonable out-of-pocket legal expenses incurred by EOG with Wachtell, Lipton, Rosen & Katz, special counsel to EOG, or Steptoe & Johnson LLP, special tax counsel to EOG, in connection with the negotiation and execution of this Agreement. EOG shall submit any invoices to Enron for reimbursement of the foregoing expenses within ninety (90) days following the date of this Agreement. 1.6 Representations. Each party signatory hereto hereby represents and warrants to each other party that the following statements are true and correct as of the date hereof: (a) it is a corporation, limited liability company or other entity duly incorporated or formed, validly existing, and in good standing under the laws of the United States or a political subdivision thereof, with all requisite power to enter into and to perform its obligations under this Agreement, and is duly qualified or registered and in good standing in each other jurisdiction in which the character of the business conducted by it or permitted to be conducted by it requires such qualification or registration, except where the failure to be so qualified would not adversely affect the transactions contemplated by this Agreement; (b) its execution, delivery, and performance of this Agreement have been duly authorized by all appropriate action by it and (if required) its stockholders, members or other owners, and this Agreement has been duly executed and delivered; (c) its authorization, execution, delivery and performance of this Agreement do not (I) violate its organizational, charter or other constituent documents, (ii) conflict with, result in a breach of any of the terms, conditions or provisions of, or constitute a default under, any other material agreement or arrangement to which it is a party or by which it is bound or with any provision of law, regulation, judgment or decree to which it is subject or with any permit or license which it has been granted, or (iii) require the filing or registration with, or the approval, authorization or consent of any governmental agency or tribunal other than filings with the Securities and Exchange Commission as contemplated by Section 1.2(b) hereof and any other filings which may be required or permitted under applicable securities laws or regulations; (d) this Agreement constitutes its valid, binding and enforceable agreement, except to the extent such enforceability may be limited by the effect of bankruptcy, insolvency, reorganization, moratorium and similar laws from time to time in effect relating to the rights and remedies of creditors, as well as general principles of equity (regardless of whether considered in a proceeding in equity or in law); and (e) there is no action, suit or proceeding pending, or, to its knowledge is any of such threatened, against it, seeking any injunction, award or other relief that would impair its ability to perform its obligations under this Agreement. 1.7 Covenants. (a) Each of EFP, EIH, EAH and Aeneas hereby severally agrees to be bound by Sections 6.2 and 6.3 of the Share Exchange Agreement, as if each were an original signatory to such agreement, with the effect that all references to Enron under Sections 6.2 and 6.3 of the Share Exchange Agreement shall be deemed to be references to EFP, EIH, EAH or Aeneas, respectively, during any time such person or persons hold any shares of the EOG Stock. (b) Each of Enron, EFP, EIH and EAH hereby agrees, in connection with any transfer of shares of EOG Stock pursuant to the Financial Transactions, to cause any transferee (including Aeneas, but excluding Enron, EFP, EIH or EAH) of shares of EOG Stock in such Financial Transactions to agree that if any further transfers of such EOG Stock would result in Enron, EFP, EIH or EAH failing to retain beneficial ownership of such EOG Stock, such transfers would only be effected in a manner permitted by Section 6.2(c) of the Share Exchange Agreement. 1.8 Effect of this Agreement. For purposes of the definition of "Standstill Expiration Date" as defined in the Share Exchange Agreement, and giving effect to the transactions contemplated by this Agreement, Enron shall be deemed to beneficially own the EOG Stock held by any of Enron, EFP, EIH, EAH or Aeneas. SECTION 2 MISCELLANEOUS 2.1 Governing Law. This Agreement shall be governed by and construed in accordance with the laws of the State of Delaware, excluding any choice of law rules that may direct the application of the laws of another jurisdiction. 2.2 Further Assurances. After the date hereof, each party hereto at the reasonable request of any other party hereto and without additional consideration, shall execute and deliver, or shall cause to be executed and delivered, from time to time, such further certificates, agreements or instruments and shall take such other action as the other party or parties hereto may reasonably request, to consummate, implement or confirm the transactions contemplated by this Agreement. 2.3 Entire Agreement; Amendment. This Agreement, the Share Exchange Agreement, and any agreements, instruments or documents executed and delivered by the parties or their affiliates pursuant to this Agreement, constitute the entire agreement and understanding among the parties, and it is understood and agreed that all other previous undertakings, negotiations and agreements among the parties regarding the subject matter hereof (other than the Share Exchange Agreement) are merged herein. This Agreement may not be modified orally, but only by an agreement in writing signed by each of the parties. 2.4 Waivers. No delay on the part of any party in exercising any right, power or privilege hereunder shall operate as a waiver thereof, nor shall any waiver on the part of any party of any such right, power or privilege, nor any single or partial exercise of any such right, power or privilege, preclude any further exercise thereof or the exercise of any other such right, power or privilege. 2.5 Binding Effect; No Third Party Beneficiaries. This Agreement and all of its provisions, rights and obligations shall be binding upon and shall inure to the benefit of the parties hereto and their respective successors and assigns. Nothing herein express or implied is intended or shall be construed to confer upon or to give anyone other than the parties hereto and their respective successors and assigns any rights or benefits under or by reason of this Agreement, and no other party shall have any right to enforce any of the provisions of this Agreement. 2.6 Execution in Counterparts. This Agreement may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement. Delivery of an executed counterpart of a signature page to this Agreement by telecopier shall be effective as delivery of a manually executed counterpart of this Agreement. IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed by their respective officers thereunto duly authorized, as of the date first above written. EOG RESOURCES, INC. By: /s/ EDMUND P. SEGNER, III --------------------------------- Name: EDMUND P. SEGNER, III Title: President and Chief of Staff ENRON CORP. By: /s/ RICHARD A. CAUSEY -------------------------------- Name: Richard A. Causey Title: Executive Vice President & Chief Accounting Officer ENRON FINANCE PARTNERS, LLC By: Enron Finance Management, LLC, its Class A Member By:Enron Corp., its Sole Member By: /s/ RICHARD A. CAUSEY ----------------------------- Name: Richard A. Causey Title: Executive Vice President & Chief Accounting Officer ENRON INTERMEDIATE HOLDINGS, LLC By: Enron Finance Partners, LLC, its Sole Member By: Enron Finance Management, LLC, its Class A Member By: Enron Corp., its Sole Member By: /s/ Richard A. Causey ------------------------- Name: Richard A. Causey Title: Executive Vice President & Chief Accounting Officer ENRON ASSET HOLDINGS, LLC By: Enron Finance Management, LLC, its Class A Member By: Enron Corp., its Sole Member By: /s/ Richard A. Causey ------------------------------ Name: Richard A. Causey Title: Executive Vice President & Chief Accounting Officer AENEAS, LLC By: Enron Asset Holdings, LLC, its Sole Member By: Enron Finance Management, LLC, its Class A Member By: Enron Corp., its Sole Member By: /s/ Richard A. Causey ---------------------------- Name: Richard A. Causey Title: Exec. Vice Pres. & Chief Account. Officer EX-12 4 exhibit12.txt COMPUTATION OF RATIOS STATEMENT EXHIBIT 12 EOG RESOURCES, INC. Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Dividends (In Thousands) (Unaudited) Year Ended December 31, - ----------------------------------------------------------------------------------------------------------- 2000 1999 1998 1997 1996 - ----------------------------------------------------------------------------------------------------------- EARNINGS AVAILABLE FOR FIXED CHARGES: Net Income $396,931 $569,094 $ 56,171 $121,970 $140,008 Less: Capitalized Interest Expense (6,708) (10,594) (12,711) (13,706) (9,136) Add: Fixed Charges 67,714 72,413 61,290 41,423 21,997 Income Tax Provision (Benefit) 236,626 (1,382) 4,111 41,500 50,954 -------- -------- -------- -------- -------- EARNINGS AVAILABLE $694,563 $629,531 $108,861 $191,187 $203,823 ======== ======== ======== ======== ======== FIXED CHARGES: Interest Expense $ 61,006 $ 61,819 $ 48,463 $ 27,369 $ 12,370 Capitalized Interest 6,708 10,594 12,711 13,706 9,136 Rental Expense Representative of Interest Factor - - 116 348 491 -------- -------- -------- -------- -------- TOTAL FIXED CHARGES 67,714 72,413 61,290 41,423 21,997 Preferred Dividends on a Pre-tax Basis 17,602 660 - - - -------- -------- -------- -------- -------- COMBINED TOTAL FIXED CHARGES AND PREFERRED DIVIDENDS $ 85,316 $ 73,073 $ 61,290 $ 41,423 $ 21,997 ======== ======== ======== ======== ======== RATIO OF EARNINGS TO FIXED CHARGES 10.26 8.69 1.78 4.62 9.27 RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED DIVIDENDS 8.14 8.62 1.78 4.62 9.27
EX-13 5 exhibit13cover.txt ANNUAL REPORT TO SECURITY HOLDERS - COVER COVER EXHIBIT 13 EOG RESOURCES, INC. 2000 ANNUAL REPORT TO SHAREHOLDERS EOG salutes its employees who are creating the oil and gas exploration and production company of the future by including every employee's name on the cover of its 2000 annual report. 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Financial and Operating Highlights --------------------------------------------------------------- (In millions, except per share data, unless otherwise indicated) 2000 1999 1998 1997 1996 1995 - ------------------------------------------------------------------------------------------------------------------------------- Net Operating Revenues, As Adjusted * $1,490 $ 794 $ 732 $ 784 $ 747 $ 667 Income Before Interest and Taxes, As Adjusted * $ 695 $ 147 $ 81 $ 183 $ 204 $ 195 Net Income Available to Common, As Adjusted * $ 386 $ 58 $ 43 $ 117 $ 140 $ 141 Adjustments for India and China Operations and Certain Non-recurring Items $ - $ 511 $ 13 $ 5 $ - $ 1 Net Income Available to Common, As Reported $ 386 $ 569 $ 56 $ 122 $ 140 $ 142 Discretionary Cash Flow Available to Common * $1,007 $ 466 $ 427 $ 492 $ 478 $ 421 Exploration and Development Expenditures * $ 687 $ 428 $ 716 $ 619 $ 515 $ 492 Wellhead Statistics Natural Gas Volumes (MMcf/d) * 908 892 915 871 830 743 Natural Gas Prices ($/Mcf) * $ 3.49 $ 2.01 $ 1.80 $ 2.11 $ 1.84 $ 1.36 Crude Oil and Condensate Volumes (MBbls/d) * 27.5 19.4 19.6 17.6 16.8 16.6 Crude Oil and Condensate Prices ($/Bbl) * $29.57 $18.02 $12.65 $19.24 $20.70 $16.80 Natural Gas Liquids Volumes (MBbls/d) 4.7 3.4 3.9 3.9 2.5 1.4 Natural Gas Liquids Prices ($/Bbl) $19.87 $12.24 $ 8.38 $12.17 $13.00 $11.31 NYSE Price Range ($/Share) High $56.69 $25.38 $24.50 $27.00 $30.63 $25.38 Low $13.69 $14.38 $11.75 $17.50 $22.38 $17.13 Close $54.63 $17.56 $17.25 $21.19 $25.25 $24.00 Cash Dividends Per Share $ .135 $ .120 $ .120 $ .120 $ .120 $ .120 Average Shares Outstanding 117.1 140.9 154.3 157.4 159.9 159.9 Year-end Shares Outstanding 116.9 119.1 153.7 155.1 159.8 159.8 * 1995 - 1999 adjusted to exclude India and China operations and certain non-recurring items.
On the Cover EOG salutes its employees who are building the exploration and production company of the future. EOG's stock price more than tripled during 2000, ranking third in Standard & Poor's 500 index. Contents Letter to Shareholders................................. 2 Review of Operations................................... 6 Midland, Texas Division................................ 8 Denver, Colorado Division.............................. 9 Oklahoma City/Mid-Continent Division................... 10 Tyler, Texas Division.................................. 11 Corpus Christi, Texas Division......................... 12 Pittsburgh, Pennsylvania Division...................... 13 Houston,Texas/Offshore Division........................ 14 Calgary, Canada Division............................... 15 International Division................................. 16 Financial Review....................................... 17 Officers and Directors................................. 54 Glossary of Terms...................................... 55 Shareholder Information................................ 56 EX-13 6 exhibit13narrative.txt ANNUAL REPORT TO SECURITY HOLDERS - NARRATIVE EXHIBIT 13 - NARRATIVE THE COMPANY EOG Resources, Inc. (EOG) is one of the largest independent (non-integrated) oil and gas companies in the United States. It is engaged in the exploration and development, production and marketing of natural gas and crude oil primarily in major producing basins in the United States, as well as in Canada, Trinidad and selected other international areas. At December 31, 2000, EOG's estimated net proved natural gas reserves were 3,381 Bcf and estimated net proved crude oil, condensate and natural gas liquids reserves were 73 million barrels. Approximately 56 percent of EOG's reserves on a natural gas equivalent basis were located in the United States, 15 percent in Canada and 29 percent in Trinidad. At year-end 2000, EOG had approximately 850 employees. 2000 HIGHLIGHTS EOG reported record net income available to common of $385.9 million or $3.30 per share. This compares to 1999 results of net income available to common of $57.6 million, or $.49 per share, adjusted to exclude operations in India and China transferred to Enron Corp., and various non-recurring items primarily associated with the share exchange agreement with Enron Corp. On a per share basis, compared to as-adjusted 1999, total company production increased 8.9 percent, natural gas production increased 3.6 percent, crude oil production increased 43.5 percent and natural gas liquids production increased 40.6 percent. EOG exceeded its original absolute production goal of 4 percent in North America by increasing production over 8 percent, primarily through the drillbit, compared to 1999. The after-tax rate of return on EOG's 2000 capital program in North America was 46 percent, which breaks into a 16 percent rate of return on the $102 million spent on property acquisitions and a 66 percent rate of return on the $541 million spent on land, seismic and drilling. EOG repurchased a total of 2.2 million shares of common stock, reducing the share count from 119.1 million at year-end 1999 to 116.9 million at year-end 2000. To offset employee stock option exercises, an additional 6.7 million shares also were repurchased. During the second quarter 2000, EOG increased the annual common stock dividend from $.12 per share to $.14 per share. During the first quarter 2001, the common stock dividend was increased by another $.02 per share to $.16 per share. EOG paid down $131.3 million of debt reducing the debt-to-total capitalization ratio from 47 percent at year-end 1999 to 38 percent at year-end 2000. Total EOG proved reserves increased by approximately 6 percent to 3,821 Bcfe at year-end 2000. EOG replaced 152 percent of production from all sources at a finding cost of $1.07 per Mcfe. EOG's stock appreciated 211 percent, reflecting the company's leverage to North America natural gas. EOG was the third best performer in Standard & Poor's 500 Index in 2000. EOG set up its North America operations for future growth by adding significant acreage in several new geologic trends and increasing its experienced geological and geophysical employee headcount by over 25 percent to enhance future exploration growth. EOG also created a new onshore operating division to establish a foothold in the Appalachian Basin. Internationally, EOG signed a contract to supply 60 MMcf/d of natural gas from the U(a) block to serve an ammonia plant in Trinidad. EOG was the second most active driller in the U.S. in 2000 measured by footage drilled, and plans to maintain its active drilling program in 2001. A YEAR OF CONTINUED MOMENTUM 2000 ANNUAL REPORT 1 AT THE START OF 2000, EOG WAS CONFIDENT IN THE VALIDITY OF ITS LONG-TERM NATURAL GAS THESIS AND STRATEGY. AS ENERGY EVENTS UNFOLDED DURING THE YEAR, EOG'S TENACITY AND SINGLE-MINDED PURSUIT OF THE FUNDAMENTALS WERE REWARDED. ITS 2000 STOCK PRICE PERFORMANCE WAS UNPARALLELED IN THE INDUSTRY, ITS ORGANIC GROWTH WAS UNMATCHED AND ITS POSITIONING FOR CONTINUED SUCCESS IN 2001 AND BEYOND WAS SOLIDIFIED. LETTER TO SHAREHOLDERS EOG has been called a 'no-excuses' company. Our approach to the exploration and production business has been characterized as 'what you see is what you get.' Frankly, we like both descriptions. They accurately sum up EOG's commitment to a long-term natural gas strategy and the fundamentals that underpin our company's foundation. EOG is natural gas based, per share focused, and rate of return driven, and is both a low cost producer and a consistent performer. Our commitment to that strategy and adherence to those fundamentals has not changed. In our first full year as a truly independent exploration and production company (no longer associated with Enron Corp.), we made progress toward our goal of being ranked as the best independent exploration and production company in the industry. Our success created a momentum that was fueled by achieving - and in some cases exceeding - the goals we articulated this time last year. We also benefited from the highest natural gas and crude oil prices in recent history. Therefore, we are reporting outstanding 2000 results. DELIVERING ON OUR PROMISES EOG's stock price appreciated 211 percent during the year, ranking it third in the S&P 500 Index, to which we were added in November. EOG outperformed every stock in our peer group, more than doubling their average stock price appreciation. For 2000, EOG reported net income available to common of $385.9 million, or $3.30 per share, compared to 1999 net income available to common of $57.6 million or $ .49 per share, adjusted to exclude operations in India and China transferred to Enron Corp., and various non-recurring items primarily associated with the share exchange agreement with Enron Corp. With one of the highest weightings to natural gas in the industry, EOG decided early in 2000 to remain unhedged. This proved beneficial when industry natural gas prices began a steady rise from $2.29 per MMbtu on January 1 to $9.52 per MMbtu on December 31, resulting in over $1.0 billion of discretionary cash flow to EOG. Natural gas prices for the year averaged $4.29 per MMbtu. Much of that cash flow was plowed back into the ground allowing us to substantially increase our production through the drillbit in 2000 and to build a drilling 2 EOG RESOURCES, INC. [Photo] Left, Mark G. Papa Right, Edmund P. Segner, III inventory for the future. Other cash above our capital program was used to repurchase shares and reduce debt. During the year, we also took advantage of industry merger dynamics to make a significant investment in geologists and geophysicists, increasing EOG's headcount of prospect generators by 25 percent. At the beginning of the year, EOG set a target of 4 percent growth in North American production, increased it to 7 percent at the end of the first quarter and upped it to 8 percent at the end of the third quarter. This degree of organic production growth is unique in the industry and is particularly important at a time when North American natural gas has become so valuable. Because of EOG's atypical focus on earnings per share, cash flow per share and production per share, the reduction of over two million shares of common stock outstanding during the year was significant. We closed out 2000 with 116.9 million shares of stock outstanding, continuing the pattern we established when EOG began to reduce the 160 million shares it had outstanding in 1996. During 2000, we paid down over $130 million of debt, ending the year with a 38 percent debt-to-total capital ratio. We also announc ed a 17 percent increase in our annual dividend from $.12 to $.14 per share in the second quarter. Each of our seven North American Divisions and our International Division delivered outstanding performances in 2000 with continued emphasis on reinvestment rate of return. We increased the number of divisions during the year by adding EOG Resources Appalachian LLC, following the acquisition of Somerset Oil & Gas Company, Inc. of Indiana, Pennsylvania. This addition gives us a foothold in a new, proven hydrocarbon basin. NATURAL GAS BECOMES NORTH AMERICAN HEADLINE NEWS During the winter of 2000-2001, tight natural gas supplies and strong demand fueled by colder than normal winter temperatures after four years of mild weather converged to push natural gas prices to new highs. This latest chapter in the North American natural gas story caught consumers by surprise. However, at EOG, we regarded this convergence as a matter of timing. These factors have combined to establish a new price benchmark for 2000 ANNUAL REPORT 3 natural gas and heighten awareness and appreciation for this clean burning, efficient, environmentally friendly fuel. EOG expects continued tightness in the natural gas market. It is anticipated that the future will be shaped by the following trends: * Demand for natural gas will continue to escalate from 22.2 Tcf this year to 29.0 Tcf in 2010 in the U.S., according to a recent National Petroleum Council study. Much of that increase will be the result of new demand from natural gas fired electric generating plants that are already being approved, sited and built. The recent California power crisis has confirmed the need for additional plants. * During the decade of the 1990s, natural gas from individual wells was produced at a faster rate than had been historically possible due to significant improvements in completion technology. the U.S. natural gas decline rate has increased significantly over this period. * On the supply side, U.S. reserves discovered per well dropped from an average of 1.34 Bcf in 1995-97 to .99 Bcf in 1998-99. * Canadian natural gas supplies that have historically absorbed the majority of the growth in U.S. natural gas consumption are no longer keeping pace with U.S. demand. Western Canadian production has been flat, influenced by factors such as smaller reserve targets drilled and decline rates similar to those in the U.S. CONSISTENCY, CONSISTENCY, CONSISTENCY: CORNERSTONE OF EOG'S GAME PLAN In 2001, the key to meeting our objectives is consistency. We are not a company whose strategy changes regularly - just for the sake of change. First and foremost, WE WILL MAKE PRUDENT USE OF CAPITAL. We are aware that portions of this industry have historically embarked on value-destroying capital investments, particularly in periods of high cash flow such as today. That's why we place such a strong emphasis on prudent use of capital. WE WILL CONTINUE TO PRIMARILY EXPLORE FOR RESERVES RATHER THAN MAKE LARGE ACQUISITIONS. Organic growth for an exploration and production company is like blocking and tackling for a football team. It's not as glorious as being involved in a big acquisition but it gets consistent results. During 2000, the after-tax unlevered rate of return on our drilling program was 66 percent compared to 16 percent on the acquisitions we made. OUR DRILLING PROGRAM MIX NOW INCLUDES A GREATER NUMBER OF LARGER POTENTIAL PROSPECTS THAN IN THE PAST. This provides an augmentation to our basic 'singles and doubles' strategy. WE PLAN TO ADD TO OUR INTERNATIONAL PORTFOLIO IN 2001 AND WILL CONTINUE TO INCREASE OUR MARKET PRESENCE IN TRINIDAD. In 2000, we captured a market for a portion of our U(a) block natural gas to supply a new ammonia plant. Because of high North American natural gas prices, domestic fertilizer operations and other industries that require natural gas as feedstock are look ing to alternative locations like Trinidad. We expect to add an additional market for our Trinidad gas in 2001. WE WILL CONTINUE TO FOCUS ON ACTIVITIES THAT HAVE A PER SHARE IMPACT. Although EOG has not participated in a major merger, our share price has out-performed the stock price of the surviving entities of the major mergers and transactions that have taken place in the exploration and production industry peer group in the last three years. 4 EOG RESOURCES, INC. In 2001, EOG's main thrust is to add value by generating prospects, drilling wells, controlling costs and focusing on rate of return. This strategy isn't likely to grab any headlines, but it provides consistent bottom line results. OUR STRENGTH IS OUR EMPLOYEES A review of 2000 and a look ahead at 2001 and beyond at EOG would be incomplete without paying tribute to EOG's employees. The consistent game plan that management has laid out is being put into action daily in our division offices and our Houston headquarters. Thank you for your efforts! Welcome to all new employees, including our expanded geological, geophysical, land and engineering teams, whose expertise is adding new skills to our existing workforce of prospectors. Our nine divisions operate as autonomous profit centers, similar to nine entrepreneurial mini-exploration and production companies. These decentralized, cohesive units are physically located close to their areas of operations and are focused on executing the EOG strategy. This portfolio approach to our asset base continues to deliver solid results for EOG shareholders. During 2000, we acted true to our beliefs at EOG and were rewarded for it. Our commitment has not wavered. There are very few management teams in the exploration and production sector who deliver long-term results. We want to continue to be one of the management teams that does. We want to be the best independent exploration and production company, the best driller and producer, and the best employer. We will settle for nothing less. /s/ MARK G. PAPA /s/ EDMUND P. SEGNER, III Mark G. Papa Edmund P. Segner, III Chairman and Chief Executive Officer President and Chief of Staff 2000 ANNUAL REPORT 5 REVIEW OF OPERATIONS North American Reserve Replacement ---------------------------------------------------------- 1996** 1997** 1998** 1999* 2000 ---------------------------------------------------------- All Sources 137% 135% 144% 136% 154% Drilling Only 123% 111% 118% 106% 100% * Excludes deep Paleozoic reserves ** Includes volumes related to a volumetric production payment [ ] All Sources [ ] Drilling Only Exploration & Development Expenditures North America & Trinidad ($ Millions) ----------------------------------------------------------- 1996 1997 1998 1999 2000 ----------------------------------------------------------- North America 496 600 681 423 684 & Trinidad [ ] North America [ ] Trinidad Year-end Reserves (Bcfe) ----------------------------------------------------------- 1996* 1997* 1998* 1999 2000 ----------------------------------------------------------- North America 2,524 2,606 3,478 3,610 3,821 & Trinidad * Adjusted to exclude deep Paleozoic reserves [ ] North America [ ] Trinidad Natural Gas Volumes (MMcf/d) ----------------------------------------------------------- 1996 1997 1998 1999 2000 ----------------------------------------------------------- North America 830 871 915 892 908 & Trinidad [ ] North America [ ] Trinidad Total Production Volumes (MMcfe/d) ----------------------------------------------------------- 1996 1997 1998 1999 2000 ----------------------------------------------------------- North America 946 1,000 1,056 1,029 1,101 & Trinidad [ ] North America [ ] Trinidad Year-end Shares Outstanding (millions) ----------------------------------------------------------- 1996 1997 1998 1999 2000 ----------------------------------------------------------- 160 155 154 119 117
6 EOG RESOURCES, INC. [Photo] A drilling rig working for EOG is silhouetted against the evening sky in East Texas. 2000 ANNUAL REPORT 7 [Photo] A drilling rig lights up the night sky in the Permian Basin of West Texas. "There are enormous opportunities to add low cost reserves and production in practically every producing region in the United States. The key is the identification of these opportunities along with the ability to capture and produce the reserves. To do this, we must have the very best people, coupled with an organizational culture that allows them to perform. I believe we have the best staff in the Permian Basin and my job is to see that they have the resources and the freedom to create, acquire and produce the significant potential that exists!" Bill Thomas, Senior Vice President & General Manager Midland, Texas Division "When I decided to go to work with EOG, I was immediately impressed with the quality of the core oil and gas professionals that EOG had assembled because they had a passion for finding oil and gas which equals my own." John Troschinetz, Project Geologist During 2000, the Midland Division generated a 100-plus percent after-tax rate of return on its total capital program and increased production 31 percent from 40.5 to 53.2 Bcfe. The division drilled 67 gross wells and was most successful in Southeast New Mexico and the Midland Basin of West Texas. Completion of a property trade with Burlington Resources Oil & Gas Company early in 2000 added approximately 170,000 acres of leasehold in the Permian Basin. By yearend, production on these properties had increased 170 percent. Three new exploration trends in the Permian Basin were defined during the year and over 200,000 acres of new leasehold and seismic options were added in these prolific areas. In 2001, the Midland division's goal is to increase production by 10 percent. It has identified upside potential in the following trends: Morrow and Wolfcamp in Southeast New Mexico; Montoya and Devonian Horizontal in West Texas; and the Carbonate 3-D plays in the Midland Basin of West Texas. The Midland Division plans to drill over 90 wells in the Permian Basin, a 30 percent increase over its 2000 program. Plans also call for acquiring significant new leasehold and new 3-D seismic in high potential trends to set up drilling for future years. The division also will continue to add staff and grow through internally generated prospects. 8 EOG RESOURCES, INC. Denver, Colorado Division "EOG continues to lead the pack because its management and employees have a passion for action and a commitment to success." Ty Stillman, Project Landman [Top Photo] Morning light bathes a drilling rig in the EOG Denver Division. The strategy in the Denver Division is maintaining a successful singles and doubles drilling program, while adding large exploration targets. One attractive exploration play currently underway is the North Shafter horizontal oil play near Bakersfield, California. During 2000, the division drilled 12 wells in North Shafter at a 100 percent success rate and although the play is still in an early stage of development, each successful well provides additional data and a better understanding of the area's geology. During 2001, the Denver Division plans to drill more wells in the play to continue to gather information and ultimately determine the size and potential of the oil field. During 2000, the Denver Division integrated and merged 520 square miles of 3-D seismic data, covering the LaBarge Platform in Big Piney, Wyoming to identify and develop both shallow and deep exploratory prospects. Based on this data, EOG plans to drill more than 50 wells in the area during 2001. Key producing areas with promising up-side potential that are part of an ongoing development/exploitation program for the Denver Division are the Big Piney - LaBarge Platform; Vernal - Chapita/Natural Buttes; California - - North Shafter; and Southwest Wyoming - Cepo/Cedar Chest. Plans are to drill more than 250 wells in 2001, an 80 percent increase over 2000, and to increase production by 14 percent. [Bottom Photo] Contract drillers work on the rig floor. "The exploration and exploitation potential of the Western United States is enormous and EOG is in the best position to develop these resources. We have the people, acreage position, expertise and desire to succeed." Kurt Doerr, Vice President & General Manager 2000 ANNUAL REPORT 9 Oklahoma City/Mid-Continent Division "We can move faster than anybody else. Every place else I have worked they have always said that.but here at EOG.it's reality.we CAN move faster than anybody else.and that gives us a competitive advantage." Dennis Cates, Division Operations Manager "There is absolutely no question in my mind, there are tremendous opportunities for finding significant new reserves in the mature Mid-Continent basins. Think about it.in the past three years, our division has discovered new reserves of over 180 Bcfe gross IN THE LARGEST AND OLDEST GAS FIELD IN NORTH AMERICA.HUGOTON! To do this, you have to have the right people focused on the right opportunities, and then provide them with the value system and resources to be successful. It produces leaders. And being a leader is what EOG's culture, and the Mid-Continent Division's culture is all about." Steve Coleman, Vice President & General Manager [Photo] An EOG well is drilled in Oklahoma during the winter of 2000-2001. The strategy in the Mid-Continent Division is to continue to grow by building on its success in the Oklahoma Panhandle Hugoton trend while exposing EOG to a portfolio of other significant and innovative play opportunities across the Anadarko Basin. In the Hugoton trend, EOG has accumulated close to 1,000,000 acres through various trades, farmout agreements and leasing activity, setting up the Mid-Continent Division with a four-year prospect inventory. During 2000, the division drilled 105 gross wells in the region replacing reserves over 150 percent and generating an after- tax rate of return on total capital spent in excess of 100 percent. The division's plans for 2001 include increasing drilling activity by 57 percent over 2000 by drilling 165 wells. These plans include 15 to 20 wells in the continued development of a new horizontal play discovered in 2000. This play is at a depth of 3,300 feet and the typical well produces from a 2,500-foot lateral at a rate of 1.2 MMcf/d and is expected to recover between 1.0 to 1.5 Bcfe. The division's plans also include testing three to five similar horizontal plays and several Deep Anadarko Basin prospects which all have significant reserve potential. 10 EOG RESOURCES, INC. Tyler, Texas Division "Stagnation leads to deterioration. EOG is ever changing to meet the needs of tomorrow. Status-quo is not an option." Mark Cox, Project Drilling Engineer The Tyler Division increased production by 35 percent to 54.4 Bcfe in 2000. Key areas of production for the division are the Sabine Uplift Region, Upper Texas Coast and Mississippi Salt Basin. During 2000, the Tyler Division assimilated and exploited properties received from OXY USA Inc. in a property trade agreement. Through drilling success and the application of technology, the division tripled the reserve potential from original projections. EOG moved into the Bossier play and conducted a 3-D seismic survey in Galveston County, to further develop its reserve base and prospect inventory. In 2001, EOG seeks to enter new exploratory areas including the Bossier play in Louisiana. EOG further plans to drill over 50 wells in the Sabine Uplift area. [Photo] EOG employees discuss the company's East Texas plant facilities. [Map] Key areas of Activity - Tyler, Texas Division "In the Tyler Division, our strategy is to seek the competitive edge and delegate authority and hold high expectations. We pursue only projects that the team would put its own money into. Our strategy is to maintain our production base by low cost exploitation and grow by using 3-D based exploration and purchasing exploitable assets." Jack Huppler, Vice President & General Manager 2000 ANNUAL REPORT 11 Corpus Christi, Texas Division "At EOG Resources, teamwork is not a corporate concept, but a method of operation. Team members are enthusiastic about meeting challenges and communicate effectively both up and down the line. The result is that team members share success. This in turn reflects the company as a whole, which celebrates success with both verbal and material recognition for its employees. After 26 years in the oil and gas business, I am surprised at how much I enjoy going to work each day." Randall Davis, Project Landman Early in 2000, the Corpus Christi Division made a 100 Bcfe-plus discovery in the Roleta trend of South Texas. Two to three rigs ran in the Roleta throughout the year, drilling 39 gross wells with a 90 percent success rate. The division exceeded 100 percent reserve replacement and generated an after- tax rate of return on its total capital program that exceeded 100 percent while increasing production 21 percent to 67.6 Bcfe versus 55.7 Bcfe in 1999. The growth came from significant acreage that was added in three trends: the Lobo and Wilcox in South Texas and the Geopressured Frio along the Texas Gulf Coast. The Corpus Christi Division has identified seven fields with upside potential: Zwebb - Webb and Zapata Counties; El Huerfano - Zapata County; Pok-A-Dot - Zapata County; Tiffany - Webb County; Rosita - Duval County; Bucks Bayou North - Matagorda County; and Bay City Area - Matagorda County. In 2001, approximately 70 gross wells will be drilled in the Corpus Christi Division, including a major extension of the successful Bay City program. Production growth is targeted at 5 percent over 2000, as well as replacement of 100 percent of production through the drillbit. [Photo] EOG employees in the Corpus Christi, Texas Division pause beside a huge wellhead in early morning light. "Successful exploration starts with technically integrated teams and requires shared vision, a long term sense of purpose, new ideas, implementation and a constant focus on the bottom line. Our approach is a balance between exploration risk with the accompanying upside and an aggressive development program. We are particularly proud that all of our success in recent years is due to internally generated exploration. Our program is completely home grown." Bob Garrison, Vice President & General Manager 12 EOG RESOURCES, INC. Pittsburgh, Pennsylvania Division "I've spent the first 25 years of my career in the Appalachian Basin working for independent oil and gas companies where the focus has always been on the shallow formations. I am convinced that the resources of EOG, now directed toward the development of the deeper horizons in the region, will be a successful effort for the stockholders, the company and our exploration team." R.P. "Chip" Keddie, Project Landman This newest EOG division was added late in 2000 following the purchase of Somerset Oil & Gas Company, Inc., a small independent oil and gas operator in Appalachia with assets located primarily in Western Pennsylvania. The acquisition added 150 Bcf of reserves and more than 400 drilling locations to EOG's portfolio. Historically, drilling in this region has focused on shallow wells. EOG's 2001 plan for the division is to assemble a substantial acreage position for exploration plays, shoot several miles of 2-D seismic and drill at least four exploratory wells. Plans include the drilling of at least 120 natural gas development wells in the Brady and Indiana fields in Pennsylvania. The division also will pursue strategic property acquisitions with shallow and exploratory drilling potential. In addition, the Pittsburgh Division will focus on completing its staffing to become a fully operational exploitation and exploration unit. [Photo] Fall colors paint the Appalachian Region, home to EOG's newest division, headquartered in Pittsburgh. "Of the hundreds of thousands of wells in the Appalachian Basin, the vast majority are less than 5,000 feet deep. Only a handful have ever been drilled deeper than 12,500 feet. Here in the shadow of Titusville, the birthplace of the American petroleum industry, we're assembling a team of intelligent, energetic and experienced people to further develop the long proven shallow gas potential and the yet unproven, but very exciting potential of the deeper producing horizons." Gary L. Smith, Vice President & General Manager [Map] Key areas of Activity - Pittsburgh, Pennsylvania Division 2000 ANNUAL REPORT 13 Houston,Texas/Offshore Division "Offshore Division employees are excited because we have found the right formula for us as a division, blending shelf and deepwater opportunities. We're evaluating them through a very disciplined approach we all believe will lead to success." David Brunette, Land manager [Top Photo] EOG Offshore Division employees review shelf and deepwater exploration opportunities. EOG's Offshore Division is active in the Gulf of Mexico Shelf in Texas and Louisiana with two fields, Eugene Island 135 and Matagorda Island 623, accounting for a significant portion of the division's production. During 2000, total production was 33.3 Bcfe versus 48.6 Bcfe in 1999. On December 31, 1999, the division traded approximately 28 MMcf/d but, through successful drilling, had almost replaced this production by yearend. During 2000, EOG drilled or participated in five wells that increased production in the division. This included an exploratory discovery at Matagorda Island 704 that added 5 MMcf/d net. EOG has a 25 percent working interest. Taking advantage of industry mergers, EOG assembled an expert deep-water staff to initiate deep-water exploration. This team will evaluate both domestic and international opportunities to add to EOG's exploration profile. In 2001, the Offshore Division will increase its deep-water activity by participating in one or more high impact exploratory prospects. EOG plans to maintain an active shelf exploration program by participating in eight wells. It also plans to complete a major compression project (non-operated) at Matagorda Island 623 to increase production from the field by 25 percent. [Bottom Photo] An active offshore shelf exploration drilling platform. "We're maximizing our return on investment through technical and economic analysis by highly competent and motivated staff. We'll achieve growth and high profitability by implementing a mix of development drilling and high impact wildcats." Earl J. Ritchie, Jr., Vice President & General Manager 14 EOG RESOURCES, INC. Calgary, Canada Division "The one who says it cannot be done should never interrupt the one who is doing it!" Sarah Rotermann, Senior Exploitation Technologist During 2000, the Calgary Division was again successful with its strategy of drilling a large number of shallow gas wells in Western Canada, adding production and reserves. The division increased production from 49.2 Bcfe in 1999 to 53.7 Bcfe in 2000 and set a new record by drilling 434 wells, most of which were shallow gas. Key producing areas were Sandhills, Blackfoot and Grande Prairie (Wapiti). All three show upside potential for the future, along with the Waskada and Twining fields. Also in 2000, the Calgary Division acquired a small Canadian producer, Q Energy Limited, which had assets adjacent to EOG's existing Sandhills operation. For 2001 and beyond, the division is broadening its strategy by seeking large reserve targets in Canadian producing basins. It made a significant step toward meeting this goal last year by acquiring a significant acreage position of about 240,000 net acres in the central Mackenzie corridor of the Northwest Territories. The division added to its exploration portfolio with the identification and development of a significant potential of an ineffective waterflood at Waskada, Manitoba. Plans are to enter the first phase of the redevelopment of the reservoir during 2001. During the coming year, the division plans to drill at least 375 shallow gas wells in the Sandhills and Blackfoot areas and carry out further seismic and aeromagnetic surveys on the Northwest Territories acreage where drilling is planned for early 2002. [Map] New EOG Interest - Calgary, Canada Division [Photo] A skiff of snow covers the ground where another Canadian well is drilled. "People are the key to unlocking the many unique and varied opportunities that are waiting to be discovered. Make sure they understand what it takes to make money and then give them some rein and let them run." Lanny Fenwick, Senior Vice President & General Manager, EOG Resources Canada Inc. 2000 ANNUAL REPORT 15 International Division "EOG's international division has really been rebuilt within the last 12 months. With our small group of seasoned professionals, we have developed a competitive edge to quickly screen, evaluate, and decide the merits of an opportunity as we search the international arena for the right fit." Sammy Pickering, Engineering Director 2000 got underway in the International Division with the announcement that EOG had signed an ammonia plant contract in Trinidad and received approval from the Government of Trinidad and Tobago to supply 60 MMcf/d of natural gas to this facility. To support the contract, EOG drilled an appraisal well on the U(a) block and increased proved reserves to 746 Bcfe. EOG's blocks in Trinidad include the SECC and the U(a). All current production is from the SECC block, where production increased from 138 MMcfe/d in 1999 to 141 MMcfe/d in 2000. The SECC block production is under a take-or-pay contract with the National Gas Company of Trinidad. Initial natural gas sales from the U(a) block and ammonia production should start in the latter part of 2002. [Map] Key Trinidad Production - International Division [Bottom Photo] An offshore platform explores for additional natural gas reserves offshore Trinidad. "EOG is one of the few large independents who has been successful in adding value through niche international projects. We will continue to grow our business in Trinidad and add a mix of quality international projects to our portfolio." Lindy Looger, Vice President & General Manager, EOG Resources Trinidad Ltd. & Gerald Colley, Vice President & General Manager, International Division 16 EOG RESOURCES, INC. EX-13 7 exhibit13financials.txt ANNUAL REPORT TO SECURITY HOLDERS - FINANCIALS Financial Review Management's Discussion and Analysis of Financial Condition and Results of Operations................ 18 Report of Independent Public Accountants......................... 24 Management's Responsibility for Financial Reporting.............. 25 Consolidated Statements of Income and Comprehensive Income....... 26 Consolidated Balance Sheets...................................... 27 Consolidated Statements of Shareholders' Equity.................. 28 Consolidated Statements of Cash Flows............................ 29 Notes to Consolidated Financial Statements....................... 30 Supplemental Information to Consolidated Financial Statements.... 43 Selected Financial Data.......................................... 52 Quarterly Stock Data and Related Shareholder Matters............. 53 2000 ANNUAL REPORT 17 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following review of operations for each of the three years in the period ended December 31, 2000 should be read in conjunction with the consolidated financial statements of EOG Resources, Inc. ("EOG") and notes thereto beginning with page 26. As a result of the consensus of Emerging Issues Task Force Issue 00-10, "Accounting for Shipping and Handling Fees and Costs," EOG reclassified all prior periods to reflect certain transportation expenses incurred as lease and well expenses, instead of deductions from revenues as previously reported. Results of Operations NET OPERATING REVENUES. Wellhead volume and price statistics for the specified years were as follows: Year Ended December 31, ------------------------------- 2000 1999 1998 ------ ------ ------ Natural Gas Volumes (MMcf per day) United States 654 654 671(1) Canada 129 115 105 Trinidad 125 123 139 India(2) - 46 56 ----------------------------------- Total 908 938 971 - -------------------------------------------------------------------- Average Natural Gas Prices ($/Mcf) United States $ 3.96 $ 2.20 $ 2.01(3) Canada 3.33 1.88 1.48 Trinidad 1.17 1.08 1.06 India(2) - 2.09 2.57 Composite 3.49 2.01 1.85 - -------------------------------------------------------------------- Crude Oil and Condensate Volumes (MBbl per day) United States 22.8 14.4 14.0 Canada 2.1 2.6 2.6 Trinidad 2.6 2.4 3.0 India(2) - 4.1 5.1 ----------------------------------- Total 27.5 23.5 24.7 - -------------------------------------------------------------------- Average Crude Oil and Condensate Prices ($/Bbl) United States $29.68 $18.55 $12.89 Canada 27.76 16.77 11.82 Trinidad 30.14 16.21 12.26 India(2) - 12.80 12.86 Composite 29.57 17.12 12.69 - -------------------------------------------------------------------- Natural Gas Liquids Volumes (MBbl per day) United States 4.0 2.6 2.9 Canada 0.7 0.8 1.0 ---------------------------------- Total 4.7 3.4 3.9 - -------------------------------------------------------------------- Average Natural Gas Liquids Prices ($/Bbl) United States $20.45 $13.41 $ 9.50 Canada 16.75 8.23 5.32 Composite 19.87 12.24 8.38 - -------------------------------------------------------------------- Natural Gas Equivalent Volumes (MMcfe per day)(4) United States 814 757 771 Canada 146 134 128 Trinidad 141 138 157 India(2) - 70 86 ----------------------------------- Total 1,101 1,099 1,142 ----------------------------------- Total Bcfe Deliveries 403 401 417 - -------------------------------------------------------------------- (1) Includes 48 MMcf per day delivered under the terms of a volumetric production payment agreement effective October 1, 1992, as amended. Delivery obligations were terminated in December 1998. (2) See Note 4 to the Consolidated Financial Statements regarding the Share Exchange Agreement with Enron Corp. (3) Includes an average equivalent wellhead value of $1.88 per Mcf for the volumes detailed in note (1). (4) Includes natural gas, crude oil, condensate and natural gas liquids.
2000 COMPARED TO 1999. During 2000, net operating revenues increased $648 million to $1,490 million. Total wellhead revenues of $1,491 million increased by $641 million, or 75%, as compared to 1999. Average wellhead natural gas prices for 2000 were approximately 74% higher than the comparable period in 1999, increasing net operating revenues by $491 million. Average wellhead crude oil and condensate prices were up by 73%, increasing net operating revenues by $125 million. Wellhead natural gas volumes were approximately 3% lower than the comparable period in 1999, decreasing net operating revenues by $20 million. The decrease in wellhead natural gas volumes is primarily due to the transfer of producing properties in connection with the Share Exchange Agreement ("Share Exchange") described in Note 4 to the Consolidated Financial Statements, partially offset by increased deliveries in Canada and Trinidad. Wellhead crude oil and condensate volumes were 17% higher than in 1999, increasing net operating revenues by $26 million. The increase in wellhead crude oil and condensate volumes is primarily due to increased deliveries in the United States and Trinidad, partially offset by the transfer of producing properties in the Share Exchange and decreased deliveries in Canada. Natural gas liquids prices and deliveries were approximately 62% 18 EOG RESOURCES, INC. and 39% higher than 1999, increasing net operating revenues by $13 million and $6 million, respectively. Gains (losses) on sales of reserves and related assets and other, net totaled a gain of $8 million during 2000 compared to a loss of nearly $1 million in 1999. The difference is due primarily to a $7 million gain on sales of certain North America properties in 2000. Other marketing activities associated with sales and purchases of natural gas, and natural gas and crude oil price hedging and trading transactions decreased net operating revenue by $10 million during 2000, compared to a $7 million reduction in 1999. 1999 COMPARED TO 1998. During 1999, net operating revenues increased $34 million to $842 million. Total wellhead revenues of $850 million increased by $69 million, or 9%, as compared to 1998. Average wellhead natural gas prices for 1999 were approximately 9% higher than the comparable period in 1998 increasing net operating revenues by approximately $56 million. Average wellhead crude oil and condensate prices were up by 35% increasing net operating revenues by $38 million. Revenues from the sale of natural gas liquids increased $3 million primarily due to higher wellhead prices. Wellhead natural gas volumes were approximately 3% lower than the comparable period in 1998 decreasing net operating revenues by nearly $22 million. The decrease in volumes is primarily due to the transfer of producing properties in the Share Exchange and decreased deliveries in Trinidad. Production in Trinidad decreased 16 MMcf per day due primarily to decreased nominations and the temporary shut-in of a well in accordance with the terms of a field allocation agreement. North America wellhead natural gas production was approximately 1% lower than the comparable period in 1998. Wellhead crude oil and condensate volumes were 5% lower than in 1998 decreasing net operating revenues by $6 million. The decrease is primarily attributable to the Share Exchange and decreased deliveries in Trinidad. Gains (losses) on sales of reserves and related assets and other, net totaled a loss of $1 million during 1999 compared to a net gain of $18 million in 1998. The difference is due primarily to an $8 million loss in 1999 related to the anticipated disposition of certain international assets compared to a $27 million gain on sale of certain South Texas properties, partially offset by a $14 million provision for loss on certain physical natural gas contracts in 1998. Other marketing activities associated with sales and purchases of natural gas, natural gas and crude oil price hedging and trading transactions, and margins related to the volumetric production payment (in 1998) decreased net operating revenue by $7 million during 1999, compared to a $9 million addition in 1998. Operating Expenses 2000 COMPARED TO 1999. During 2000, operating expenses of $793 million were approximately $31 million lower than the $824 million incurred in 1999. Lease and well expenses increased $9 million to $141 million primarily due to continually expanding operations and increases in production activity in North America. Exploration expenses of $67 million and dry hole expenses of $17 million increased $14 million and $5 million, respectively, from 1999 due to increased exploratory drilling activities. Impairment of unproved oil and gas properties increased $4 million to $36 million as a result of increased acquisition of unproved leases in North America. Depreciation, depletion and amortization ("DD&A") expense decreased $90 million primarily due to charges of $15 million pursuant to a change in EOG's strategy related to certain offshore operations in the second quarter of 1999, the impairment of various North America properties in the fourth quarter of 1999, and non-recurring charges of $114 million related primarily to assets determined no longer central to EOG's business in the third quarter of 1999. General and administrative ("G&A") expenses decreased $16 million primarily due to non-recurring costs in 1999 of $14 million related to the Share Exchange, the potential sale of EOG and personnel expenses partially offset by savings resulting from the discontinuance of the India and China operations as a result of the Share Exchange. Taxes other than income increased $42 million reflecting higher state severance taxes associated with higher taxable wellhead revenues resulting from higher average prices. Total operating costs per unit of production, which include lease and well, DD&A, G&A, taxes other than income and interest expense, decreased 7% to $1.82 per thousand cubic feet equivalent ("Mcfe") in 2000 from $1.97 in 1999. This decrease is primarily due to lower per unit rates of DD&A and G&A, partially offset by higher per unit rates of taxes other than income and lease and well. Excluding the aforementioned 1999 charges of $15 million and $114 million in DD&A and $14 million in G&A, the per unit operating costs for EOG were $1.61 per Mcfe in 1999. The per unit operating costs in 2000 of $1.82 was $0.21 higher than this adjusted per unit operating costs of 1999 primarily due to a higher per unit rate of DD&A, taxes other than income and lease and well expense. 1999 COMPARED TO 1998. During 1999, operating expenses of $824 million were approximately $129 million higher than the $695 million incurred in 1998. 2000 ANNUAL REPORT 19 Lease and well expenses decreased $6 million to $132 million primarily due to the effects of the Share Exchange, fewer workovers, the effects of a warm winter and a continuing focus on controlling operating costs in all areas of EOG operations. Exploration expenses of $53 million and dry hole expenses of $12 million decreased $13 million and $11 million, respectively, from 1998 primarily due to implementation of cost provisions of certain new service agreements in North America. Impairment of unproved oil and gas properties of $32 million remained essentially flat compared to 1998. DD&A expense increased approximately $145 million to $460 million in 1999 primarily due to charges of $15 million pursuant to a change in EOG's strategy related to certain offshore operations in the second quarter and an impairment of various North America properties in the fourth quarter, and non-recurring charges of $114 million related primarily to assets determined no longer central to EOG's business in the third quarter. G&A expenses were $14 million higher than in 1998 due to non-recurring costs of $5 million related to the potential sale of EOG, $4 million related to personnel expenses and $9 million related to the completion of the Share Exchange partially offset by a reduction of $4 million resulting from the discontinuance of the India and China operations as a result of the Share Exchange. Total operating costs per unit of production, which include lease and well, DD&A, G&A, taxes other than income and interest expense, increased 32% to $1.97 per Mcfe in 1999 from $1.49 per Mcfe in 1998. This increase is primarily due to a higher per unit rate of DD&A, G&A and interest expense. Excluding the aforementioned charges of $15 million and $114 million in DD&A and $14 million in G&A, the per unit operating costs for EOG were $1.61 per Mcfe. The adjusted per unit operating costs were $0.12 higher compared to $1.49 per Mcfe for the comparable period in 1998 primarily due to a higher per unit rate of interest as a result of higher debt levels and a higher per unit rate of DD&A expense. OTHER INCOME (EXPENSE). Other income of $611 million for 1999 included a $575 million net gain from the Share Exchange, a $59.6 million gain on the sale of 3.2 million options owned by EOG to purchase Enron Corp. common stock, and a $19.4 million charge for estimated exit costs related to EOG's decision to dispose of certain international assets. INTEREST EXPENSE. The increase in net interest expense of $13 million from 1998 to 1999 primarily reflects a higher level of debt outstanding due to expanded worldwide operations and common stock repurchases (See Note 2 to the Consolidated Financial Statements). INCOME TAXES. Income tax provision increased approximately $238 million for 2000 as compared to 1999 as a result of a higher pre-tax income year to year after removing the non-taxable gain on the Share Exchange in 1999. Income tax provision decreased approximately $5 million for 1999 as compared to 1998 primarily due to lower pre-tax income year to year after removing the non-taxable gain on the Share Exchange in 1999. Capital Resources and Liquidity CASH FLOW. The primary sources of cash for EOG during the three-year period ended December 31, 2000 included funds generated from operations, proceeds from the sales of other assets, selected oil and gas reserves and related assets, funds from new borrowings and proceeds from equity offerings. Primary cash outflows included funds used in operations, exploration and development expenditures, common stock repurchases, dividends paid to EOG shareholders, repayments of debt and cash contributed to transferred subsidiaries in the Share Exchange. Net operating cash flows of $967 million in 2000 increased approximately $524 million as compared to 1999 due to higher net operating revenues resulting from higher prices, net of cash operating expenses, and higher tax benefits from stock options exercised partially offset by higher current income taxes. Changes in working capital and other liabilities decreased operating cash flows by $16 million as compared to 1999 primarily due to changes in accounts receivable, accrued royalties payable and accrued production taxes caused by fluctuation of commodity prices at each yearend. Net investing cash outflows of $667 million in 2000 increased by $304 million as compared to 1999 due primarily to increased exploration and development expenditures of $231 million (including producing property acquisitions), increased equity investments, and the non-recurrence of proceeds from sales of Enron Corp. options in 1999, partially offset by increased proceeds from sales of reserves and related assets. Changes in components of working capital associated with investing activities included changes in accounts payable associated with the accrual of exploration and development expenditures and changes in inventories which represent materials and equipment used in drilling and related activities. Cash used in financing activities in 2000 was $305 million as compared to $62 million in 1999. Financing activities in 2000 included repayments of debt of $131 million, common stock repurchases of $273 million and dividend payments of $26 million, partially offset by proceeds from sales of treasury stock of $127 million. 20 EOG RESOURCES, INC. Net operating cash flows of $444 million in 1999 increased approximately $40 million as compared to 1998 due to higher net operating revenues resulting from higher prices, net of cash operating expenses, and lower current income taxes. Changes in working capital and other liabilities decreased operating cash flows by $18 million as compared to 1998 primarily due to changes in accounts receivable, accrued royalties payable and accrued production taxes caused by fluctuation of commodity prices at each yearend. Net investing cash outflows of $363 million in 1999 decreased by $396 million as compared to 1998 due primarily to decreased exploration and development expenditures of $312 million (including producing property acquisitions) and higher proceeds from sales of other assets of $83 million partially offset by lower proceeds from sales of reserves and related assets of $51 million. Changes in components of working capital associated with investing activities included for all periods changes in accounts payable related to the accrual of exploration and development expenditures and changes in inventories which represent materials and equipment used in drilling and related activities. Cash used in financing activities in 1999 was $62 million as compared to cash provided by financing activities of $353 million in 1998. Financing activities in 1999 included funds used in the Share Exchange of $609 million, dividend payments of $17 million, transaction fees of $19 million associated with the Share Exchange and other financing transactions, and net repayment of $152 million of long-term debt, partially offset by net proceeds from common and preferred equity offerings of $725 million and proceeds from sales of treasury stock of $13 million. Discretionary cash flow available to common, a frequently used measure of performance for exploration and production companies, is generally derived by adjusting net income to include tax benefits on stock options exercised and to eliminate the effects of depreciation, depletion and amortization, impairment of unproved oil and gas properties, deferred income taxes, gains on sales of oil and gas reserves and related assets, certain other non-cash amounts, except for amortization of deferred revenue and exploration and dry hole costs. EOG generated discretionary cash flow available to common of approximately $1,007 million in 2000, $477 million in 1999 and $463 million in 1998. Discretionary cash flow available to common should not be considered as an alternative to income from operations or to cash flows from operating activities (as determined in accordance with accounting principles generally accepted in the United States) and should not be construed as an indication of a company's operating performance or as a measure of liquidity. EXPLORATION AND DEVELOPMENT EXPENDITURES. The table below sets out components of actual exploration and development expenditures for the years ended December 31, 2000, 1999 and 1998, along with the total budgeted for 2001, excluding acquisitions. Excluding India and Budgeted 2001 Expenditure Category Actual China Operations (excluding acquisitions) (In Millions) ------------------------------------------------------------------------------ 2000 1999 1998 1999 1998 - --------------------------------------------------------------------------------------------- Capital Drilling and Facilities $443 $319 $420 $293 $373 Leasehold Acquisitions 51 21 36 21 36 Producing Property Acquisitions 102 45 211 43 211 Capitalized Interest 7 11 13 8 9 ---------------------------------------------------- Subtotal 603 396 680 365 629 Exploration Costs 67 53 66 51 64 Dry Hole Costs 17 12 23 12 23 ---------------------------------------------------- Total $687 $461 $769 $428 $716 $700 - $800 ========================================================================================================================
2000 ANNUAL REPORT 21 Exploration and development expenditures increased $226 million in 2000 as compared to 1999 primarily due to increased exploration and development activities in the United States and Trinidad, and acquisitions of oil and gas properties in North America, partially offset by the Share Exchange and the acquisition of producing properties in the Big Piney area in the first quarter of 1999. HEDGING TRANSACTIONS. EOG's 2000 NYMEX-related natural gas and crude oil commodity price swaps decreased net operating revenues by $11 million and $6 million, respectively. At December 31, 2000, there were open crude oil commodity price swaps for 2001 covering approximately 0.7 MMBbl of crude oil at a weighted average price of $26.25 per barrel. There were no open natural gas commodity price swaps. FINANCING. EOG's long-term debt-to-total-capital ratio was 38% as of December 31, 2000 compared to 47% as of December 31, 1999. During 2000, total long-term debt decreased $131 million to $859 million primarily due to higher cash flow from operations primarily resulting from higher oil and gas prices, partially offset by additions to oil and gas properties and significant share repurchases of common stock. (See Note 2 to the Consolidated Financial Statements). The estimated fair value of EOG's long-term debt at December 31, 2000 and 1999 was $831 million and $933 million, respectively, based upon quoted market prices and, where such prices were not available, upon interest rates currently available to EOG at yearend. EOG's debt is primarily at fixed interest rates. At December 31, 2000, a 1% change in interest rates would result in a $44 million change in the estimated fair value of the fixed rate obligations. (See Note 12 to the Consolidated Financial Statements). SHELF REGISTRATION. During the third quarter of 2000, EOG filed a shelf registration statement for the offer and sale from time to time of up to $600 million of EOG debt securities, preferred stock and/or common stock. Such registration statement was declared effective by the Securities and Exchange Commission on October 27, 2000. As of February 15, 2001, EOG had sold no securities pursuant to this shelf registration. When combined with the unused portion of a previously filed registration statement declared effective in January 1998, such registration statements provide for the offer and sale from time to time of EOG debt securities, preferred stock and/or common stock by EOG in an aggregate amount up to $688 million. OUTLOOK. Natural gas prices historically have been volatile, and this volatility is expected to continue. Uncertainty continues to exist as to the direction of future North America natural gas and crude oil price trends, and there remains a rather wide divergence in the opinions held by some in the industry. This divergence in opinion is caused by various factors including improvements in the technology used in drilling and completing crude oil and natural gas wells, improvements being realized in the availability and utilization of natural gas storage capacity and colder weather experienced in the latter part of 2000. However, the increasing recognition of natural gas as a more environmentally friendly source of energy along with the availability of significant domestically sourced supplies should result in further increases in demand. Being primarily a natural gas producer, EOG is more significantly impacted by changes in natural gas prices than by changes in crude oil and condensate prices. At December 31, 2000, based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2001 for which prices have not, in effect, been hedged using NYMEX-related commodity market transactions and long-term marketing contracts, EOG's price sensitivity for each $.10 per Mcf change in average wellhead natural gas prices is $19 million (or $0.16 per share) for net income and $19 million for current operating cash flow. EOG is not impacted as significantly by changing crude oil prices for those volumes not otherwise hedged. EOG's price sensitivity for each $1.00 per barrel change in average wellhead crude oil prices is $6 million (or $0.05 per share) for net income and $6 million for current operating cash flow. EOG plans to continue to focus a substantial portion of its exploration and development expenditures in its major producing areas in North America. However, in order to diversify its overall asset portfolio and as a result of its overall success realized in Trinidad, EOG anticipates expending a portion of its available funds in the further development of opportunities outside North America. In addition, EOG expects to conduct limited exploratory activity in other areas outside of North America and will continue to evaluate the potential for involvement in other exploitation type opportunities. Budgeted 2001 expenditures, excluding acquisitions, are in the range of $700 - $800 million, addressing the continuing uncertainty with regard to the future of the North America natural gas and crude oil and condensate price environment. Budgeted expenditures for 2001 are structured to maintain the flexibility necessary under EOG's continuing strategy of funding North America exploration, exploitation, development and acquisition activities primarily from available internally generated cash flow. 22 EOG RESOURCES, INC. The level of exploration and development expenditures may vary in 2001 and will vary in future periods depending on energy market conditions and other related economic factors. Based upon existing economic and market conditions, EOG believes net operating cash flow and available financing alternatives in 2001 will be sufficient to fund its net investing cash requirements for the year. However, EOG has significant flexibility with respect to its financing alternatives and adjustment of its exploration, exploitation, development and acquisition expenditure plans if circumstances warrant. While EOG has certain continuing commitments associated with expenditure plans related to operations in Trinidad, such commitments are not anticipated to be material when considered in relation to the total financial capacity of EOG. ENVIRONMENTAL REGULATIONS. Various federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to protection of the environment, may affect EOG's operations and costs as a result of their effect on natural gas and crude oil exploration, exploitation, development and production operations. Compliance with such laws and regulations has not had a material adverse effect on EOG's operations or financial condition. It is not anticipated, based on current laws and regulations, that EOG will be required in the near future to expend amounts that are material in relation to its total exploration and development expenditure program by reason of environmental laws and regulations. However, inasmuch as such laws and regulations are frequently changed, EOG is unable to predict the ultimate cost of compliance. New Accounting Pronouncement - SFAS No. 133 In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 133--"Accounting for Derivative Instruments and Hedging Activities" effective for fiscal years beginning after June 15, 1999. In June 1999, the FASB issued SFAS No. 137, which delayed the effective date of SFAS No. 133 for one year, to fiscal years beginning after June 15, 2000. In June 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. SFAS No. 133, as amended by SFAS No. 137 and No. 138, cannot be applied retroactively and must be applied to (a) derivative instruments and (b) certain derivative instruments embedded in hybrid contracts that were issued, acquired or substantively modified after a transition date to be selected by EOG of either December 31, 1997 or December 31, 1998. The statement establishes accounting and reporting standards requiring that every derivative instrument 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. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the statements of income and requires a company to formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment. EOG adopted SFAS No. 133, as amended by SFAS No. 137 and No. 138, on January 1, 2001 for the accounting periods which begin thereafter. The adoption of SFAS No. 133 did not have a material impact on EOG's financial statements. Information Regarding Forward-Looking Statements This Annual Report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical facts, including, among others, statements regarding EOG's future financial position, business strategy, budgets, reserve information, projected levels of production, projected costs and plans and objectives of management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "strategy," "intend," "plan" and "believe" or the negative of those terms or other variations of them or by comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning future operating results or the ability to increase reserves or to generate income or cash flows are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes its expectations reflected in forward-looking statements are based on reasonable assumptions, no assurance can be given that these expectations will be achieved. Important factors that could cause actual results to differ materially from the expectations reflected in the forward-looking statements include, among others: timing and extent of changes in commodity prices for crude oil, natural gas and related products and interest rates; extent of EOG's success in discovering, developing, marketing and producing reserves and in acquiring oil and gas properties; political developments around the world; and financial market conditions. In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements might not occur. EOG undertakes no obligations to update or revise its forward-looking statements, whether as a result of new information, future events or otherwise. 2000 ANNUAL REPORT 23 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To EOG Resources, Inc.: We have audited the accompanying consolidated balance sheets of EOG Resources, Inc. (a Delaware corporation) and subsidiaries as of December 31, 2000 and 1999, and the related consolidated statements of income and comprehensive income, 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 EOG Resources, 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. /s/ ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP Houston, Texas February 15, 2001 24 EOG RESOURCES, INC. Management's Responsibility for Financial Reporting The following consolidated financial statements of EOG Resources, Inc. and its subsidiaries ("EOG") were prepared by management, which is responsible for their integrity, objectivity and fair presentation. The statements have been prepared in conformity with accounting principles generally accepted in the United States and, accordingly, include some amounts that are based on the best estimates and judgments of management. Arthur Andersen LLP, independent public accountants, was engaged to audit the consolidated financial statements of EOG and issue a report thereon. In the conduct of the audit, Arthur Andersen LLP was given unrestricted access to all financial records and related data including minutes of all meetings of shareholders, the Board of Directors and committees of the Board. Management believes that all representations made to Arthur Andersen LLP during the audit were valid and appropriate. The system of internal controls of EOG is designed to provide reasonable assurance as to the reliability of financial statements and the protection of assets from unauthorized acquisition, use or disposition. This system includes, but is not limited to, written policies and guidelines including a published code for the conduct of business affairs, conflicts of interest and compliance with laws regarding antitrust, antiboycott and foreign corrupt practices policies, the careful selection and training of qualified personnel, and a documented organizational structure outlining the separation of responsibilities among management representatives and staff groups. The adequacy of financial controls of EOG and the accounting principles employed in financial reporting by EOG are under the general oversight of the Audit Committee of the Board of Directors. No member of this committee is an officer or employee of EOG. The independent public accountants and internal auditors have direct access to the Audit Committee and meet with the committee from time to time to discuss accounting, auditing and financial reporting matters. It should be recognized that there are inherent limitations to the effectiveness of any system of internal control, including the possibility of human error and circumvention or override. Accordingly, even an effective system can provide only reasonable assurance with respect to the preparation of reliable financial statements and safeguarding of assets. Furthermore, the effectiveness of an internal control system can change with circumstances. It is management's opinion that, considering the criteria for effective internal control over financial reporting and safeguarding of assets which consists of interrelated components including the control environment, risk assessment process, control activities, information and communication systems, and monitoring, EOG maintained an effective system of internal control as to the reliability of financial statements and the protection of assets against unauthorized acquisition, use or disposition during the year ended December 31, 2000. /s/ TIMOTHY K. DRIGGERS - -------------------------- Timothy K. Driggers Vice President, Accounting and Land Administration /s/ EDMUND P. SEGNER, III - ---------------------------- Edmund P. Segner, III President and Chief of Staff /s/ MARK G. PAPA - ---------------------------- Mark G. Papa Chairman and Chief Executive Officer Houston, Texas February 15, 2001 2000 ANNUAL REPORT 25 CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME Year Ended December 31, -------------------------------------- (In Thousands, Except Per Share Amounts) 2000 1999 1998 - ---------------------------------------------------------------------------------------------------------------- Net Operating Revenues Natural Gas $1,155,804 $ 683,469 $ 658,949 Crude Oil, Condensate and Natural Gas Liquids 325,726 159,373 131,052 Gains (Losses) on Sales of Reserves and Related Assets and Other, Net 8,365 (743) 18,251 -------------------------------------- Total 1,489,895 842,099 808,252 Operating Expenses Lease and Well 140,915 132,233 137,932 Exploration Costs 67,196 52,773 65,940 Dry Hole Costs 17,337 11,893 22,751 Impairment of Unproved Oil and Gas Properties 35,717 31,608 32,076 Depreciation, Depletion and Amortization 370,026 459,877 315,106 General and Administrative 66,932 82,857 69,010 Taxes Other Than Income 94,909 52,670 51,776 -------------------------------------- Total 793,032 823,911 694,591 -------------------------------------- Operating Income 696,863 18,188 113,661 Other Income (Expense) Gain on Share Exchange - 575,151 - Other, Net (2,300) 36,192 (4,800) -------------------------------------- Total (2,300) 611,343 (4,800) -------------------------------------- Income Before Interest Expense and Income Taxes 694,563 629,531 108,861 Interest Expense Incurred 67,714 72,413 61,290 Capitalized (6,708) (10,594) (12,711) -------------------------------------- Net Interest Expense 61,006 61,819 48,579 -------------------------------------- Income Before Income Taxes 633,557 567,712 60,282 Income Tax Provision (Benefit) 236,626 (1,382) 4,111 -------------------------------------- Net Income 396,931 569,094 56,171 Preferred Stock Dividends (11,028) (535) - -------------------------------------- Net Income Available to Common $ 385,903 $ 568,559 $ 56,171 ====================================== Earnings Per Share available to Common Basic $ 3.30 $ 4.04 $ 0.36 ====================================== Diluted $ 3.24 $ 4.01 $ 0.36 ====================================== Average Number of Common Shares Basic 116,934 140,648 154,002 ====================================== Diluted 119,102 141,627 154,573 ====================================== Net Income $ 396,931 $ 569,094 $ 56,171 Other Comprehensive Income (Loss) Foreign Currency Translation Adjustment (12,338) 16,038 (16,077) Unrealized Gain on Available-for-Sale Security, Net of Tax of $211 392 - - -------------------------------------- Comprehensive Income $ 384,985 $ 585,132 $ 40,094 =============================================================================================================== The accompanying notes are an integral part of these consolidated financial statements.
26 EOG RESOURCES, INC. At December 31, CONSOLIDATED BALANCE SHEETS ---------------------------- (In Thousands) 2000 1999 - ------------------------------------------------------------------------------------------------------- ASSETS Current Assets Cash and Cash Equivalents $ 20,152 $ 24,836 Accounts Receivable 342,579 148,189 Inventories 16,623 18,816 Other 15,073 8,660 ----------- ----------- Total 394,427 200,501 Oil and Gas Properties (Successful Efforts Method) 5,122,728 4,602,740 Less: Accumulated Depreciation, Depletion and Amortization (2,597,721) (2,267,812) ----------- ----------- Net Oil and Gas Properties 2,525,007 2,334,928 Other Assets 81,381 75,364 ----------- ----------- Total Assets $ 3,000,815 $ 2,610,793 =========== =========== LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities Accounts Payable $ 246,030 $ 172,780 Accrued Taxes Payable 78,838 19,648 Dividends Payable 4,525 4,227 Other 40,285 21,963 ----------- ----------- Total 369,678 218,618 Long-Term Debt 859,000 990,306 Other Liabilities 51,133 46,306 Deferred Income Taxes 340,079 225,952 Shareholders' Equity Preferred Stock, $.01 Par, 10,000,000 Shares Authorized: Series B, 100,000 shares Issued, Cumulative, $100,000,000 Liquidation Preference 97,879 97,909 Series D, 500 shares Issued, Cumulative, $50,000,000 Liquidation Preference 49,285 49,281 Common Stock, $.01 Par, 320,000,000 shares Authorized and 124,730,000 shares Issued 201,247 201,247 Additional Paid In Capital 4,221 - Unearned Compensation (3,756) (1,618) Accumulated Other Comprehensive Income (31,756) (19,810) Retained Earnings 1,301,067 930,938 Common Stock Held in Treasury, 7,825,708 shares at December 31, 2000 and 5,625,446 shares at December 31, 1999 (237,262) (128,336) ----------- ----------- Total Shareholders' Equity 1,380,925 1,129,611 ----------- ----------- Total Liabilities and Shareholders' Equity $ 3,000,815 $ 2,610,793 =========== =========== ====================================================================================================== The accompanying notes are an integral part of these consolidated financial statements.
2000 ANNUAL REPORT 27 CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY Accumulated Common Additional Other Stock Total Preferred Common Paid In Unearned Comprehensive Retained Held In Shareholders' (In Thousands, Stock Stock Capital Compensation Income Earnings Treasury Equity Except Per Share Amounts) - -------------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 1997 $ - $201,600 $ 402,877 $(4,694) $(19,771) $ 800,709 $ (99,672) $1,281,049 Net Income - - - - - 56,171 - 56,171 Common Stock Dividends Paid/ Declared, $.12 Per Share - - - - - (18,509) - (18,509) Translation Adjustment - - - - (16,077) - - (16,077) Treasury Stock Purchased - - - - - - (25,875) (25,875) Treasury Stock Issued Under Stock Option Plans - - (762) (1,709) - - 5,104 2,633 Tax Benefits from Stock Options Exercised - - 270 - - - - 270 Amortization of Unearned Compensation - - - 1,503 - - - 1,503 Other - - (861) - - - - (861) - ------------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 1998 - 201,600 401,524 (4,900) (35,848) 838,371 (120,443) 1,280,304 Net Income - - - - - 569,094 - 569,094 Preferred Stock Issued 147,175 - - - - - - 147,175 Amortization of Preferred Stock Discount 15 - - - - - - 15 Common Stock Issued - 270 577,662 - - - - 577,932 Preferred Stock Dividends Paid/Declared - - - - - (535) - (535) Common Stock Dividends Paid/ Declared, $.12 Per Share - - - - - (16,377) - (16,377) Translation Adjustment - - - - 16,038 - - 16,038 Treasury Stock Purchased - - - - - - (2,143) (2,143) Treasury Stock Received in Share Exchange - - - - - - (1,459,484) (1,459,484) Common Stock Retired - (623) (978,224) - - (458,033) 1,436,880 - Treasury Stock Issued Under Stock Option Plans - - (2,274) 136 - (1,582) 16,854 13,134 Tax Benefits from Stock Options Exercised - - 1,387 - - - - 1,387 Amortization of Unearned Compensation - - - 3,146 - - - 3,146 Other - - (75) - - - - (75) - ------------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 1999 147,190 201,247 - (1,618) (19,810) 930,938 (128,336) 1,129,611 Net Income - - - - - 396,931 - 396,931 Amortization of Preferred Stock Discount 419 - - - - (419) - - Exchange Offer Fees (445) - - - - - - (445) Preferred Stock Dividends Paid/Declared - - - - - (10,609) - (10,609) Common Stock Dividends Paid/ Declared, $.135 Per Share - - - - - (15,774) - (15,774) Translation Adjustment - - - - (12,338) - - (12,338) Unrealized Gain on Available- for-Sale Security - - - - 392 - - 392 Treasury Stock Purchased - - - - - - (272,723) (272,723) Treasury Stock Issued Under Stock Option Plans - - (36,701) - - - 163,350 126,649 Tax Benefits from Stock Options Exercised - - 41,307 - - - - 41,307 Restricted Stock and Units - - 2,805 (3,411) - - 606 - Amortization of Unearned Compensation - - - 1,273 - - - 1,273 Equity Derivative Transactions - - (3,190) - - - - (3,190) Other - - - - - - (159) (159) - ------------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 2000 $ 147,164 $201,247 $ 4,221 $(3,756) $(31,756) $1,301,067 $ (237,262) $1,380,925 =============================================================================================================================== The accompanying notes are an integral part of these consolidated financial statements.
28 EOG RESOURCES, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31, (In Thousands) ------------------------------------ 2000 1999 1998 - ------------------------------------------------------------------------------------------------------------------ Cash Flows from Operating Activities Reconciliation of Net Income to Net Operating Cash Inflows: Net Income $ 396,931 $ 569,094 $ 56,171 Items Not Requiring (Providing) Cash Depreciation, Depletion and Amortization 370,026 459,877 315,106 Impairment of Unproved Oil and Gas Properties 35,717 31,608 32,076 Deferred Income Taxes 97,729 (26,252) (26,794) Other, Net 6,693 25,583 7,761 Exploration Costs 67,196 52,773 65,940 Dry Hole Costs 17,337 11,893 22,751 Losses (Gains) On Sales of Reserves and Related Assets and Other, Net (5,977) 5,602 (11,191) Gains on Sales of Other Assets - (59,647) - Gain on Share Exchange - (575,151) - Tax Benefits from Stock Options Exercised 41,307 1,387 270 Other, Net (8,935) (19,081) 1,116 Changes in Components of Working Capital and Other Liabilities Accounts Receivable (191,492) (12,914) 36,363 Inventories 2,345 5,180 (7,541) Accounts Payable 97,374 4,395 (65,249) Accrued Taxes Payable 54,556 2,449 (8,754) Other Liabilities 348 (15,438) 2,324 Other, Net 11,378 (9,960) (3,620) Amortization of Deferred Revenue - - (43,344) Changes in Components of Working Capital Associated with Investing and Financing Activities (25,123) (7,879) 30,491 -------------------------------------- Net Operating Cash Inflows 967,410 443,519 403,876 Investing Cash Flows Additions to Oil and Gas Properties (602,638) (396,450) (680,520) Exploration Costs (67,196) (52,773) (65,940) Dry Hole Costs (17,337) (11,893) (22,751) Proceeds from Sales of Reserves and Related Assets 26,189 10,934 61,858 Proceeds from Sales of Other Assets - 82,965 - Changes in Components of Working Capital Associated with Investing Activities 22,798 7,909 (30,173) Other, Net (28,977) (4,057) (22,094) -------------------------------------- Net Investing Cash Outflows (667,161) (363,365) (759,620) Financing Cash Flows Long-Term Debt Trade (131,306) 47,527 394,004 Affiliate - (200,000) 7,500 Proceeds from Preferred Stock Issued - 147,175 - Proceeds from Common Stock Issued - 577,932 - Dividends Paid (26,071) (17,395) (18,504) Treasury Stock Purchased (272,723) (2,143) (25,875) Proceeds from Sales of Treasury Stock 127,090 13,341 2,613 Equity Contribution to Transferred Subsidiaries - (608,750) - Other, Net (1,923) (19,308) (7,021) -------------------------------------- Net Financing Cash Inflows (Outflows) (304,933) (61,621) 352,717 -------------------------------------- Increase (Decrease) in Cash and Cash Equivalents (4,684) 18,533 (3,027) Cash and Cash Equivalents at Beginning of Year 24,836 6,303 9,330 -------------------------------------- Cash and Cash Equivalents at End of Year $ 20,152 $ 24,836 $ 6,303 ==================================================================================================================== The accompanying notes are an integral part of these consolidated financial statements.
2000 ANNUAL REPORT 29 Notes to Consolidated Financial Statements 1. Summary of Significant Accounting Policies PRINCIPLES OF CONSOLIDATION. The consolidated financial statements of EOG Resources, Inc. ("EOG"), a Delaware corporation, include the accounts of all domestic and foreign subsidiaries. All material intercompany accounts and transactions have been eliminated. Certain reclassifications have been made to the consolidated financial statements for prior years to conform with the current presentation. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. CASH AND CASH EQUIVALENTS. EOG records as cash equivalents all highly liquid short-term investments with original maturities of three months or less. OIL AND GAS OPERATIONS. EOG accounts for its natural gas and crude oil exploration and production activities under the successful efforts method of accounting. Oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with significant acquisition costs are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. Amortization of any remaining costs of such leases begins at a point prior to the end of the lease term depending upon the length of such term. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive, based on historical experience, is amortized over the average holding period. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred. Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of natural gas and crude oil, are capitalized. Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. Estimated future dismantlement, restoration and abandonment costs (classified as long-term liabilities), net of salvage values, are taken into account. Certain other assets are depreciated on a straight-line basis. Periodically, or when circumstances indicate that an asset may be impaired, EOG compares expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on EOG's estimate of future crude oil and natural gas prices and operating costs and anticipated production from proved reserves are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. Inventories, consisting primarily of tubular goods and well equipment held for use in the exploration for, and development and production of natural gas and crude oil reserves, are carried at cost with adjustments made from time to time to recognize changes in value. Natural gas revenues are recorded on the entitlement method based on EOG's percentage ownership of current production. Each working interest owner in a well generally has the right to a specific percentage of production, although actual production sold may differ from an owner's ownership percentage. Under entitlement accounting, a receivable is recorded when underproduction occurs and a payable when overproduction occurs. Gains and losses associated with the sale of in place natural gas and crude oil reserves and related assets are classified as net operating revenues in the consolidated statements of income and comprehensive income based on EOG's strategy of continuing such sales in order to maximize the economic value of its assets. 30 EOG RESOURCES, INC. NEW ACCOUNTING PRONOUNCEMENTS IN 2000. In July 2000, the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board reached a consensus on EITF Issue 00-15, "Classification in the Statement of Cash Flows of the Income Tax Benefit Received by a Company upon Exercise of a Nonqualified Employee Stock Option." Pursuant to the consensus, reduction of income taxes paid as a result of the deduction triggered by employee exercise of stock options should be classified as an operating cash inflow. In accordance with EITF Issue 00-15, EOG reported tax benefits from stock options exercised as an operating cash inflow for the year 2000 and reclassified the amounts in the prior periods on the consolidated statements of cash flows to conform with the current year classification. In September 2000, the EITF reached a consensus on EITF Issue 00-10, "Accounting for Shipping and Handling Fees and Costs." Pursuant to the consensus, amounts paid related to certain transportation must be reported as an expense on the income statement rather than reporting revenues net of transportation as has been industry practice. In addition, pertinent amounts in financial statements for prior periods should be reclassified to reflect the same accounting treatment. In accordance with EITF Issue 00-10, EOG recorded transportation related amounts of $29.4 million, $40.7 million and $39.1 million in lease and well expense with a corresponding increase to revenues for 2000, 1999 and 1998, respectively, in the consolidated statements of income and comprehensive income. ACCOUNTING FOR PRICE RISK MANAGEMENT ACTIVITIES. EOG engages in price risk management activities from time to time primarily for non-trading and to a lesser extent for trading purposes. Derivative financial instruments (primarily price swaps and costless collars) are utilized selectively for non-trading purposes to hedge the impact of market fluctuations on natural gas and crude oil market prices. Hedge accounting is utilized in non-trading activities when there is a high degree of correlation between price movements in the derivative and the item designated as being hedged. Gains and losses on derivative financial instruments used for hedging purposes are recognized as revenue in the same period as the hedged item. Gains and losses on hedging instruments that are closed prior to maturity are deferred in the consolidated balance sheets and recognized as revenue in the same period as the hedged item. In instances where the anticipated correlation of price movements does not occur, hedge accounting is terminated and future changes in the value of the derivative are recognized as gains or losses using the mark-to-market method of accounting. Derivative and other financial instruments utilized in connection with trading activities, primarily price swaps and call options, are accounted for using the mark-to-market method, under which changes in the market value of outstanding financial instruments are recognized as gains or losses in the period of change. The cash flow impact of derivative and other financial instruments used for non-trading and trading purposes is reflected as cash flows from operating activities in the consolidated statements of cash flows. (See Notes 12 and 15 for new accounting pronouncement related to accounting for price risk management activities.) CAPITALIZED INTEREST COSTS. Certain interest costs have been capitalized as a part of the historical cost of unproved oil and gas properties and in work in progress for development drilling and related facilities with significant cash outlays. INCOME TAXES. EOG accounts for income taxes under the provisions of Statement of Financial Accounting Standards ("SFAS") No. 109--"Accounting for Income Taxes." SFAS No. 109 requires the asset and liability approach for accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax bases (See Note 5 "Income Taxes"). FOREIGN CURRENCY TRANSLATION. For subsidiaries whose functional currency is deemed to be other than the U.S. dollar, asset and liability accounts are translated at year-end exchange rates and revenue and expenses are translated at average exchange rates prevailing during the year. Translation adjustments are included as a separate component of shareholders' equity. Any gains or losses on transactions or monetary assets or liabilities in currencies other than the functional currency are included in net income in the current period. NET INCOME PER SHARE. In accordance with the provisions of SFAS No. 128--"Earnings per Share," basic net income per share is computed on the basis of the weighted-average number of common shares outstanding during the periods. Diluted net income per share is computed based upon the weighted-average number of common shares plus the assumed issuance of common shares for all potentially dilutive securities (See Note 8 "Net Income Per Share Available to Common" for additional information to reconcile the difference between the Average Number of Common Shares outstanding for basic and diluted net income per share). 2000 ANNUAL REPORT 31 2. Long-Term Debt Long-Term Debt at December 31 consisted of the following: ------------------------------- (In thousands) 2000 1999 - ------------------------------------------------------------------------ Commercial Paper $ - $123,186 Uncommitted Credit Facilities 38,800 87,000 6.50% Notes due 2004 100,000 100,000 6.70% Notes due 2006 150,000 150,000 6.50% Notes due 2007 100,000 100,000 6.00% Notes due 2008 175,000 175,000 6.65% Notes due 2028 150,000 150,000 Subsidiary Debt due 2001 105,000 105,000 Subsidiary Debt due 2002 40,200 - Other - 120 ------------------------------- Total $859,000 $990,306 ========================================================================
EOG maintains two credit facilities with different expiration dates. On July 26, 2000, the $400 million credit facility that was scheduled to expire was renewed for $375 million, thereby reducing aggregate long-term committed credit from $800 million at December 31, 1999 to $775 million. Credit facility expirations are as follows: $375 million in 2001 and $400 million in 2004. With respect to the $375 million expiring in 2001, EOG may, at its option, extend the final maturity date of any advances made under the facility by one full year from the expiration date of the facility, effectively qualifying such debt as long-term. Advances under both agreements bear interest, at the option of EOG, based upon a base rate or a Eurodollar rate. At December 31, 2000, there were no advances outstanding under either of these agreements. Commercial paper and short-term funding from uncommitted credit facilities provide financing for various corporate purposes and bear interest based upon market rates. Commercial paper and uncommitted credit borrowings are classified as long-term debt based on EOG's intent and ability to ultimately replace such amounts with other long-term debt. The 6.00% to 6.70% Notes due 2004 to 2028 were issued through public offerings and have effective interest rates of 6.14% to 6.83%. The Subsidiary Debt due 2001 was fully paid in January 2001 by increased borrowings from commercial paper and uncommitted credit facilities. The Subsidiary Debt due 2002 bears interest at variable market-based rates. At December 31, 2000, the aggregate annual maturities of long-term debt outstanding were $105 million for 2001, $40 million for 2002, none for 2003, $100 million for 2004 and none for 2005. SHELF REGISTRATION. During the third quarter of 2000, EOG filed a shelf registration statement for the offer and sale from time to time of up to $600 million of EOG debt securities, preferred stock and/or common stock. Such registration statement was declared effective by the Securities and Exchange Commission on October 27, 2000. As of February 15, 2001, EOG had sold no securities pursuant to this shelf registration. When combined with the unused portion of a previously filed registration statement declared effective in January 1998, such registration statements provide for the offer and sale from time to time of EOG debt securities, preferred stock and/or common stock by EOG in an aggregate amount up to $688 million. FAIR VALUE OF LONG-TERM DEBT. At December 31, 2000 and 1999, EOG had $859 million and $990 million, respectively, of long-term debt which had fair values of approximately $831 million and $933 million, respectively. The fair value of long-term debt is the value EOG would have to pay to retire the debt, including any premium or discount to the debtholder for the differential between the stated interest rate and the year-end market rate. The fair value of long-term debt is based upon quoted market prices and, where such quotes were not available, upon interest rates available to EOG at yearend. 3. Shareholders' Equity In February 1998, the Board of Directors authorized the purchase of an aggregate maximum of 10 million shares of common stock of EOG from time to time in the open market to be held in treasury for the purpose of, but not limited to, fulfilling any obligations arising under EOG's stock option plans and any other approved transactions or activities for which such common stock shall be required. In February 2000, as amended in December 2000, the Board of Directors authorized the purchase of an aggregate maximum of 15 million shares of common stock of EOG which replaced the remaining authorization from February 1998. At December 31, 2000 and 1999, 7,825,708 shares and 5,625,446 shares, respectively, were held in treasury under these authorizations. During the first half of 2000, to supplement its share repurchase program, EOG entered into a series of equity derivative transactions. Settlement alternatives for these equity derivative contracts under all circumstances are at the option of EOG and include physical share, net share and net cash settlement. The transactions were accounted for as equity transactions with premium received recorded to additional paid in capital in the consolidated balance sheets. During the third quarter of 2000, EOG closed substantially all of its equity derivative contracts which were to expire in April 2001 by paying $3.75 million. EOG had one million put 32 EOG RESOURCES, INC. options which it had written which were still outstanding at December 31, 2000. The strike price of these options is $18.00 per share, and they expire in April 2001. At December 31, 1999, there were no put options outstanding. At December 31, 1998, there were put options outstanding for 175,000 shares of common stock. On July 23, 1999, EOG filed a registration statement with the Securities and Exchange Commission for the public offering of 27,000,000 shares of EOG's common stock. The public offering was completed on August 16, 1999, and the net proceeds were used to repay short-term borrowings used to fund a significant portion of the cash capital contribution in connection with the Share Exchange Agreement ("Share Exchange") described in Note 4 "Transactions with Enron Corp. and Related Parties." As a result of the public offering and the retirement of the 62,270,000 shares of EOG's common stock received from Enron Corp. in the Share Exchange transaction, the number of shares of EOG's common stock issued was reduced to 124,730,000 from 160,000,000 prior to the Share Exchange. The following summarizes shares of common stock outstanding: (In thousands) 2000 1999 1998 - ------------------------------------------------------------------------- Outstanding at January 1 119,105 153,724 155,064 Repurchased (8,910) (130) (1,590) Issued Pursuant to Stock Options and Stock Plans 6,709 781 250 Retired - (62,270) - Public Offering - 27,000 - ------------------------------------ Outstanding at December 31 116,904 119,105 153,724 =========================================================================
In December 1999, EOG issued the following two series of preferred stock: SERIES A. On December 10, 1999, EOG issued 100,000 shares of Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series A, with a $1,000 Liquidation Preference per share, in a private transaction. Dividends will be payable on the shares only if declared by EOG's board of directors and will be cumulative. If declared, dividends will be payable at a rate of $71.95 per share, per year on March 15, June 15, September 15, and December 15 of each year beginning March 15, 2000. The dividend rate may only be adjusted in the event that certain amendments are made to the Dividend Received Percentage, as defined, within the first 18 months of the issuance date. EOG may redeem all or a part of the Series A preferred stock at any time beginning on December 15, 2009 at $1,000 per share, plus accrued and unpaid dividends. The shares may also be redeemable, in whole but not in part, in the event that certain amendments are made to the Dividend Received Percentage. The Series A preferred shares are not convertible into, or exchangeable for, common stock of EOG. SERIES C. On December 22, 1999, EOG issued 500 shares of Flexible Money Market Cumulative Preferred Stock, Series C, with a liquidation preference of $100,000 per share, in a private transaction. Dividends will be payable on the shares only if declared by EOG's board of directors and will be cumulative. The initial dividend rate on the shares will be 6.84% until December 15, 2004 (the "Initial Period-End Dividend Payment Date"). Through the Initial Period-End Dividend Payment Date dividends will be payable, if dec lared, on March 15, June 15, September 15, and December 15 of each year beginning March 15, 2000. The cash dividend rate for each subsequent dividend period will be determined pursuant to periodic auctions conducted in accordance with certain auction procedures. The first auction date will be December 14, 2004. After December 15, 2004 (unless EOG has elected a "Non-Call Period" for a subsequent dividend period), EOG may redeem the shares, in whole or in part, on any dividend payment date at $100,000 per share plus accumulated and unpaid dividends. The shares may also be redeemable, in whole but not in part, in the event that certain amendments are made to the Dividend Received Percentage. The Series C preferred shares are not convertible into, or exchangeable for, common stock of EOG. During the third quarter of 2000, EOG completed two exchange offers for its preferred stock whereby shares of EOG's Series A preferred stock were exchanged for shares of EOG's Series B preferred stock, and shares of EOG's Series C preferred stock were exchanged for shares of EOG's Series D preferred stock. All preferred shares were validly tendered and not withdrawn prior to expiration of the offers. EOG accepted all of the tendered shares and issued the respective series in exchange. Both exchange offers were registered under the Securities Act of 1933. The Series B preferred stock has substantially the same terms as Series A and the Series D preferred stock has substantially the same terms as Series C. On February 14, 2000, EOG's Board of Directors declared a dividend of one preferred share purchase right (a "Right" or "Rights Agreement") for each outstanding share of common stock, par value $.01 per share. The Board of Directors has adopted this Rights Agreement to protect stockholders from coercive or otherwise unfair takeover tactics. The dividend was distributed to the stockholders of record on February 24, 2000. Each Right, expiring February 24, 2010, represents a right to buy from EOG one hundredth (1/100) of a share of Series E Junior Participating Preferred Stock ("Preferred Share") for $90, once the Rights become exercisable. This portion of a Preferred Share will give the stockholder approximately the same dividend, voting, and 2000 ANNUAL REPORT 33 liquidation rights as would one share of common stock. Prior to exercise, the Right does not give its holder any dividend, voting, or liquidation rights. If issued, each one hundredth (1/100) of a Preferred Share (i) will not be redeemable; (ii) will entitle holders to quarterly dividend payments of $.01 per share, or an amount equal to the dividend paid on one share of common stock, whichever is greater; (iii) will entitle holders upon liquidation either to receive $1 per share or an amount equal to the payment made on one share of common stock, whichever is greater; (iv) will have the same voting power as one share of common stock; and (v) if shares of EOG's common stock are exchanged via merger, consolidation, or a similar transaction, will entitle holders to a per share payment equal to the payment made on one share of common stock. The Rights will not be exercisable until ten days after the public announcement that a person or group has become an acquiring person ("Acquiring Person") by obtaining beneficial ownership of 15% or more of EOG's common stock, or if earlier, ten business days (or a later date determined by EOG's Board of Directors before any person or group becomes an Acquiring Person) after a person or group begins a tender or exchange offer which, if consummated, would result in that person or group becoming an Acquir ing Person. The Board of Directors may reduce the threshold at which a person or a group becomes an Acquiring Person from 15% to not less than 10% of the outstanding common stock. If a person or group becomes an Acquiring Person, all holders of Rights except the Acquiring Person may, for $90, purchase shares of our common stock with a market value of $180, based on the market price of the common stock prior to such acquisition. If EOG is later acquired in a merger or similar transaction after the Rights become exercisable, all holders of Rights except the Acquiring Person may, for $90, purchase shares of the acquiring corporation with a market value of $180 based on the market price of the acquiring corporation's stock, prior to such merger. EOG's Board of Directors may redeem the Rights for $.01 per Right at any time before any person or group becomes an Acquiring Person. If the Board of Directors redeems any Rights, it must redeem all of the Rights. Once the Rights are redeemed, the only right of the holders of Rights will be to receive the redemption price of $.01 per Right. The redemption price will be adjusted if EOG has a stock split or stock dividends of EOG's common stock. After a person or group becomes an Acquiring Person, but before an Acquiring Person owns 50% or more of EOG's outstanding common stock, the Board of Directors may exchange the Rights for common stock or equivalent security at an exchange ratio of one share of common stock or an equivalent security for each such Right, other than Rights held by the Acquiring Person. 4. Transactions with Enron Corp. and Related Parties SHARE EXCHANGE. On August 16, 1999, EOG and Enron Corp. completed the Share Exchange whereby EOG received 62,270,000 shares of EOG's common stock out of 82,270,000 shares owned by Enron Corp. in exchange for all the stock of EOG's subsidiary, EOGI-India, Inc. Prior to the Share Exchange, EOG made an indirect capital contribution of approximately $600 million in cash, plus certain intercompany receivables, to EOGI-India, Inc. At the time of completion of this transaction, this subsidiary owned, through subsidiaries, all of EOG's assets and operations in India and China. EOG recognized a $575 million tax-free gain on the Share Exchange based on the fair value of the shares received, net of transaction fees of $14 million. Immediately following the Share Exchange, EOG retired the 62,270,000 shares of EOG's common stock received in the transaction. The weighted average basis in the treasury shares retired was first deducted from and fully eliminated existing additional paid in capital with the remaining value deducted from retained earnings. This transaction is a tax-free exchange to EOG. On August 30, 1999, EOG changed its corporate name to "EOG Resources, Inc." from "Enron Oil & Gas Company" and has since made similar changes to its subsidiaries' names. Immediately prior to the closing of the Share Exchange, Enron Corp. owned 82,270,000 shares of EOG's common stock, representing approximately 53.5 percent of all of the shares of EOG's common stock that were issued and outstanding. As a result of the closing of the Share Exchange, the sale by Enron Corp. of 8,500,000 shares of EOG's common stock as a selling stockholder in the public offering referred to above, and the completion on August 17, 1999 and August 20, 1999 of the offering of Enron Corp. notes mandatorily exchangeable at maturity into up to 11,500,000 shares of EOG's common stock, Enron Corp.'s maximum remaining interest in EOG after the automatic conversion of its notes on July 31, 2002, will be under two percent (assuming the notes are exchanged for less than the 11,500,000 shares of EOG's common stock). 34 EOG RESOURCES, INC. Effective as of August 16, 1999, the closing date of the Share Exchange, the members of the board of directors of EOG who were officers or directors of Enron Corp. resigned their positions as directors of EOG. NATURAL GAS AND CRUDE OIL, CONDENSATE AND NATURAL GAS LIQUIDS NET OPERATING REVENUES. Prior to the Share Exchange, Natural Gas and Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues included revenues from and associated costs paid to various subsidiaries and affiliates of Enron Corp. pursuant to contracts which, in the opinion of management, were no less favorable than could be obtained from third parties. Revenues from sales to Enron Corp. and its affiliates totaled $57.3 million in 1999 prior to the Share Exchange and $72.2 million in 1998. Natural Gas and Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues also included certain commodity price swap and NYMEX-related commodity transactions with Enron Corp. affiliated companies, which in the opinion of management, were no less favorable than could be received from third parties. (See Note 12 "Price and Interest Rate Risk Management"). GENERAL AND ADMINISTRATIVE EXPENSES. Prior to the Share Exchange, EOG was charged by Enron Corp. for all direct costs associated with its operations. Such direct charges, excluding benefit plan charges (See Note 6 "Employee Benefit Plans"), totaled $10.6 million and $14.2 million for the years ended December 31, 1999 and 1998, respectively. Additionally, certain administrative costs not directly charged to any Enron Corp. operations or business segments were allocated to the entities of the consolidated group. Approximately $3.4 million and $5.1 million was incurred by EOG for indirect general and administrative expenses for 1999 and 1998, respectively. Management believes that these charges were reasonable. SALE OF ENRON CORP. OPTIONS. In December 1997, EOG and Enron Corp. entered into an Equity Participation and Business Opportunity Agreement. Under the agreement, among other things, Enron Corp. granted EOG options to purchase 3.2 million shares of Enron Corp. During 1999, EOG sold the 3.2 million options and recognized a pre-tax gain of $59.6 million. The gain on sale of the options is included in other income (expense) - other, net in the consolidated statements of income and comprehensive income. 5. Income Taxes The principal components of EOG's net deferred income tax liability at December 31, 2000 and 1999 were as follows: (In thousands) 2000 1999 - ---------------------------------------------------------------------- Deferred Income Tax Assets Non-Producing Leasehold Costs $ 22,623 $ 25,199 Seismic Costs Capitalized for Tax 15,536 9,912 Alternative Minimum Tax Credit Carryforward - 21,772 Trading Activity 4,420 1,426 Section 29 Credit Monetization 12,774 15,657 Other 16,743 13,993 ------------------------- Total Deferred Income Tax Assets 72,096 87,959 ------------------------- Deferred Income Tax Liabilities Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization 403,808 299,704 Capitalized Interest 5,697 11,986 Other 2,670 2,221 ------------------------- Total Deferred Income Tax Liabilities 412,175 313,911 ------------------------- Net Deferred Income Tax Liability $340,079 $225,952 =======================================================================
The components of income (loss) before income taxes were as follows: (In thousands) 2000 1999 1998 - ----------------------------------------------------------- United States $491,417 $561,841 $ (3,297) Foreign 142,140 5,871 63,579 --------------------------------- Total $633,557 $567,712 $ 60,282 ===========================================================
2000 ANNUAL REPORT 35 Total income tax provision (benefit) was as follows: (In thousands) 2000 1999 1998 - ----------------------------------------------------------- Current: Federal $ 81,912 $ 5,510 $ 10,496 State 7,528 3,234 1,474 Foreign 49,457 16,126 18,935 ---------------------------------- Total 138,897 24,870 30,905 ================================== Deferred: Federal 78,833 (49,474) (31,279) State 10,324 (502) (4,589) Foreign 8,572 23,724 9,074 ---------------------------------- Total 97,729 (26,252) (26,794) ================================== Income Tax Provision (Benefit) $236,626 $ (1,382) $ 4,111 ===========================================================
The differences between taxes computed at the U.S. federal statutory tax rate and EOG's effective rate were as follows: 2000 1999 1998 - ----------------------------------------------------------------- Statutory Federal Income Tax Rate 35.00% 35.00% 35.00% State Income Tax, Net of Federal Benefit 1.83 0.31 (3.36) Income Tax Related to Foreign Operations 1.32 1.60 4.76 Tight Gas Sand Federal Income Tax Credits - (1.45) (17.36) Revision of Prior Years' Tax Estimates 0.16 (0.21) (10.78) Share Exchange - (35.46) - Other (.96) (.03) (1.45) ------------------------------- Effective Income Tax Rate 37.35% (0.24)% 6.81% =================================================================
EOG's foreign subsidiaries' undistributed earnings of approximately $380 million at December 31, 2000 are considered to be indefinitely invested outside the U.S. and, accordingly, no U.S. federal or state income taxes have been provided thereon. Upon distribution of those earnings in the form of dividends, EOG may be subject to both foreign withholding taxes and U.S. income taxes, net of allowable foreign tax credits. Determination of any potential amount of unrecognized deferred income tax liabilities is not practicable. In 2000, EOG fully utilized an alternative minimum tax credit carryforward of approximately $22 million to offset regular income taxes payable. In 1999 and 2000, EOG entered into arrangements with a third party whereby certain Section 29 credits were sold by EOG to the third party, and payments for such credits will be received on an as-generated basis. As a result of these transactions, EOG recorded a deferred tax asset representing a tax gain on the sale of the Section 29 credit properties, which will reverse as the results of operations of such properties are recognized for book purposes. 6. Employee Benefit Plans Employees of EOG were covered by various retirement, stock purchase and other benefit plans of Enron Corp. through August 1999. During each of the years ended December 31, 1999 and 1998, EOG was charged $4.4 million and $6.4 million, respectively, for all such benefits, including pension expense totaling $0.9 million and $1.3 million, respectively, by Enron Corp. PENSION AND POSTRETIREMENT PLANS. Since August 1999, EOG has adopted defined contribution pension plans for most of its employees in the United States. EOG's contributions to these plans are based on various percentages of compensation, and in some instances, are based upon the amount of the employees' contributions to the plan. From August 31, 1999 to December 31, 1999 the cost of these plans amounted to approximately $1.2 million. For 2000, the cost of these plans amounted to approximately $3.1 million. EOG also has in effect pension and savings plans related to its Canadian and Trinidadian subsidiaries. Activity related to these plans is not material relative to EOG's operations. During 2000, EOG adopted postretirement medical and dental benefits for eligible employees and their eligible dependents. Benefits are provided under the provisions of a contributory defined dollar benefit plan. EOG accrues these postretirement benefit costs over the service lives of the employees expected to be eligible to receive such benefits. As of December 31, 2000, the postretirement plan had a benefit obligation of $1.5 million and during 2000, EOG recognized a $0.3 million net periodic benefit cost related to this plan. STOCK PLANS. STOCK OPTIONS. EOG has various stock plans ("the Plans") under which employees of EOG and its subsidiaries and nonemployee members of the Board of Directors have been or may be granted rights to purchase shares of common stock of EOG at a price not less than the market price of the stock at the date of grant. Stock options granted under the Plans vest over a period of time based on the nature of the grants and as defined in the individual grant agreements. Terms for stock options granted under the Plans have not exceeded a maximum term of 10 years. 36 EOG RESOURCES, INC. EOG accounts for the stock options under the provisions and related interpretations of Accounting Principles Board Opinion No. 25 ("APB No. 25")--"Accounting for Stock Issued to Employees." No compensation expense is recognized for such options. As allowed by SFAS No. 123--"Accounting for Stock-Based Compensation" issued in 1995, EOG has continued to apply APB No. 25 for purposes of determining net income and to present the pro forma disclosures required by SFAS No. 123. The following table sets forth the option transactions under the Plans for the years ended December 31: 2000 1999 1998 ------------------------------------------------------------------ Average Average Average Grant Grant Grant (Options in thousands) Options Price Options Price Options Price - -------------------------------------------------------------------------------------------------------------- Outstanding at January 1 12,667 $18.66 15,036 $18.35 9,735 $19.99 Granted 1,317 30.88 1,280 19.88 5,949 15.76 Exercised (6,726) 18.90 (822) 16.22 (172) 15.14 Forfeited (202) 19.09 (2,827) 18.26 (476) 20.62 ------- ------- ------- Outstanding at December 31 7,056 20.70 12,667 18.66 15,036 18.35 ======= ======= ======= Options Exercisable at December 31 3,845 19.83 8,118 19.23 7,703 19.38 ======= ======= ======= Options Available for Future Grant 6,387 5,564 3,098 ======= ======= ======= Average Fair Value of Options Granted During Year $12.20 $ 7.43 $ 4.75 ==============================================================================================================
The fair value of each option grant is estimated using the Black-Scholes option-pricing model with the following weighted-average assumptions used for grants in 2000, 1999, and 1998, respectively: (1) dividend yield of 0.6%, 0.6% and 0.6%, (2) expected volatility of 30%, 28%, and 26%, (3) risk-free interest rate of 6.0%, 5.9%, and 5.1%, and (4) expected life of 6.0 years, 6.0 years and 4.9 years. The following table summarizes certain information for the options outstanding at December 31, 2000 (options in thousands): Options Outstanding Options Exercisable ---------------------------------- --------------------- Weighted Weighted Weighted Average Average Average Remaining Grant Grant Range of Grant Prices Options Life (years) Price Options Price - ----------------------------------------------------------------------- --------------------- $ 9.00 to $12.99 24 1 $ 9.45 24 $ 9.45 13.00 to 17.99 2,137 8 14.72 979 15.24 18.00 to 22.99 3,271 6 20.09 2,161 20.02 23.00 to 28.99 560 5 23.93 505 23.74 29.00 to 39.99 1,047 10 32.93 173 32.84 40.00 to 50.00 17 10 47.11 3 47.11 ------ ------ 7,056 7 20.70 3,845 19.83 ======================================================================= =====================
EOG's pro forma net income and net income per share of common stock for 2000, 1999 and 1998, had compensation costs been recorded in accordance with SFAS No. 123, are presented below: 2000 1999 1998 -------------------------------------------------------------------- As As As (In millions except per share data) Reported Pro Forma Reported Pro Forma Reported Pro Forma - --------------------------------------------------------------------------------------------------------------- Net Income Available to Common $ 385.9 $373.4 $ 568.6 $ 565.7 $ 56.2 $ 47.3 Net Income per Share Available to Common Basic $ 3.30 $3.19 $ 4.04 $ 4.02 $ .36 $ .31 =================================================================== Diluted $ 3.24 $3.14 $ 4.01 $ 3.99 $ .36 $ .31 ===============================================================================================================
2000 ANNUAL REPORT 37 The effects of applying SFAS No. 123 in this pro forma disclosure should not be interpreted as being indicative of future effects. SFAS No. 123 does not apply to awards prior to 1995, and the extent and timing of additional future awards cannot be predicted. The Black-Scholes model used by EOG to calculate option values, as well as other currently accepted option valuation models, were developed to estimate the fair value of freely tradable, fully transferable options without vesting and/or trading restrictions, which significantly differ from EOG's stock option awards. These models also require highly subjective assumptions, including future stock price volatility and expected time until exercise, which significantly affect the calculated values. Accordingly, management does not believe that this model provides a reliable single measure of the fair value of EOG's stock option awards. RESTRICTED STOCK AND UNITS. Under the Plans, participants may be granted restricted stock and/or units without cost to the participant. The shares and units granted vest to the participant at various times ranging from one to seven years. Upon vesting, the restricted shares are released to the participants and the restricted units released to the participants are converted into one share of common stock. The following summarizes shares of restricted stock and units granted: 2000 1999 1998 - --------------------------------------------------------------- Outstanding at January 1 265,168 345,334 284,000 Granted 200,566 23,000 108,500 Released to Participants (171,502) (37,166) (14,166) Forfeited or Expired (2,661) (66,000) (33,000) ---------- ---------- ---------- Outstanding at December 31 291,571 265,168 345,334 ========== ========== ========== Average Fair Value of Shares Granted During Year $ 16.10 $ 21.43 $ 20.11 ===============================================================
The fair value of the restricted shares and units at date of grant has been recorded in shareholders' equity as unearned compensation and is being amortized over the vesting period as compensation expense. Related compensation expense for 2000, 1999 and 1998 was approximately $1.3 million, $3.1 million and $1.5 million, respectively. TREASURY SHARES. During 2000, 1999 and 1998, EOG purchased 6,709,138, 130,000, and 249,788 of its common shares, respectively, to offset the dilution resulting from shares issued under the EOG employee stock plans. The difference between the cost of the treasury shares and the exercise price of the options, net of federal income tax benefit of $41.3 million, $1.4 million and $.3 million for the years 2000, 1999 and 1998, respectively, is reflected as an adjustment to additional paid in capital to the extent EOG has accumulated additional paid in capital relating to treasury stock and retained earnings thereafter. 7. Commitments and Contingencies LETTERS OF CREDIT. At December 31, 2000 and 1999, EOG had letters of credit and guaranties outstanding totaling approximately $122 million and $118 million, respectively. CONTINGENCIES. On July 21, 1999, two stockholders of EOG filed separate lawsuits purportedly on behalf of EOG against Enron Corp. and those individuals who were then directors of EOG, alleging that Enron Corp. and those directors breached their fiduciary duties of good faith and loyalty in approving the Share Exchange. The lawsuits seek to rescind the transaction or to receive monetary damages and costs and expenses, including reasonable attorneys' and experts' fees. EOG, Enron Corp. and the individual defendants believe the lawsuits are without merit and intend to vigorously contest them. EOG is engaged in arbitration hearings to settle a disagreement over the timing of the conversion of a 5% overriding royalty interest held by a third party in EOG's Trinidad SECC block to a 15% working interest. EOG does not expect the outcome to have a material adverse effect on EOG's financial position or results of operations. There are various other suits and claims against EOG that have arisen in the ordinary course of business. However, management does not believe these suits and claims will individually or in the aggregate have a material adverse effect on the financial condition or results of operations of EOG. EOG has been named as a potentially responsible party in certain Comprehensive Environmental Response Compensation and Liability Act proceedings. However, management does not believe that any potential assessments resulting from such proceedings will individually or in the aggregate have a materially adverse effect on the financial condition or results of operations of EOG. 38 EOG RESOURCES, INC. 8. Net Income Per Share Available to Common The following table sets forth the computation of basic and diluted earnings from net income available to common for the years ended December 31: (In thousands, except per share amounts) 2000 1999 1998 - ------------------------------------------------------------------------------------ Numerator for basic and diluted earnings per share - Net income available to common $385,903 $568,559 $ 56,171 ===================================== Denominator for basic earnings per share - Weighted average shares 116,934 140,648 154,002 Potential dilutive common shares - Stock options 2,038 964 461 Restricted stock and units 130 15 110 ------------------------------------- Denominator for diluted earnings per share - Adjusted weighted average shares 119,102 141,627 154,573 ===================================== Net income per share of common stock Basic $ 3.30 $ 4.04 $ 0.36 ===================================== Diluted $ 3.24 $ 4.01 $ 0.36 ====================================================================================
9. Supplemental Cash Flow Information On August 16, 1999, EOG and Enron Corp. completed the Share Exchange whereby EOG received 62,270,000 shares of EOG's common stock out of 82,270,000 shares owned by Enron Corp. in exchange for all the stock of EOG's subsidiary, EOGI-India, Inc (see Note 4 "Transactions with Enron Corp. and Related Parties"). Prior to the Share Exchange, EOG made an indirect capital contribution of approximately $600 million in cash, plus certain intercompany receivables, to EOGI-India, Inc. At the time of completion of this transaction, EOG's net investment in EOGI-India, Inc. was $870 million. Cash paid for interest and income taxes was as follows for the years ended December 31: (In thousands) 2000 1999 1998 - ------------------------------------------------------------------------ Interest (net of amount capitalized) $61,679 $67,965 $51,166 Income taxes 87,285 19,810 38,551 ========================================================================
10. Business Segment Information EOG's operations are all natural gas and crude oil exploration and production related. SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information," establishes standards for reporting information about operating segments in annual financial statements and requires selected information about operating segments in interim financial reports. Operating segments are defined as components of an enterprise about which separate financial information is available and evaluated regularly by the chief operating decision maker, or decision making group, in deciding how to allocate resources and in assessing performance. EOG's chief operating decision making group is the Executive Committee, which consists of the Chairman and Chief Executive Officer and other key officers. This group routinely reviews and makes operating decisions related to significant issues associated with each of EOG's major producing areas in the United States and each significant international location. For segment reporting purposes, the major U.S. producing areas have been aggregated as one reportable segment due to similarities in their operations as allowed by SFAS No. 131. 2000 ANNUAL REPORT 39 Financial information by reportable segment is presented below for the years ended December 31, or at December 31: (in thousands) United States Canada Trinidad India(1) Other(2) Total - --------------------------------------------------------------------------------------------------------------------------- 2000 Net Operating Revenues $1,223,315(3)(4) $184,092(3) $ 82,430 $ - $ 58 $1,489,895(3) Depreciation, Depletion and Amortization 316,814 39,253 13,959 - - 370,026 Operating Income (Loss) 552,091 103,229 41,974 - (431) 696,863 Interest Income 522 2,186 915 - 214 3,837 Other Income (Expense) (6,344) 302 31 - (126) (6,137) Interest Expense 59,841 7,550 323 - - 67,714 Income Tax Provision (Benefit) 181,506 31,159 24,076 - (115) 236,626 Additions to Oil and Gas Properties 499,207 69,157 33,223 - 1,051 602,638 Total Assets 2,465,204 374,476 159,872 - 1,263 3,000,815 - --------------------------------------------------------------------------------------------------------------------------- 1999 Net Operating Revenues $ 635,587(3)(4) $ 97,817(3) $ 62,689 $ 53,897 $ (7,891) $ 842,099(3) Depreciation, Depletion and Amortization 371,606 29,826 12,787 7,223 38,435 459,877 Operating Income (Loss) (7,714) 33,941 32,643 22,699 (63,381) 18,188 Interest Income 113 184 626 51 63 1,037 Other Income (Expense) 630,872 112 128 (992) (19,814) 610,306 Interest Expense 64,875 7,215 323 - - 72,413 Income Tax Provision (Benefit) (4,200) 4,637 18,484 8,858 (29,161) (1,382) Additions to Oil and Gas Properties 292,970 63,783 7,361 23,281 9,055 396,450 Total Assets 2,118,843 344,465 145,186 - 2,299 2,610,793 - --------------------------------------------------------------------------------------------------------------------------- 1998 Net Operating Revenues $ 597,215(4) $ 71,680 $ 66,967 $ 75,995 $ (3,605) $ 808,252 Depreciation, Depletion and Amortization 265,738 25,972 12,867 8,456 2,073 315,106 Operating Income (Loss) 54,272 11,908 42,094 41,718 (36,331) 113,661 Interest Income 216 88 507 205 131 1,147 Other Expense (559) - (150) (1,761) (3,477) (5,947) Interest Expense 53,773 6,558 859 100 - 61,290 Income Tax Provision (Benefit) (6,214) (1,112) 21,517 13,401 (23,481) 4,111 Additions to Oil and Gas Properties 539,978 48,898 19,214 46,479 25,951 680,520 Total Assets 2,238,969 277,861 131,964 289,596 79,705 3,018,095 ============================================================================================================================ (1) See Note 4 "Transactions with Enron Corp. and Related Parties." (2) Other includes China operations in 1999 and 1998. See Note 4 "Transactions with Enron Corp. and Related Parties." (3) Sales activities with a certain purchaser in the United States and Canada segments totaled approximately $183.2 million and $98.1 million of the consolidated Net Operating Revenues for 2000 and 1999, respectively. (4) Net Operating Revenues for the United States segment are net of costs related to natural gas marketing activities of $49.0 million, $44.6 million and $83.1 million for 2000, 1999 and 1998, respectively.
40 EOG RESOURCES, INC. 11. Other Income (Expense), Net Other income (expense) other, net for the year ended December 31, 1999, included the gain of $59.6 million on the sale of 3.2 million shares of Enron Corp. options granted to EOG under the 1997 Equity Participation and Business Opportunity Agreement with Enron Corp., and $19.4 million loss relating to anticipated costs of abandonment of certain international activities. 12. Price and Interest Rate Risk Management Activities Periodically, EOG enters into certain trading and non-trading activities including NYMEX-related commodity market transactions and other contracts. The non-trading portions of these activities have been designated to hedge the impact of market price fluctuations on anticipated commodity delivery volumes or other contractual commitments. TRADING ACTIVITIES. At December 31, 2000, EOG had outstanding swap contracts covering notional volumes of approximately 0.7 million barrels ("MMBbl") of crude oil and condensate for 2001. EOG elected not to designate these crude oil swap contracts as a hedge of its 2001 crude oil production, and accordingly, is accounting for these swap contracts under mark-to-market accounting. At December 31, 2000, the fair value of these swap contracts was $0.4 million. During 1999, EOG did not enter into derivative contracts that were accounted for as trading activities. Trading activities in 1998 included a revenue increase of $1.1 million related to the change in market value of natural gas price swap options exercisable by a counterparty and partially offsetting "buy" price swap positions. HEDGING TRANSACTIONS. At December 31, 2000, EOG had closed positions covering notional volumes of approximately 4 trillion British thermal units of natural gas for each of the years 2001 through 2005. At December 31, 2000, the aggregate deferred revenue reduction for 2001, 2002 and thereafter was approximately $1.2 million, $1.0 million and $3.8 million, respectively, and is classified as "Other Assets." During 2000, natural gas and crude oil and condensate revenues included a $17 million loss related to closed hedge positions. INTEREST RATE SWAP AGREEMENTS AND FOREIGN CURRENCY CONTRACTS. At December 31, 2000 and 1999, a subsidiary of EOG and EOG are parties to offsetting foreign currency and interest rate swap agreements with an aggregate notional principal amount of $210 million. Such swap agreements terminated in January 2001. In November 1998, EOG entered into two interest rate swap agreements having notional values of $100 million each. The agreements were entered into to hedge the base variable interest rates of EOG's commercial paper, uncommitted credit facilities and affiliated borrowings. These agreements terminated in November 2000. The following table summarizes the estimated fair value of financial instruments and related transactions for non-trading activities at December 31, 2000 and 1999: 2000 1999 -------------------------------------------------------- Carrying Estimated Carrying Estimated (In millions) Amount Fair Value(1) Amount Fair Value(1) - ---------------------------------------------------------------------------------------------------- Long-Term Debt(2) $ 859.0 $ 831.1 $ 990.3 $ 933.0 NYMEX-Related Commodity Market Positions (5.6) (5.6) (18.0) (20.3) ==================================================================================================== (1) Estimated fair values have been determined by using available market data and valuation methodologies. Judgment is necessarily required in interpreting market data and the use of different market assumptions or estimation methodologies may affect the estimated fair value amounts. (2) See Note 2 "Long-Term Debt."
2000 ANNUAL REPORT 41 CREDIT RISK. While notional contract amounts are used to express the magnitude of price and interest rate swap agreements, the amounts potentially subject to credit risk, in the event of nonperformance by the other parties, are substantially smaller. EOG does not anticipate nonperformance by the other parties. 13. Concentration of Credit Risk Substantially all of EOG's accounts receivable at December 31, 2000 and 1999 result from crude oil and natural gas sales and/or joint interest billings to third party companies including foreign state-owned entities in the oil and gas industry. This concentration of customers and joint interest owners may impact EOG's overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. In determining whether or not to require collateral from a customer or joint interest owner, EOG analyzes the entity's net worth, cash flows, earnings, and credit ratings. Receivables are generally not collateralized. Historical credit losses incurred on receivables by EOG have been immaterial. 14. Accounting for Certain Long-Lived Assets In 1999, as a result of the change to EOG's portfolio of assets brought about by the Share Exchange (see Note 4"Transactions with Enron Corp. and Related Parties"), EOG conducted a re-evaluation of its overall business. As a result of this re-evaluation, some of EOG's projects were no longer deemed central to its business. EOG recorded non-cash charges in connection with the impairment and/or EOG's decision to dispose of such projects of $133 million pre-tax ($89 million after-tax). In addition, EOG recorded charges of $15 million pre-tax ($10 million after-tax) pursuant to a change in EOG's strategy related to certain offshore operations in the second quarter and an impairment of various North America properties in the fourth quarter of 1999 to depreciation, depletion and amortization expense. In the United States operating segment, a pre-tax impairment charge of $85 million was recorded to depreciation, depletion and amortization expense. The carrying values for assets determined to be impaired were adjusted to estimated fair values based on projected future discounted net cash flows for such assets. In the Other operating segment, a pre-tax charge of $36 million was recorded to depreciation, depletion and amortization expense to fully write-off EOG's basis and a pre-tax charge of $19 million was recorded to other income (expense)--other, net for the estimated exit costs related to EOG's decision to dispose of certain international operations. Net loss for the Other operating segment operations for 1999, excluding these charges, was approximately $3 million. 15. New Accounting Pronouncement--SFAS No. 133 In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 133--"Accounting for Derivative Instruments and Hedging Activities" effective for fiscal years beginning after June 15, 1999. In June 1999, the FASB issued SFAS No. 137, which delays the effective date of SFAS No. 133 for one year, to fiscal years beginning after June 15, 2000. In June 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. SFAS No. 133, as amended by SFAS No. 137 and No. 138, cannot be applied retroactively and must be applied to (a) derivative instruments and (b) certain derivative instruments embedded in hybrid contracts that were issued, acquired or substantively modified after a transition date to be selected by EOG of either December 31, 1997 or December 31, 1998. The statement establishes accounting and reporting standards requiring that every derivative instrument 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. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the statements of income and requires a company to formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment. EOG adopted SFAS No. 133, as amended by SFAS No. 137 and No. 138, on January 1, 2001 for the accounting periods which begin thereafter. The adoption of SFAS No. 133 did not have a material impact on EOG's financial statements. 42 EOG RESOURCES, INC. Supplemental Information to Consolidated Financial Statements (In Thousands Except Per Share Amounts Unless Otherwise Indicated) (Unaudited Except for Results of Operations for Oil and Gas Producing Activities) Oil and Gas Producing Activities The following disclosures are made in accordance with SFAS No. 69--"Disclosures about Oil and Gas Producing Activities": OIL AND GAS RESERVES. Users of this information should be aware that the process of estimating quantities of "proved," "proved developed" and "proved undeveloped" crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures. Proved reserves represent estimated quantities of natural gas, crude oil, condensate, and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. Proved developed reserves are proved reserves expected to be recovered, through wells and equipment in place and under operating methods being utilized at the time the estimates were made. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir. Canadian provincial royalties are determined based on a graduated percentage scale which varies with prices and production volumes. Canadian reserves, as presented on a net basis, assume prices and royalty rates in existence at the time the estimates were made, and EOG's estimate of future production volumes. Future fluctuations in prices, production rates, or changes in political or regulatory environments could cause EOG's share of future production from Canadian reserves to be materially different from that presented. As a result of the re-evaluation of EOG's portfolio of assets following the Share Exchange, on November 12, 1999 senior management proposed to the Board of Directors ("the Board") of EOG to defer the development of the Big Piney Madison deep Paleozoic formation methane reserves in Wyoming for the foreseeable future. The Board approved the recommendation. As a result, the 1.2 trillion cubic feet of methane reserves in the formation, which are located on acreage owned by EOG and held by production for the foreseeable future, and which were classified as proved undeveloped reserves at December 31, 1998, were removed as a revision during 1999. At December 31, 1998, these reserves represented approximately $100 million or 5% of EOG's Standardized Measure of Discounted Future Net Cash Flows as adjusted for the sale of the India and China reserves as a result of the Share Exchange. At December 31, 2000, EOG had no plan to develop these reserves for the foreseeable future. Estimates of proved and proved developed reserves at December 31, 2000, 1999 and 1998 were based on studies performed by the engineering staff of EOG for reserves in the United States, Canada, Trinidad, India and China (See Note 4 to the Consolidated Financial Statements regarding operations transferred under the Share Exchange). Opinions by DeGolyer and MacNaughton ("D&M"), independent petroleum consultants, for the years ended December 31, 2000, 1999, and 1998 covered producing areas containing 49%, 52% and 39%, respectively, of proved reserves, excluding deep Paleozoic methane reserves in 1998 and 1997, of EOG on a net-equivalent-cubic-feet-of-gas basis. D&M's opinions indicate that the estimates of proved reserves prepared by EOG's engineering staff for the properties reviewed by D&M, when compared in total on a net-equivalent-cubic-feet-of-gas basis, do not differ materially from the estimates prepared by D&M. The deep Paleozoic methane reserves were covered by the opinion of D&M for the year ended December 31, 1995. Such estimates by D&M in the aggregate varied by not more than 5% from those prepared by the engineering staff of EOG. All reports by D&M were developed utilizing geological and engineering data provided by EOG. 2000 ANNUAL REPORT 43 No major discovery or other favorable or adverse event subsequent to December 31, 2000 is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date. The following table sets forth EOG's net proved and proved developed reserves at December 31 for each of the four years in the period ended December 31, 2000, and the changes in the net proved reserves for each of the three years in the period then ended as estimated by the engineering staff of EOG. Net Proved and Proved Developed Reserve Summary United States Canada Trinidad SUBTOTAL India(2) Other(3) TOTAL - --------------------------------------------------------------------------------------------------------------------------------- Natural Gas (Bcf)(1) Net proved reserves at December 31, 1997 2,784.8(4) 387.4 328.8 3,501.0 471.6 7.7 3,980.3 Revisions of previous estimates (55.9) (2.5) 4.7 (53.7) 32.3 (0.4) (21.8) Purchases in place 123.0 54.9 - 177.9 - - 177.9 Extensions, discoveries and other additions 272.8 62.9 693.8 1,029.5 340.9 103.0 1,473.4 Sales in place (37.5) - - (37.5) - - (37.5) Production (233.8) (38.5) (50.9) (323.2) (20.2) - (343.4) ----------------------------------------------------------------------------- Net proved reserves at December 31, 1998 2,853.4(4) 464.2 976.4 4,294.0 824.6 110.3 5,228.9 Revisions of previous estimates (1,199.1)(5) (1.3) 4.5 (1,195.9) - - (1,195.9) Purchases in place 108.5 34.0 - 142.5 - - 142.5 Extensions, discoveries and other additions 208.2 69.8 51.0 329.0 - - 329.0 Sales in place(2) (70.9) (1.4) - (72.3) (807.9) (110.3) (990.5) Production (242.9) (41.8) (37.3) (322.0) (16.7) - (338.7) ----------------------------------------------------------------------------- Net proved reserves at December 31, 1999 1,657.2 523.5 994.6 3,175.3 - - 3,175.3 Revisions of previous estimates 47.2 6.4 (0.4) 53.2 - - 53.2 Purchases in place 188.8 39.4 - 228.2 - - 228.2 Extensions, discoveries and other additions 255.4 23.8 65.1 344.3 - - 344.3 Sales in place (84.2) (0.1) - (84.3) - - (84.3) Production (243.0) (47.3) (45.8) (336.1) - - (336.1) ----------------------------------------------------------------------------- Net proved reserves at December 31, 2000 1,821.4 545.7 1,013.5 3,380.6 - - 3,380.6 ================================================================================================================================= (Table continued on following page)
44 EOG RESOURCES, INC. United States Canada Trinidad SUBTOTAL India(2) Other(3) TOTAL - --------------------------------------------------------------------------------------------------------------------------------- Liquids (MBbl)(6)(7) Net proved reserves at December 31, 1997 31,649 9,006 6,901 47,556 30,095 - 77,651 Revisions of previous estimates (152) (504) (1,049) (1,705) 3,063 73 1,431 Purchases in place 3,104 - - 3,104 - - 3,104 Extensions, discoveries and other additions 9,396 448 11,429 21,273 11,501 1,089 33,863 Sales in place (1,039) - - (1,039) - - (1,039) Production (6,131) (1,358) (1,077) (8,566) (1,874) - (10,440) ------------------------------------------------------------------------------ Net proved reserves at December 31, 1998 36,827 7,592 16,204 60,623 42,785 1,162 104,570 Revisions of previous estimates 5,085 117 (72) 5,130 - - 5,130 Purchases in place 2,753 39 - 2,792 - - 2,792 Extensions, discoveries and other additions 9,520 2,416 509 12,445 - - 12,445 Sales in place(2) (121) (37) - (158) (41,306) (1,162) (42,626) Production (6,217) (1,231) (878) (8,326) (1,479) - (9,805) ------------------------------------------------------------------------------ Net proved reserves at December 31, 1999 47,847 8,896 15,763 72,506 - - 72,506 Revisions of previous estimates (1,951) 46 28 (1,877) - - (1,877) Purchases in place 3,948 - - 3,948 - - 3,948 Extensions, discoveries and other additions 12,433 404 738 13,575 - - 13,575 Sales in place (484) (2,474) - (2,958) - - (2,958) Production (9,780) (1,055) (957) (11,792) - - (11,792) ------------------------------------------------------------------------------ Net proved reserves at December 31, 2000 52,013 5,817 15,572 73,402 - - 73,402 ================================================================================================================================= Bcf Equivalent (Bcfe)(1) Net proved reserves at December 31, 1997 2,975.0(4) 441.3 370.2 3,786.5 652.0 7.7 4,446.2 Revisions of previous estimates (57.0) (5.5) (1.7) (64.2) 50.8 - (13.4) Purchases in place 141.6 54.9 - 196.5 - - 196.5 Extensions, discoveries and other additions 329.2 65.6 762.4 1,157.2 409.9 109.5 1,676.6 Sales in place (43.7) - - (43.7) - - (43.7) Production (270.6) (46.6) (57.3) (374.5) (31.4) - (405.9) ------------------------------------------------------------------------------ Net proved reserves at December 31, 1998 3,074.5(4) 509.7 1,073.6 4,657.8 1,081.3 117.2 5,856.3 Revisions of previous estimates (1,168.8)(5) (0.6) 4.1 (1,165.3) - - (1,165.3) Purchases in place 125.1 34.3 - 159.4 - - 159.4 Extensions, discoveries and other additions 265.3 84.3 54.0 403.6 - - 403.6 Sales in place(2) (71.6) (1.6) - (73.2) (1,055.7) (117.2) (1,246.1) Production (280.2) (49.2) (42.5) (371.9) (25.6) - (397.5) ------------------------------------------------------------------------------ Net proved reserves at December 31, 1999 1,944.3 576.9 1,089.2 3,610.4 - - 3,610.4 Revisions of previous estimates 35.5 6.8 (0.2) 42.1 - - 42.1 Purchases in place 212.5 39.4 - 251.9 - - 251.9 Extensions, discoveries and other additions 330.0 26.2 69.5 425.7 - - 425.7 Sales in place (87.1) (15.0) - (102.1) - - (102.1) Production (301.7) (53.7) (51.6) (407.0) - - (407.0) ------------------------------------------------------------------------------ Net proved reserves at December 31, 2000 2,133.5 580.6 1,106.9 3,821.0 - - 3,821.0 =================================================================================================================================
(Table continued on following page) 2000 ANNUAL REPORT 45 United States Canada Trinidad SUBTOTAL India(2) TOTAL - ------------------------------------------------------------------------------------------------------------------------ Net proved developed reserves at Natural Gas (Bcf) (1) December 31, 1997 1,349.0 370.9 328.8 2,048.7 286.6 2,335.3 December 31, 1998 1,429.7 387.4 283.0 2,100.1 407.4 2,507.5 December 31, 1999 1,446.5 451.1 250.2 2,147.8 - 2,147.8 December 31, 2000 1,498.6 479.4 207.0 2,185.0 - 2,185.0 --------------------------------------------------------------------- Liquids (MBbl) (6) (7) December 31, 1997 27,707 8,885 6,901 43,493 23,322 66,815 December 31, 1998 33,045 7,465 4,782 45,292 33,472 78,764 December 31, 1999 41,717 7,041 3,833 52,591 - 52,591 December 31, 2000 42,132 5,695 2,967 50,794 - 50,794 --------------------------------------------------------------------- Bcf Equivalents December 31, 1997 1,515.3 424.2 370.2 2,309.7 426.5 2,736.2 December 31, 1998 1,628.0 432.1 311.7 2,371.8 608.2 2,980.0 December 31, 1999 1,696.8 493.3 273.2 2,463.3 - 2,463.3 December 31, 2000 1,751.4 513.6 224.8 2,489.8 - 2,489.8 ======================================================================================================================== (1) Billion cubic feet or billion cubic feet equivalent, as applicable. (2) See Note 4 "Transactions with Enron Corp. and Related Parties." (3) Other includes China operations only. See Note 4 "Transactions with Enron Corp. and Related Parties." (4) Includes 1,180 Bcf of proved undeveloped methane reserves contained, along with high concentrations of carbon dioxide and other gases, in deep Paleozoic (Madison) formations in the Big Piney area of Wyoming. (5) Includes reduction of the 1,180 Bcf of proved undeveloped methane reserves mentioned in (4) as a result of EOG's decision to defer the development of the Big Piney Madison deep Paleozoic formation methane reserves in Wyoming for the foreseeable future. (6) Thousand barrels. (7) Includes crude oil, condensate and natural gas liquids.
CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES. The following table sets forth the capitalized costs relating to EOG's natural gas and crude oil producing activities at December 31, 2000 and 1999: 2000 1999 - ------------------------------------------------------------------- Proved Properties $ 4,966,667 $ 4,459,727 Unproved Properties 156,061 143,013 ---------------------------- Total 5,122,728 4,602,740 Accumulated depreciation, depletion and amortization (2,597,721) (2,267,812) ---------------------------- Net capitalized costs $ 2,525,007 $ 2,334,928 ===================================================================
COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES. The acquisition, exploration and development costs disclosed in the following tables are in accordance with definitions in SFAS No. 19--"Financial Accounting and Reporting by Oil and Gas Producing Companies." Acquisition costs include costs incurred to purchase, lease, or otherwise acquire property. Exploration costs include exploration expenses, additions to exploration wells including those in progress, and depreciation of support equipment used in exploration activities. 46 EOG RESOURCES, INC. Development costs include additions to production facilities and equipment, additions to development wells including those in progress and depreciation of support equipment and related facilities used in development activities. The following tables set forth costs incurred related to EOG's oil and gas activities for the years ended December 31: United States Canada Trinidad Other SUBTOTAL India(1) China(1) TOTAL - ----------------------------------------------------------------------------------------------------------------------- 2000 Acquisition Costs of Properties Unproved $ 45,456 $ 5,741 $ - $ - $ 51,197 $ - $ - $ 51,197 Proved 88,473 13,965 - - 102,438 - - 102,438 ----------------------------------------------------------------------------------- Subtotal 133,929 19,706 - - 153,635 - - 153,635 Exploration Costs 98,654 9,711 10,849 3,581 122,795 - - 122,795 Development Costs 335,053 46,000 29,688 - 410,741 - - 410,741 ----------------------------------------------------------------------------------- Subtotal 567,636 75,417 40,537 3,581 687,171 - - 687,171 Deferred Income Taxes 18,744 3,685 - - 22,429 - - 22,429 ----------------------------------------------------------------------------------- Total $586,380 $ 79,102 $ 40,537 $ 3,581 $709,600 $ - $ - $709,600 ======================================================================================================================= 1999 Acquisition Costs of Properties Unproved $ 18,964 $ 2,276 $ - $ - $ 21,240 $ - $ - $ 21,240 Proved 22,092 20,838 - - 42,930 - - 42,930 ----------------------------------------------------------------------------------- Subtotal 41,056 23,114 - - 64,170 - - 64,170 Exploration Costs 65,070 6,516 8,425 4,350 84,361 1,083 1,014 86,458 Development Costs 234,900 39,544 4,801 20 279,265 23,281 7,942 310,488 ----------------------------------------------------------------------------------- Subtotal 341,026 69,174 13,226 4,370 427,796 24,364 8,956 461,116 Deferred Income Taxes - - - - - - - - ----------------------------------------------------------------------------------- Total $341,026 $ 69,174 $ 13,226 $ 4,370 $427,796 $ 24,364 $ 8,956 $461,116 ======================================================================================================================= 1998 Acquisition Costs of Properties Unproved $ 32,925 $ 3,545 $ - $ - $ 36,470 $ - $ - $ 36,470 Proved 198,006 12,896 - - 210,902 - - 210,902 ----------------------------------------------------------------------------------- Subtotal 230,931 16,441 - - 247,372 - - 247,372 Exploration Costs 82,248 12,375 15,217 24,183 134,023 1,278 1,282 136,583 Development Costs 290,673 27,578 6,024 10,206 334,481 46,479 4,296 385,256 ----------------------------------------------------------------------------------- Subtotal 603,852 56,394 21,241 34,389 715,876 47,757 5,578 769,211 Deferred Income Taxes - - - - - - - - ----------------------------------------------------------------------------------- Total $603,852 $ 56,394 $ 21,241 $34,389 $715,876 $ 47,757 $ 5,578 $769,211 ======================================================================================================================= (1) See Note 4 "Transactions with Enron Corp. and Related Parties."
2000 ANNUAL REPORT 47 RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES(1). The following tables set forth results of operations for oil and gas producing activities for the years ended December 31: United States Canada Trinidad SUBTOTAL India(2) Other(3) TOTAL - ----------------------------------------------------------------------------------------------------------------------------- 2000 Operating Revenues Trade $1,118,434 $ 184,386 $ 82,430 $1,385,250 $ - $ 59 $1,385,309 Associated Companies 102,834 - - 102,834 - - 102,834 Gains (Losses) on Sales of Reserves and Related Assets 5,833 (294) - 5,539 - - 5,539 -------------------------------------------------------------------------------- Total 1,227,101 184,092 82,430 1,493,623 - 59 1,493,682 Exploration Expenses, including Dry Hole 72,000 4,881 7,314 84,195 - 337 84,532 Production Costs 172,464 31,785 15,669 219,918 - 129 220,047 Impairment of Unproved Oil and Gas Properties 33,647 2,070 - 35,717 - - 35,717 Depreciation, Depletion and Amortization 315,746 39,253 13,959 368,958 - 2 368,960 -------------------------------------------------------------------------------- Income (Loss) before Income Taxes 633,244 106,103 45,488 784,835 - (409) 784,426 Income Tax Provision (Benefit) 231,182 41,274 25,018 297,474 - (144) 297,330 -------------------------------------------------------------------------------- Results of Operations $ 402,062 $ 64,829 $ 20,470 $ 487,361 $ - $ (265) $ 487,096 ============================================================================================================================== 1999 Operating Revenues Trade $ 510,567 $ 86,581 $ 55,900 $ 653,048 $ 53,897 $ 39 $ 706,984 Associated Companies 125,204 11,161 - 136,365 - - 136,365 Gains (Losses) on Sales of Reserves and Related Assets 2,254 75 - 2,329 - (7,931) (5,602) -------------------------------------------------------------------------------- Total 638,025 97,817 55,900 791,742 53,897 (7,892) 837,747 Exploration Expenses, including Dry Hole 49,181 5,122 5,865 60,168 1,083 3,415 64,666 Production Costs 114,810 24,698 8,322 147,830 13,413 2,334 163,577 Impairment of Unproved Oil and Gas Properties 29,384 2,224 - 31,608 - - 31,608 Depreciation, Depletion and Amortization 370,536 29,826 12,787 413,149 7,223 38,436 458,808 -------------------------------------------------------------------------------- Income (Loss) before Income Taxes 74,114 35,947 28,926 138,987 32,178 (52,077) 119,088 Income Tax Provision (Benefit) 21,283 12,259 15,909 49,451 15,445 (18,227) 46,669 -------------------------------------------------------------------------------- Results of Operations $ 52,831 $ 23,688 $ 13,017 $ 89,536 $ 16,733 $(33,850) $ 72,419 ============================================================================================================================== 1998 Operating Revenues Trade $ 448,653 $ 56,543 $ 66,967 $ 572,163 $ 75,995 $ 52 $ 648,210 Associated Companies 121,112 15,132 - 136,244 - - 136,244 Gains (Losses) on Sales of Reserves and Related Assets 29,268 (15) - 29,253 - (3,658) 25,595 -------------------------------------------------------------------------------- Total 599,033 71,660 66,967 737,660 75,995 (3,606) 810,049 Exploration Expenses, including Dry Hole 63,875 7,496 2,027 73,398 1,278 14,015 88,691 Production Costs 119,012 22,773 7,361 149,146 16,786 3,666 169,598 Impairment of Unproved Oil and Gas Properties 29,952 2,124 - 32,076 - - 32,076 Depreciation, Depletion and Amortization 264,927 25,972 12,867 303,766 8,456 2,073 314,295 -------------------------------------------------------------------------------- Income (Loss) before Income Taxes 121,267 13,295 44,712 179,274 49,475 (23,360) 205,389 Income Tax Provision (Benefit) 22,944 3,840 24,592 51,376 23,748 (7,370) 67,754 -------------------------------------------------------------------------------- Results of Operations $ 98,323 $ 9,455 $ 20,120 $ 127,898 $ 25,727 $(15,990) $ 137,635 ============================================================================================================================== (1) Excludes net revenues associated with other marketing activities, interest charges, general corporate expenses and certain gathering and handling fees for each of the three years in the period ended December 31, 2000. The gathering and handling fees and other marketing net revenues are directly associated with oil and gas operations with regard to segment reporting as defined in SFAS No. 131--"Disclosures about Segments of an Enterprise and Related Information," but are not part of Disclosures about Oil and Gas Producing Activities as defined in SFAS No. 69. (2) See Note 4 "Transactions with Enron Corp. and Related Parties." (3) Other includes China (in 1999 and 1998) and other international operations. See Note 4 "Transactions with Enron Corp. and Related Parties."
48 EOG RESOURCES, INC. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES. The following information has been developed utilizing procedures prescribed by SFAS No. 69 and based on crude oil and natural gas reserve and production volumes estimated by the engineering staff of EOG. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating EOG or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of EOG. The future cash flows presented below are based on sales prices, cost rates, and statutory income tax rates in existence as of the date of the projections. It is expected that material revisions to some estimates of crude oil and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used. Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated. The following table sets forth the standardized measure of discounted future net cash flows from projected production of EOG's crude oil and natural gas reserves for the years ended December 31: United States Canada Trinidad SUBTOTAL India(1) Other(2) TOTAL - ----------------------------------------------------------------------------------------------------------------------------------- 2000 Future cash inflows $18,500,822 $ 4,704,243 $ 1,860,366 $25,065,431 $ - $ - $25,065,431 Future production costs (2,766,579) (389,819) (668,549) (3,824,947) - - (3,824,947) Future development costs (279,407) (44,011) (194,741) (518,159) - - (518,159) -------------------------------------------------------------------------------------------- Future net cash flows before income taxes 15,454,836 4,270,413 997,076 20,722,325 - - 20,722,325 Future income taxes (5,074,986) (1,451,776) (230,712) (6,757,474) - - (6,757,474) -------------------------------------------------------------------------------------------- Future net cash flows 10,379,850 2,818,637 766,364 13,964,851 - - 13,964,851 Discount to present value at 10% annual rate (4,368,717) (1,304,886) (377,811) (6,051,414) - - (6,051,414) -------------------------------------------------------------------------------------------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves(3) $ 6,011,133 $ 1,513,751 $ 388,553 $ 7,913,437 $ - $ - $ 7,913,437 =================================================================================================================================== 1999 Future cash inflows $ 4,653,014 $ 1,159,024 $ 1,455,951 $ 7,267,989 $ - $ - $ 7,267,989 Future production costs (1,277,485) (300,332) (486,902) (2,064,719) - - (2,064,719) Future development costs (175,039) (46,966) (158,778) (380,783) - - (380,783) -------------------------------------------------------------------------------------------- Future net cash flows before income taxes 3,200,490 811,726 810,271 4,822,487 - - 4,822,487 Future income taxes (630,876) (226,118) (253,373) (1,110,367) - - (1,110,367) -------------------------------------------------------------------------------------------- Future net cash flows 2,569,614 585,608 556,898 3,712,120 - - 3,712,120 Discount to present value at 10% annual rate (842,382) (207,717) (267,965) (1,318,064) - - (1,318,064) -------------------------------------------------------------------------------------------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves $ 1,727,232 $ 377,891 $ 288,933 $ 2,394,056 $ - $ - $ 2,394,056 =================================================================================================================================== 1998 Future cash inflows $ 5,471,121 $ 827,416 $ 1,210,060 $ 7,508,597 $2,384,459 $ 179,329 $10,072,385 Future production costs (1,280,875) (200,492) (347,431) (1,828,798) (556,609) (127,039) (2,512,446) Future development costs (316,175) (38,963) (161,424) (516,562) (392,546) (11,325) (920,433) -------------------------------------------------------------------------------------------- Future net cash flows before income taxes 3,874,071 587,961 701,205 5,163,237 1,435,304 40,965 6,639,506 Future income taxes (903,983) (119,655) (229,281) (1,252,919) (614,297) (7,111) (1,874,327) -------------------------------------------------------------------------------------------- Future net cash flows 2,970,088 468,306 471,924 3,910,318 821,007 33,854 4,765,179 Discount to present value at 10% annual rate (1,399,541) (161,988) (234,129) (1,795,658) (434,714) (13,893) (2,244,265) -------------------------------------------------------------------------------------------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves $ 1,570,547 $ 306,318 $ 237,795 $ 2,114,660 $ 386,293 $ 19,961 $ 2,520,914 =================================================================================================================================== (1) See Note 4 "Transactions with Enron Corp. and Related Parties." (2) Other includes China operations only. See Note 4 "Transactions with Enron Corp. and Related Parties." (3) Natural gas prices have declined significantly since December 31, 2000; consequently, the discounted future net cash flows would be significantly reduced if the standardized measure was calculated in the first quarter of 2001.
2000 ANNUAL REPORT 49 CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS. The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, for each of the three years in the period ended December 31, 2000. United States Canada Trinidad SUBTOTAL India(1) Other(2) TOTAL - ----------------------------------------------------------------------------------------------------------------------------------- December 31, 1997 $ 1,549,719(3) $ 277,312 $ 147,919 $ 1,974,950 $ 319,728 $ 5,776 $ 2,300,454 Sales and transfers of oil and gas produced, net of production costs (423,733) (48,902) (59,606) (532,241) (59,209) 3,664 (587,786) Net changes in prices and production costs (33,809) 10,445 (36,730) (60,094) (103,097) (6,961) (170,152) Extensions, discoveries, additions and improved recovery net of related costs 325,308 43,686 159,497 528,491 218,168 18,894 765,553 Development costs incurred 59,600 2,900 6,000 68,500 43,400 4,300 116,200 Revisions of estimated development costs (26,611) 3,584 (11,410) (34,437) (66,128) (3,233) (103,798) Revisions of previous quantity estimates (35,216) (4,109) (1,142) (40,467) 36,877 - (3,590) Accretion of discount 174,102 30,332 28,791 233,225 53,296 562 287,083 Net change in income taxes 47,745 (5,822) (122) 41,801 212 (428) 41,585 Purchases of reserves in place 156,818 20,131 - 176,949 - - 176,949 Sales of reserves in place (33,549) - - (33,549) - - (33,549) Changes in timing and other (189,827) (23,239) 4,598 (208,468) (56,954) (2,613) (268,035) - ----------------------------------------------------------------------------------------------------------------------------------- December 31, 1998 1,570,547(3) 306,318 237,795 2,114,660 386,293 19,961 2,520,914 Sales and transfers of oil and gas produced, net of production costs (520,961) (73,044) (47,578) (641,583) (40,484) 2,334 (679,733) Net changes in prices and production costs 265,946 77,195 76,381 419,522 - - 419,522 Extensions, discoveries, additions and improved recovery net of related costs 310,470 68,396 8,523 387,389 - - 387,389 Development costs incurred 42,500 16,100 - 58,600 23,820 8,010 90,430 Revisions of estimated development costs 133,741 687 8,178 142,606 - - 142,606 Revisions of previous quantity estimates (163,423)(4) (505) 2,051 (161,877) - - (161,877) Accretion of discount 171,588 33,815 37,790 243,193 - - 243,193 Net change in income taxes (27,883) (79,397) (22,874) (130,154) - - (130,154) Purchases of reserves in place 102,086 18,769 - 120,855 - - 120,855 Sales of reserves in place (81,607) (1,276) - (82,883) (369,629) (30,305) (482,817) Changes in timing and other (75,772) 10,833 (11,333) (76,272) - - (76,272) - ----------------------------------------------------------------------------------------------------------------------------------- December 31, 1999 1,727,232 377,891 288,933 2,394,056 - - 2,394,056 Sales and transfers of oil and gas produced, net of production costs (1,048,804) (152,602) (66,761) (1,268,167) - - (1,268,167) Net changes in prices and production costs 5,459,629 1,850,021 153,961 7,463,611 - - 7,463,611 Extensions, discoveries, additions and improved recovery net of related costs 1,502,377 94,379 20,544 1,617,300 - - 1,617,300 Development costs incurred 77,000 24,100 29,600 130,700 - - 130,700 Revisions of estimated development costs (19,055) 39 (39,590) (58,606) - - (58,606) Revisions of previous quantity estimates 153,862 30,376 (129) 184,109 - - 184,109 Accretion of discount 190,045 48,912 45,192 284,149 - - 284,149 Net change in income taxes (2,436,834) (606,556) 8,566 (3,034,824) - - (3,034,824) Purchases of reserves in place 671,604 136,138 - 807,742 - - 807,742 Sales of reserves in place (331,960) (22,454) - (354,414) - - (354,414) Changes in timing and other 66,037 (266,493) (51,763) (252,219) - - (252,219) - ----------------------------------------------------------------------------------------------------------------------------------- December 31, 2000 $ 6,011,133 $ 1,513,751 $ 388,553 $ 7,913,437 $ - $ - $ 7,913,437 =================================================================================================================================== (1) See Note 4 "Transactions with Enron Corp. and Related Parties." (2) Other includes China operations only. See Note 4 "Transactions with Enron Corp. and Related Parties." (3) Includes approximately $55,316 and $100,284 in 1997 and 1998, respectively, related to the reserves in the Big Piney deep Paleozoic formations. (4) Includes reserves reduction of approximately $172,057, discounted before income taxes, related to the reserves in the Big Piney deep Paleozoic formations.
50 EOG RESOURCES, INC. UNAUDITED QUARTERLY FINANCIAL INFORMATION Quarter Ended --------------------------------------------------- (In Thousands, Except Per Share Amounts) March 31 June 30 Sept. 30 Dec. 31 - ------------------------------------------------------------------------------------------------------------- 2000 Net Operating Revenues $ 259,897 $ 322,725 $ 402,152 $ 505,121 =================================================== Operating Income $ 80,210 $ 139,235 $ 203,658 $ 273,760 =================================================== Income before Income Taxes $ 65,659 $ 124,417 $ 188,943 $ 254,538 Income Tax Provision 24,169 46,900 72,466 93,091 --------------------------------------------------- Net Income 41,490 77,517 116,477 161,447 Preferred Stock Dividends (2,654) (2,860) (2,755) (2,759) --------------------------------------------------- Net Income Available to Common $ 38,836 $ 74,657 $ 113,722 $ 158,688 =================================================== Net Income per Share Available to Common Basic(1) $ 0.33 $ 0.64 $ 0.98 $ 1.36 =================================================== Diluted(1) $ 0.33 $ 0.63 $ 0.95 $ 1.33 =================================================== Average Number of Common Shares Basic 117,827 116,666 116,559 116,684 =================================================== Diluted 118,273 119,179 119,262 119,582 ============================================================================================================= 1999 Net Operating Revenues $ 169,561 $ 198,208 $ 236,887 $ 237,443 =================================================== Operating Income (Loss) $ (9,604) $ 15,695 $ (53,229) $ 65,326 =================================================== Income before Income Taxes $ 3,067 $ 32,273 $ 484,281 $ 48,091 Income Tax Provision (Benefit) (1,999) 11,635 (28,640) 17,622 --------------------------------------------------- Net Income 5,066 20,638 512,921 30,469 Preferred Stock Dividends - - - (535) --------------------------------------------------- Net Income Available to Common $ 5,066 $ 20,638 $ 512,921 $ 29,934 =================================================== Net Income per Share Available to Common Basic(1) $ 0.03 $ 0.13 $ 3.75 $ 0.25 =================================================== Diluted(1) $ 0.03 $ 0.13 $ 3.71 $ 0.25 =================================================== Average Number of Common Shares Basic 153,388 153,484 136,662 119,059 =================================================== Diluted 154,048 154,540 138,271 119,778 ============================================================================================================= (1) The sum of quarterly net income per share available to common may not agree with total year net income per share available to common as each quarterly computation is based on the weighted average of common shares outstanding.
2000 ANNUAL REPORT 51 SELECTED FINANCIAL DATA Year Ended December 31, ----------------------------------------------------------------- (In Thousands, Except Per Share Amounts) 2000 1999 1998 1997 1996 - -------------------------------------------------------------------------------------------------------------------------- Statement of Income Data: Net operating revenues $1,489,895 $ 842,099 $ 808,252 $ 820,451 $ 767,813 Operating expenses Lease and well 140,915 132,233 137,932 133,014 113,783 Exploration costs 67,196 52,773 65,940 57,696 55,009 Dry hole costs 17,337 11,893 22,751 17,303 13,193 Impairment of unproved oil and gas properties 35,717 31,608 32,076 27,213 21,226 Depreciation, depletion and amortization 370,026 459,877(1) 315,106 278,179 251,278 General and administrative 66,932 82,857 69,010 54,415 56,405 Taxes other than income 94,909 52,670 51,776 59,856 48,089 ----------------------------------------------------------------- Total 793,032 823,911 694,591 627,676 558,983 ----------------------------------------------------------------- Operating income 696,863 18,188 113,661 192,775 208,830 Other income (expense), net (2,300) 611,343(2) (4,800) (1,588) (5,007) Interest expense (net of interest capitalized) 61,006 61,819 48,579 27,717 12,861 ----------------------------------------------------------------- Income before income taxes 633,557 567,712 60,282 163,470 190,962 Income tax provision (benefit)(3) 236,626 (1,382) 4,111(4) 41,500(5) 50,954 ----------------------------------------------------------------- Net income 396,931 569,094 56,171 121,970 140,008 Preferred stock dividends (11,028) (535) - - - ----------------------------------------------------------------- Net income available to common $ 385,903 $ 568,559 $ 56,171 $ 121,970 $ 140,008 ================================================================= Net income per share available to common Basic $ 3.30 $ 4.04 $ 0.36 $ 0.78 $ 0.88 ================================================================= Diluted $ 3.24 $ 4.01 $ 0.36 $ 0.77 $ 0.87 ================================================================= Average number of common shares Basic 116,934 140,648 154,002 157,092 159,569 ================================================================= Diluted 119,102 141,627 154,573 157,663 160,708 ================================================================= At December 31, ----------------------------------------------------------------- (In Thousands) 2000 1999 1998 1997 1996 - -------------------------------------------------------------------------------------------------------------------------- Balance Sheet Data: Oil and gas properties - net $2,525,007 $2,334,928 $2,676,363 $2,387,207 $2,099,589 Total assets 3,000,815 2,610,793 3,018,095 2,723,355 2,458,353 Long-term debt Trade 859,000 990,306 942,779 548,775 466,089 Affiliate - - 200,000 192,500 - Deferred revenue - - 4,198 39,918 56,383 Shareholders' equity 1,380,925 1,129,611 1,280,304 1,281,049 1,265,090 =========================================================================================================================== (1) Includes $133 million non-cash charges in connection with impairments and/or the Company's decision to dispose of projects no longer deemed central to its business. (2) Includes a $575 million tax-free gain on the share exchange transactions (See Note 4 of Notes to Consolidated Financial Statements). (3) Includes benefits of approximately $8 million, $12 million, $12 million and $16 million in 1999, 1998, 1997 and 1996 respectively, relating to tight gas sand federal income tax credits. (4) Includes a benefit of $2 million related to the final audit assessments of India taxes for certain prior years, a benefit of $3.8 million related to reduced deferred franchise taxes, and $3.5 million related to cumulative Venezuela deferred tax benefits. (5) Includes a benefit of $15 million primarily associated with the refiling of certain Canadian tax returns and the sale of certain international assets and subsidiaries. (6) Includes a benefit of $9 million primarily associated with a reassessment of deferred tax requirements and the successful resolution on audit of Canadian income taxes for certain prior years.
52 EOG RESOURCES, INC. QUARTERLY STOCK DATA AND RELATED SHAREHOLDER MATTERS The following table sets forth, for the periods indicated, the high and low sales prices per share for the common stock of EOG, as reported on the New York Stock Exchange Composite Tape, and the amount of cash dividends declared per share. Price Range -------------------- Cash High Low Dividends - --------------------------------------------------------- 1999 First Quarter $ 18.38 $ 15.69 $0.030 Second Quarter 21.50 16.00 0.030 Third Quarter 25.38 19.25 0.030 Fourth Quarter 23.00 14.38 0.030 2000 First Quarter $ 24.06 $ 13.69 $0.030 Second Quart 34.88 21.75 0.035 Third Quarter 40.88 26.69 0.035 Fourth Quarter 56.69 35.31 0.035
As of March 12, 2001, there were approximately 380 record holders of EOG's common stock, including individual participants in security position listings. There are an estimated 33,630 beneficial owners of EOG's common stock, including shares held in street name. EOG currently intends to continue to pay quarterly cash dividends on its outstanding shares of common stock. However, the determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other things, the financial condition, funds from operations, level of exploration, exploitation and development expenditure opportunities and future business prospects of EOG. 2000 ANNUAL REPORT 53 OFFICERS AND DIRECTORS Fred C. Ackman(1) Gonzales, Texas Former Chairman, President and CEO The Superior Oil Company George A. Alcorn(2) Houston, Texas President, Alcorn Exploration, Inc. Mark G. Papa Houston, Texas Chairman and CEO EOG Resources, Inc. Edward Randall, III(3) Houston, Texas Investments Edmund P. Segner, III Houston, Texas President and Chief of Staff EOG Resources, Inc. Donald F. Textor(4) Locust Valley, New York Former Partner/ Managing Director, Goldman Sachs Frank G. Wisner(5) New York, New York Vice Chairman American International Group, Inc. and Former U.S. Ambassador to India, Philippines, Egypt & Zambia EXECUTIVE COMMITTEE Mark G. Papa Chairman and CEO Edmund P. Segner, III President and Chief of Staff Loren M. Leiker Executive Vice President, Exploration and Development Gary L. Thomas Executive Vice President, North America Operations Barry Hunsaker, Jr. Senior Vice President and General Counsel Sandeep Bhakhri Vice President and Chief Information Officer OFFICERS (INCLUDING KEY SUBSIDIARIES) Lewis P. Chandler, Jr. Senior Vice President, Law Lawrence E. Fenwick Senior Vice President and General Manager, EOG Resources Canada Inc. William R. Thomas Senior Vice President and General Manager, Midland Division William E. Albrecht Vice President, Acquisitions and Engineering Maire A. Baldwin Vice President, Investor Relations Ben B. Boyd Vice President, Finance and Accounting, EOG Resources International, Inc. Steven B. Coleman Vice President and General Manager, Oklahoma City Division Gerald R. Colley Vice President and General Manager, International Division President, EOG Resources International, Inc. Phil C. DeLozier Vice President, Business Development Kurt D. Doerr Vice President and General Manager, Denver Division Timothy K. Driggers Vice President, Accounting and Land Administration Patricia L. Edwards Vice President, Human Resources, Administration and Corporate Secretary Robert K. Garrison Vice President and General Manager, Corpus Christi Division Kevin S. Hanzel Vice President, Audit Andrew N. Hoyle Vice President, Marketing and Regulatory Affairs John D. Huppler Vice President and General Manager, Tyler Division Lindell L. Looger Vice President and General Manager, EOG Resources Trinidad Ltd. David R. Looney Vice President, Finance Susan M. Murray Vice President, Government Affairs Richard A. Ott Vice President, Tax Earl J. Ritchie, Jr. Vice President and General Manager, Offshore Division Gary L. Smith Vice President and General Manager, Pittsburgh Division Ann D. Janssen Treasurer (1) Chairman, Audit Committee; Member, Compensation and International Strategy Committees (2) Member, Audit, Compensation, and International Strategy Committees (3) Chairman, Compensation Committee; Member, Audit and International Strategy Committees (4) Member, Compensation and International Strategy Committees (5) Chairman, International Strategy Committee; Member, Compensation and Audit Committees 54 EOG RESOURCES, INC. GLOSSARY OF TERMS Bcf Billion cubic feet Bcfe Billion cubic feet equivalent Bbls/d Barrels per day BOE Barrels of oil equivalent CEO Chief Executive Officer Division Generic term for regional EOG office and/or subsidiary(ies) $/Bbl Dollars per barrel $/Mcf Dollars per thousand cubic feet E&P Exploration and production LOE Lease operating expense MBbl Thousand barrels MBbls/d Thousand barrels per day Mcf Thousand cubic feet Mcfe Thousand cubic feet equivalent Mcf/d Thousand cubic feet per day MMBbl Million barrels MMbtu Million British thermal units MMcf Million cubic feet MMcfe Million cubic feet equivalent MMcf/d Million cubic feet per day MMcfe/d Million cubic feet equivalent per day SECC South East Coast Consortium (Trinidad) Tcf Trillion cubic feet Tcfe Trillion cubic feet equivalent 2000 ANNUAL REPORT 55 SHAREHOLDER INFORMATION Corporate Headquarters 1200 Smith Street, Suite 300 Houston, Texas 77002 P.O. Box 4362 Houston, Texas 77210-4362 (713) 651-7000 Toll Free: (877) 363-EOGR Website: www.eogresources.com Common Stock Exchange Listing: New York Stock Exchange Ticker Symbol: EOG Common Stock Outstanding at December 31, 2000: 116,904,292 Principal Transfer Agent First Chicago Trust Company of New York, a division of EquiServe P.O. Box 2500 Jersey City, New Jersey 07303-2500 Toll Free: (800) 519-3111 Outside U.S.: (201) 324-1225 Website: www.equiserve.com Hearing Impaired: TDD (201) 222-4955 Additional Information The Annual Meeting of Shareholders will be held at 2 p.m. CDT in the Granger "B" Ballroom of the Doubletree Hotel at Allen Center, 400 Dallas Street, Houston, Texas on Tuesday, May 8, 2001. Information with respect to this meeting is contained in the Proxy Statement sent with this Annual Report to holders of record of EOG Resources, Inc. Common Stock. The Annual Report is not to be considered a part of the proxy soliciting material. Additional copies of the Annual Report and the Form 10-K are available upon request by calling (877) 363-EOGR or through the EOG Resources website at www.eogresources.com. Quarterly earnings press release information also can be accessed through the website. Financial analysts and investors who need additional information should visit the EOG website at www.eogresources.com or contact Maire A. Baldwin, Investor Relations at (713) 651-6EOG. 56 EOG RESOURCES, INC. Inside Back Cover [Blank] Back Cover EOG RESOURCES, INC. 1200 Smith Street, Suite 300 Houston, TX 77002 P.O. Box 4362 Houston, TX 77210-4362 (713) 651-7000 www.eogresources.com EX-21 8 exhibit21.txt SUBSIDIARIES OF THE REGISTRANT EXHIBIT 21 EOG Resources, Inc. Subsidiaries EOG Resources - Carthage, Inc. EOG Resources Investments, Inc. EOG Resources Property Management, Inc. EOG Resources Acquisitions L.P. ERSO, Inc. EOG Expat Services, Inc. EOG Resources Marketing, Inc. EOG - Canada, Inc. EOG Company of Canada EOG Canada Company Ltd. EOG Resources Canada Inc. Nilo Operating Company EOG Resources - Callaghan, Inc. Online Energy Solutions, Inc. EOG Resources Holdings LLC EOG Resources Properties LLC Big Sky Ranches, Inc. EOG Resources Appalachian LLC EOG Resources East Texas, L.P. EOG Resources International, Inc. EOGI - Abu Dhabi, Inc. EOG Resources Abu Dhabi, Ltd. EOGI - Algeria, Inc. EOGI -Australia, Inc. EOG Resources Bangladesh Ltd. EOGI - France, Inc. EOG Resources France S.A. EOGI - Mozambique, Inc. EOG Resources Mozambique Ltd. EOGI - Qatar, Inc. EOGI - Trinidad, Inc. EOGI Trinidad Company EOG Resources Trinidad Limited EOG Resources Capital Management I, Ltd. Wilsyx International Finance B.V. EOGI Company of Trinidad Harfin Capital and Finance Ltd. OCC Investment Company Ltd. Murrott Capital Ltd. EOGI Trinidad - U(a) Block Company EOG Resources Trinidad - U(a) Block Limited EOGI - United Kingdom, Inc. EOGI United Kingdom Company B.V. EOG Resources UK Limited EOGI - Uzbekistan, Inc. EOGI - Venezuela, Inc. EOGI - Venezuela (Guarico), Inc. Ghana Resources Holding Inc. Ghana Resources I Ltd. Ghana Resources II Ltd. EX-23 9 exhibit23-1.txt CONSENTS OF EXPERTS AND COUNSEL EXHIBIT 23.1 DeGolyer and MacNaughton One Energy Square Dallas, Texas 75206 March 21, 2001 EOG Resources, Inc. 1200 Smith Street, Suite 300 Houston, Texas 77002 Gentlemen: We hereby consent to the references to our firm and to the opinions delivered to EOG Resources, Inc., formerly Enron Oil & Gas Company, (the Company) regarding our comparison of estimates prepared by us with those furnished to us by the Company of the proved oil, condensate, natural gas liquids, and natural gas reserves of certain selected properties owned by the Company. The opinions are contained in our letter reports dated January 11, 1999, February 8, 2000, and February 8, 2001, for estimates as of December 31, 1998, December 31, 1999, and December 31, 2000, respectively. The opinions are referred to in the section Supplemental Information to Consolidated Financial Statements Oil and Gas Producing Activities in the Company's Annual Report to Shareholders dated March 23, 2001 (the Annual Report). That section of the Annual Report is in turn incorporated by reference in item 14 of the Company's Report on Form 10-K dated March 23, 2001, to be filed with the Securities & Exchange Commission (the Form 10-K). Additionally, we hereby consent to the incorporation by reference of such references to our firm and to our opinions included in the Company's previously filed Registration Statement Nos. 33-48368, 33-52201, 33-58103, 33-62005, 333-09919, 333-20841, 333-18511, 333-31715, 333-44785, 333-69483, and 333-46858. Very truly yours, DeGOLYER and MacNAUGHTON EX-23 10 exhibit23-3.txt CONSENTS OF EXPERTS AND COUNSEL EXHIBIT 23.3 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our report dated February 15, 2001, incorporated by reference in the Annual Report of EOG Resources, Inc. and subsidiaries' on Form 10-K for the year ended December 31, 2000, into EOG Resources Inc. and subsidiaries' previously filed Registration Statement Nos. 33-48358, 33-52201, 33-58103, 33-62005, 333-09919, 333- 20841, 333-18511, 333-31715, 333-44785, 333-69483 and 333-46858. ARTHUR ANDERSEN LLP Houston, Texas March 22, 2001 EX-24 11 exhibit24.txt POWERS OF ATTORNEY EXHIBIT 24 POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS, that in connection with the filing by EOG Resources, Inc., a Delaware corporation (the "Company") of its Annual Report on Form 10-K for the year ended December 31, 2000 with the Securities and Exchange Commission, the undersigned director of the Company hereby constitutes and appoints Barry Hunsaker, Jr. and Patricia L. Edwards, and each of them (with full power to each of them to act alone), his true and lawful attorney-in-fact and agent, for him and on his behalf and in his name, place and stead, in any and all capacities, to sign, execute and file such Annual Report on Form 10-K, together with any amendments or supplements thereto, with all exhibits and any and all documents required to be filed with respect thereto with any regulatory authority, granting unto said attorneys, and each of them, full power and authority to do and perform each and every act and action requisite and necessary to be done in and about the premises in order to effectuate the same as fully to all intents and purposes as the undersigned might or could do if personally present, hereby ratifying and confirming all the said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof. IN WITNESS WHEREOF, the undersigned has hereto set his hand this 12th day of March, 2001. /s/ FRANK G. WISNER ------------------------------ FRANK G. WISNER POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS, that in connection with the filing by EOG Resources, Inc., a Delaware corporation (the "Company") of its Annual Report on Form 10-K for the year ended December 31, 2000 with the Securities and Exchange Commission, the undersigned director of the Company hereby constitutes and appoints Barry Hunsaker, Jr. and Patricia L. Edwards, and each of them (with full power to each of them to act alone), his true and lawful attorney-in-fact and agent, for him and on his behalf and in his name, place and stead, in any and all capacities, to sign, execute and file such Annual Report on Form 10-K, together with any amendments or supplements thereto, with all exhibits and any and all documents required to be filed with respect thereto with any regulatory authority, granting unto said attorneys, and each of them, full power and authority to do and perform each and every act and action requisite and necessary to be done in and about the premises in order to effectuate the same as fully to all intents and purposes as the undersigned might or could do if personally present, hereby ratifying and confirming all the said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof. IN WITNESS WHEREOF, the undersigned has hereto set his hand this 16th day of March, 2001. /s/ FRED C. ACKMAN ------------------------------ FRED C. ACKMAN POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS, that in connection with the filing by EOG Resources, Inc., a Delaware corporation (the "Company") of its Annual Report on Form 10-K for the year ended December 31, 2000 with the Securities and Exchange Commission, the undersigned director of the Company hereby constitutes and appoints Barry Hunsaker, Jr. and Patricia L. Edwards, and each of them (with full power to each of them to act alone), his true and lawful attorney-in-fact and agent, for him and on his behalf and in his name, place and stead, in any and all capacities, to sign, execute and file such Annual Report on Form 10-K, together with any amendments or supplements thereto, with all exhibits and any and all documents required to be filed with respect thereto with any regulatory authority, granting unto said attorneys, and each of them, full power and authority to do and perform each and every act and action requisite and necessary to be done in and about the premises in order to effectuate the same as fully to all intents and purposes as the undersigned might or could do if personally present, hereby ratifying and confirming all the said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof. IN WITNESS WHEREOF, the undersigned has hereto set his hand this 16th day of March, 2001. /s/ GEORGE A. ALCORN ------------------------------ GEORGE A. ALCORN POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS, that in connection with the filing by EOG Resources, Inc., a Delaware corporation (the "Company") of its Annual Report on Form 10-K for the year ended December 31, 2000 with the Securities and Exchange Commission, the undersigned director of the Company hereby constitutes and appoints Barry Hunsaker, Jr. and Patricia L. Edwards, and each of them (with full power to each of them to act alone), his true and lawful attorney-in-fact and agent, for him and on his behalf and in his name, place and stead, in any and all capacities, to sign, execute and file such Annual Report on Form 10-K, together with any amendments or supplements thereto, with all exhibits and any and all documents required to be filed with respect thereto with any regulatory authority, granting unto said attorneys, and each of them, full power and authority to do and perform each and every act and action requisite and necessary to be done in and about the premises in order to effectuate the same as fully to all intents and purposes as the undersigned might or could do if personally present, hereby ratifying and confirming all the said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof. IN WITNESS WHEREOF, the undersigned has hereto set his hand this 9th day of March, 2001. /s/ EDWARD RANDALL, III ------------------------------ EDWARD RANDALL, III POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS, that in connection with the filing by EOG Resources, Inc., a Delaware corporation (the "Company") of its Annual Report on Form 10-K for the year ended December 31, 2000 with the Securities and Exchange Commission, the undersigned director of the Company hereby constitutes and appoints Barry Hunsaker, Jr. and Patricia L. Edwards, and each of them (with full power to each of them to act alone), his true and lawful attorney-in-fact and agent, for him and on his behalf and in his name, place and stead, in any and all capacities, to sign, execute and file such Annual Report on Form 10-K, together with any amendments or supplements thereto, with all exhibits and any and all documents required to be filed with respect thereto with any regulatory authority, granting unto said attorneys, and each of them, full power and authority to do and perform each and every act and action requisite and necessary to be done in and about the premises in order to effectuate the same as fully to all intents and purposes as the undersigned might or could do if personally present, hereby ratifying and confirming all the said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof. IN WITNESS WHEREOF, the undersigned has hereto set his hand this 9th day of March, 2001. /s/ EDMUND P. SEGNER, III --------------------------------- EDMUND P. SEGNER, III POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS, that in connection with the filing by EOG Resources, Inc., a Delaware corporation (the "Company") of its Annual Report on Form 10-K for the year ended December 31, 2000 with the Securities and Exchange Commission, the undersigned director of the Company hereby constitutes and appoints Barry Hunsaker, Jr. and Patricia L. Edwards, and each of them (with full power to each of them to act alone), his true and lawful attorney-in-fact and agent, for him and on his behalf and in his name, place and stead, in any and all capacities, to sign, execute and file such Annual Report on Form 10-K, together with any amendments or supplements thereto, with all exhibits and any and all documents required to be filed with respect thereto with any regulatory authority, granting unto said attorneys, and each of them, full power and authority to do and perform each and every act and action requisite and necessary to be done in and about the premises in order to effectuate the same as fully to all intents and purposes as the undersigned might or could do if personally present, hereby ratifying and confirming all the said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof. IN WITNESS WHEREOF, the undersigned has hereto set his hand this 19th day of March, 2001. /s/ DONALD F. 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