10-K 1 eog10-k03.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, 2003 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) 333 Clay Street, Suite 4200, 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 . Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes x No State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of March 8, 2004, and as of the last business day of the registrant's most recently completed second fiscal quarter. Common Stock aggregate market value held by non- affiliates as of March 8, 2004: $5,317,400,876, and as of June 30, 2003: $4,806,502,591. Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date. Class: Common Stock, par value $0.01 per share, on March 8, 2004, Shares Outstanding: 116,252,752. Documents incorporated by reference. Portions of the following documents are incorporated by reference into the indicated parts of this report: Current Report on Form 8-K filed February 24, 2004 - Part I, II and IV; and Proxy Statement for the May 4, 2004 Annual Meeting of Shareholders to be filed within 120 days after December 31, 2003 (Proxy Statement) - Part III. TABLE OF CONTENTS Page PART I Item 1. Business 1 General 1 Business Segments 1 Exploration and Production 1 Marketing 5 Wellhead Volumes and Prices, and Lease and Well Expenses 6 Competition 6 Regulation 7 Enron Corp. Bankruptcy 10 Other Matters 10 Current Executive Officers of the Registrant 12 Item 2. Properties Oil and Gas Exploration and Production Properties and Reserves 13 Item 3. Legal Proceedings 16 Item 4. Submission of Matters to a Vote of Security Holders 16 PART II Item 5. Market for Registrant's Common Equity and Related Shareholder Matters 16 Item 6. Selected Financial Data 17 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 18 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 19 Item 8. Financial Statements and Supplementary Data 19 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 19 Item 9A. Controls and Procedures 19 PART III Item 10. Directors and Executive Officers of the Registrant 19 Item 11. Executive Compensation 19 Item 12. Security Ownership of Certain Beneficial Owners and Management 20 Item 13. Certain Relationships and Related Transactions 20 Item 14. Principal Accounting Fees and Services 20 PART IV Item 15. Financial Statements and Financial Statement Schedule, Exhibits and Reports on Form 8-K 20 SIGNATURES PART I ITEM 1. Business General EOG Resources, Inc. (EOG), a Delaware corporation organized in 1985, together with its subsidiaries, explores for, develops, produces and markets natural gas and crude oil primarily in major producing basins in the United States of America, as well as in Canada and Trinidad and, to a lesser extent, selected other international areas, including the United Kingdom North Sea. EOG's principal producing areas are further described under "Exploration and Production" below. EOG's website address is http://www.eogresources.com. EOG's Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments to those reports are made available, free of charge, through its website as soon as reasonably practicable after such reports have been filed with or furnished to the Securities and Exchange Commission (SEC). At December 31, 2003, EOG's total estimated net proved reserves were 5,216 billion cubic feet equivalent (Bcfe), of which estimated net proved natural gas reserves were 4,645 billion cubic feet (Bcf) and estimated net proved crude oil, condensate and natural gas liquids reserves were 95 million barrels (MMBbl) (see "Supplemental Information to Consolidated Financial Statements" beginning on page 42 of EOG's Current Report on Form 8-K filed with the SEC on February 24, 2004, which included financial statements of EOG for the fiscal year ended December 31, 2003 and is attached hereto as Exhibit 99.1 (Form 8-K filed on February 24, 2004)). At such date, approximately 49% of EOG's reserves (on a natural gas equivalent basis) were located in the United States, 27% in Trinidad, 23% in Canada and 1% in the United Kingdom North Sea. As of December 31, 2003, EOG employed approximately 1,100 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 and exploration. EOG focuses on the cost-effective utilization of advances in technology associated with the gathering, processing and interpretation of three-dimensional seismic data, the development of reservoir simulation models, the use of new and/or improved drill bits, mud motors and mud additives, and 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 select tactical acquisitions that result in additional economies of scale or land positions with significant additional prospects. Maintaining the lowest possible operating cost structure that is consistent with prudent and safe operations is also an important goal 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. Business Segments EOG's operations are all natural gas and crude oil exploration and production related. Exploration and Production North American Operations EOG's North American operations are focused on most of the productive basins in the United States and Canada, utilizing personnel who have developed experience and expertise unique to the geology of that region, thereby leveraging EOG's knowledge and cost structure into enhanced returns on invested capital. At December 31, 2003, 87% of EOG's net proved North American reserves (on a natural gas equivalent basis) were natural gas and 13% were crude oil, condensate and natural gas liquids. A substantial portion of EOG's North American natural gas reserves are in long-lived fields with well-established production histories. EOG believes that opportunities exist to increase production in and around many of these fields through continued development and application of new technology. EOG will also continue an active exploration program, designed to extend fields and add new trends to its broad portfolio of North American plays. The following is a summary of significant developments during 2003 and certain 2004 plans for EOG's North American operations. United States. During 2003, EOG continued its successful Permian Basin horizontal drilling programs in the Devonian play of West Texas and the Bone Spring play of Southeast New Mexico. Improved horizontal technology continues to lower drilling and completion costs along with increasing the production rates and reserves of new wells. In 2003, EOG initiated horizontal drilling operations in the Barnett Shale play of the Fort Worth Basin. EOG drilled approximately 58 net wells in the Permian and Fort Worth basins during 2003 and increased net average daily production to approximately 100 million cubic feet per day (MMcfd) of natural gas and 7.8 thousand barrels per day (MBbld) of crude oil, condensate and natural gas liquids. This represents a 7% increase in natural gas and a 21% increase in liquids production from 2002 levels. EOG plans an active year of drilling and continued production growth in 2004. EOG increased drilling activity in the Rocky Mountains area during 2003, drilling approximately 77 net wells. The majority of the activity continues to be located in its key producing areas of Big Piney, Wyoming - LaBarge Platform and Vernal, Utah - Uintah/Chapita/Natural Buttes, and a new area in Richland County, Montana. EOG is developing a new Bakken Horizontal play in Richland County, Montana, and expects to drill approximately 13 net wells in 2004. During 2003, the net average daily production for the Rocky Mountains area was approximately 117 MMcfd of natural gas and 5.5 MBbld of crude oil, condensate and natural gas liquids. EOG expects to increase drilling in the Uintah Basin, in both the Deep Mesaverde and Wasatch, and in the Williston Basin, Bakken horizontal oil play. The Mid-Continent net average daily production during 2003 was approximately 79 MMcfd of natural gas and 1.5 MBbld of crude oil and condensate. Natural gas production for 2003 increased 12% over 2002. In 2003, EOG drilled 133 net wells in two core areas: the Hugoton-Deep play in the Oklahoma Panhandle and the Cleveland Horizontal play in the Texas Panhandle. The Hugoton Deep program will continue at a level comparable to 2003, while an increase in the Cleveland Horizontal play program is expected. EOG has expanded its Cleveland position over the last year to more than 64,000 net acres and expects to drill over 50 Cleveland Horizontal wells in 2004. The average Cleveland gross well has an initial rate of 1.5 MMcfd and an estimated ultimate recovery of 1.25 Bcfe. In addition to these two core areas, EOG will remain active in the exploration of other plays throughout Oklahoma, Kansas, and the Texas Panhandle. The Upper Gulf Coast continues to be a significant producing and exploration area for EOG. New operating areas were added in East Texas and North Louisiana through exploration and property trades during 2003. EOG drilled approximately 68 net wells in the Upper Gulf Coast area during 2003. Net average production for the year was 96 MMcfd of natural gas and 3.1 MBbld of crude oil, condensate and natural gas liquids. In 2004, EOG will continue to develop growth opportunities in East Texas, North Louisiana, and Mississippi, and will test several high potential prospects in the Lower Gulf Coast areas of Texas and South Louisiana. EOG had another active year in South Texas during 2003, drilling or participating in approximately 74 net wells. The area averaged net production of approximately 169 MMcfd of natural gas, a 5% increase over 2002, and 2.2 MBbld of crude oil, condensate and natural gas liquids. Several second half 2003 discoveries in Lavaca and San Patricio Counties resulted in additional natural gas and liquids production of approximately 30 MMcfd and 3.5 MBbld, net, respectively. There was also continued success and growth in the Roleta and Lobo trends with key discoveries in Webb and Zapata Counties. EOG had successful drilling programs in the Wilcox in Duval and Lavaca Counties, the Frio in Nueces, San Patricio and Matagorda Counties, and the Olmos in Webb County. EOG was successful in adding to its current leasehold position in 2003, and this will provide additional opportunities for its Roleta, Lobo, Frio, Wilcox and Olmos programs in 2004. In 2003, EOG drilled over 200 net shallow Devonian natural gas wells in the Appalachian Basins. Net production increased throughout the year from 20 MMcfd in January to over 25 MMcfd of natural gas in December, averaging approximately 22 MMcfd for the year. While shallow drilling will continue to play an important role in these areas in 2004, EOG will continue to pursue higher impact plays such as the Oriskany and Trenton Black River. In the Gulf of Mexico, EOG focuses on offshore Texas and Louisiana. Three fields, South Timbalier 156, Eugene Island 135 and Matagorda Island 623, account for over sixty percent of EOG's Gulf of Mexico net production. During 2003, total net production averaged approximately 55 MMcfd of natural gas and 1.3 MBbld of crude oil, condensate and natural gas liquids. In 2003, EOG drilled or participated in seven gross wells, including a significant exploration discovery at Matagorda Island 685. EOG operates and has a 60% working interest in this estimated 27 Bcfe discovery, which is expected to commence sales in the second quarter of 2004. The South Timbalier 156 field, a 2002 discovery, commenced first sales in October 2003 with initial gross production of 13 MMcfd of natural gas and 4.4 MBbld of condensate. In 2004, EOG plans a similar level of drilling concentrated primarily on the Gulf of Mexico shelf, with limited deepwater activity possible. At December 31, 2003, EOG held approximately 2,424,900 net undeveloped acres in the United States. Canada. EOG conducts operations through its Canadian subsidiary, EOG Resources Canada Inc. (EOGRC), from offices in Calgary, Alberta. During 2003, EOGRC was again successful with its shallow natural gas strategy in Western Canada, drilling a record 1,034 net wells and increasing its reserve base and production potential. Strategic property acquisitions were also utilized to expand the shallow gas platform area in Southeast Alberta. On October 1, 2003, EOGRC closed the largest asset purchase of primarily natural gas properties in EOG's history for approximately US $320 million. These properties are essentially adjacent to existing EOGRC operations or are properties in which EOGRC already has a working interest. In late December 2003, EOGRC closed another property acquisition for US $46 million. EOGRC's net production during 2003 averaged approximately 165 MMcfd of natural gas, as compared to 154 MMcfd during 2002. Crude oil, condensate and natural gas liquids averaged approximately 3.0 MBbld, net, in 2003. Additions from strategic property acquisitions and new wells coming on stream late in the year increased fourth quarter 2003 net production to 196 MMcfd of natural gas and 3.4 MBbld of crude oil, condensate and natural gas liquids. Key producing areas in the Western Canadian Sedimentary Basin were the Southeast Alberta/Southwest Saskatchewan shallow natural gas trend and Grande Prairie - Wapiti. EOGRC expects to increase its shallow natural gas drilling on its expanded Southeast Alberta platform, to initiate coalbed methane development at Twining, and to participate in several higher impact exploratory and unconventional tests during 2004. At December 31, 2003, EOG held approximately 1,082,700 net undeveloped acres in Canada. Outside North America Operations EOG has operations in offshore Trinidad and the United Kingdom North Sea, and is evaluating additional exploration, exploitation and development opportunities in the United Kingdom and other international areas. Trinidad. In November 1992, EOG, through its subsidiary, EOG Resources Trinidad Limited (EOGRT) was awarded a 95% working interest concession in the South East Coast Consortium (SECC) Block offshore Trinidad, encompassing three undeveloped fields - the Kiskadee, Ibis and Oilbird fields. The Kiskadee and Ibis fields have since been developed and are being produced. The Oilbird field was successfully appraised by the drilling of two wells in the fourth quarter of 2001 and one well in the fourth quarter of 2003. The Oilbird 2 well encountered 380 feet of net pay and the Oilbird 3 well encountered 290 feet of net pay. The Oilbird 3X well, which was drilled during 2003, encountered 64 feet of net pay in the targeted sand. EOGRT expects to develop the Oilbird field over the next few years and place it on production in early 2007. EOGRT discovered a new field with the drilling of the Parula #1 wildcat well in 2002, which encountered 370 feet of net pay. This field was brought on stream in February 2004. The term of the license covering the SECC Block expires in December 2029. In July 1996, EOG, through its subsidiary, EOG Resources Trinidad-U(a) Block Limited (EOGUA), 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. EOG drilled its first commitment well, OA-1, on this block in 1998. This well encountered over 500 feet of net pay. In the first quarter of 2001, EOG drilled the OA-2 well which encountered 305 feet of net pay and increased gross proved reserves to a field total of 870 Bcfe. In September 2001, EOGUA set a platform and jacket and first production began in the second quarter of 2002. Existing surplus processing and transportation capacity at the Pelican field facilities owned and operated by a subsidiary of EOGRT's partners in the SECC Block is being used to process and transport much of EOGRT's natural gas production and all of its condensate and crude oil production from the SECC and U(a) Blocks. In April 2002, EOG, through its subsidiary, EOG Resources Trinidad LRL Unlimited, signed a production sharing contract with the Government of Trinidad and Tobago for the Lower Reverse "L" Block which is adjacent to the SECC Block. EOG holds a 100% working interest in the Lower Reverse "L" Block. In the fourth quarter of 2003, EOG drilled the first exploration well on this block. The well was determined to be uneconomical. In October 2002, EOG, through its subsidiary, EOG Resources Trinidad-U(b) Block Unlimited, signed a production sharing contract with the Government of Trinidad and Tobago for the Modified U(b) Block which is also adjacent to the SECC Block. EOG holds a 55% working interest in and operates the Modified U(b) Block. Primera Oil & Gas Ltd, a Trinidadian company, holds the remaining 45% interest. At December 31, 2003, EOG held approximately 194,500 net undeveloped acres in Trinidad. Natural gas from EOG's Trinidad operations is being sold to the National Gas Company of Trinidad and Tobago (NGC) under the following arrangements: . Under the first take-or-pay contract, which expires in 2009, natural gas is delivered to NGC for resale to Trinidad local markets. During 2003, EOG delivered net average production of 104 MMcfd of natural gas under this agreement. . Under the second take-or-pay contract, which expires in 2017, EOG delivers to NGC approximately 60 MMcfd, gross, of natural gas which is resold to an anhydrous ammonia plant owned by Caribbean Nitrogen Company Limited (CNCL). Based on average 2003 prices, approximately 48 MMcfd of natural gas delivered to NGC was net to EOG in 2003. EOGRT owns an approximate 12% equity interest in CNCL, a Trinidadian company, which has constructed an ammonia plant in Pt. Lisas, Trinidad. The other shareholders in CNCL are subsidiaries of Ferrostaal AG, Halliburton, Koch Industries, Inc. and CL Financial Ltd. At December 31, 2003, EOGRT's investment in CNCL was approximately $14 million. CNCL commenced production in June 2002 and currently produces approximately 1,950 metric tons of ammonia daily. At December 31, 2003, CNCL had a long- term debt balance of approximately $218 million, which is non- recourse to CNCL's shareholders. As part of the financing for CNCL, the shareholders agreed to enter into a post-completion deficiency loan agreement with CNCL to fund the costs of operations, payment of principal and interest to the principal creditor and other cash deficiencies of CNCL up to $30 million, up to $4 million of which is to be provided by EOGRT. The Shareholders' Agreement requires the consent of the holders of 90% or more of the shares to take certain material actions. Accordingly, given its current level of equity ownership, EOGRT is able to exercise significant influence over the operating and financial policies of CNCL and therefore, EOG accounts for the investment using the equity method. During 2003, EOG recognized equity income of $3.7 million from CNCL. . Under a fifteen-year take-or-pay contract, EOG is to supply approximately 60 MMcfd gross of natural gas to NGC. This gas will be resold by NGC to an anhydrous ammonia plant that is currently under construction and is owned by Nitrogen 2000 Unlimited (N2000). EOG's subsidiary, EOG Resources NITRO2000 Ltd. (EOGNitro2000), owns an approximate 23% equity interest in N2000 at February 29, 2004. The other shareholders in N2000 are subsidiaries of Ferrostaal AG, Halliburton, Koch Industries, Inc. and CL Financial Ltd. At December 31, 2003, EOGNitro2000's equity interest and investment in N2000 was approximately 27% and $20 million, respectively. In February 2004, a portion of EOGNitro2000's shareholdings was sold to one of the other shareholders. The sale did not result in any gain or loss. N2000 is constructing an ammonia plant in Trinidad, at an expected total cost of approximately $320 million, and is expected to commence production in the third quarter 2004. At December 31, 2003, N2000 had a long-term debt balance of approximately $172 million, which is non-recourse to N2000's shareholders. As part of the loan agreement for the N2000 financing, affiliates of the shareholders have entered into a pre-completion deficiency loan agreement with N2000 to fund plant cost overruns up to $15 million, up to $3 million of which is to be provided by the immediate parent company of EOGNitro2000. Affiliates of the shareholders have also entered into a post-completion deficiency loan agreement with N2000 to fund the costs of operations, payment of principal and interest to the principal creditor and other cash deficiencies of N2000 up to $30 million, up to $7 million of which is to be provided by the immediate parent company of EOGNitro2000. The Shareholders' Agreement requires the consent of the holders of 90% or more of the shares to take certain material actions. Accordingly, given its current level of equity ownership, EOGNitro2000 is able to exercise significant influence over the operating and financial policies of N2000 and therefore, EOG accounts for the investment using the equity method. . Lastly, under a fifteen-year requirements natural gas contract, which was also recently signed, EOG will ultimately supply 87 MMcfd, net, of natural gas to a methanol plant, based on current price and operating assumptions. The plant is presently under construction and is expected to start up in mid-2005 with EOG supplying 67 MMcfd, net for the first four years of the contract. EOG has no equity investment in this plant. United Kingdom. In 2003, EOG's subsidiary, EOG Resources United Kingdom Limited (EOGUK), participated with other North Sea partners in the drilling of three exploration wells, two of which were commercial successes. In 2002, EOGUK acquired a 25% non- operating working interest in a portion of Block 49/16, located in the Southern Gas Basin of the North Sea. The first commercial well, the 49/16-14Z, was drilled in the Southern Gas Basin and temporarily abandoned in February 2003. It encountered approximately 106 Bcf gross of natural gas reserves in the Rotliegendes formation, 26 Bcf net to EOGUK. EOGUK and its partners are, as of this date, drilling a development well 49/16- VB from the Vampire platform. In 2003, EOGUK acquired a 30% non- operating working interest in a portion of Blocks 53/1 and 53/2. These Blocks are also located in the Southern Gas Basin of the North Sea. EOGUK drilled and completed as a natural gas producer Well 53/2-11 in November 2003. The well encountered approximately 198 feet of net pay sands in the Rotliegendes formation, with gross estimated natural gas reserves of 109 Bcf, or 33 Bcf, net to EOGUK. At December 31, 2003, EOG held approximately 78,200 net undeveloped acres in the United Kingdom. Other International. EOG continues to evaluate other select 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 under either a contract with a fixed price schedule with annual escalations, or a contract that is price dependent on Caribbean ammonia index prices. Substantially all of EOG's wellhead crude oil and condensate is sold under various terms and arrangements at market-responsive prices. During 2003, sales to subsidiaries of a major utility company and subsidiaries of a major integrated oil and gas company accounted for 12% and 10%, respectively, of EOG's oil and gas revenues. No other individual purchaser accounted for 10% or more of EOG's oil and gas revenues for the same period. EOG does not believe that the loss of any single purchaser will have a material adverse effect on the financial condition or results of operations of EOG. Other Marketing. EOG Resources Marketing, Inc., a wholly owned subsidiary of EOG, has purchased and constructed several small gas gathering systems in order to facilitate its entry into the gas gathering business on a limited basis. 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), wellhead volume of and average prices for 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, 2003.
Year Ended December 31, 2003 2002 2001 Natural Gas Volumes (MMcf per day) United States 638 635 680 Canada 165 154 126 Trinidad 152 135 115 Total 955 924 921 Crude Oil and Condensate Volumes (MBbl per day) United States 18.5 18.8 22.0 Canada 2.3 2.1 1.7 Trinidad 2.4 2.4 2.1 Total 23.2 23.3 25.8 Natural Gas Liquids Volumes (MBbl per day) United States 3.2 2.9 3.5 Canada 0.6 0.8 0.5 Total 3.8 3.7 4.0 Average Natural Gas Prices ($/Mcf) United States $ 5.06 $ 2.89 $ 4.26 Canada 4.66 2.67 3.78 Trinidad 1.35 1.20 1.22 Composite 4.40 2.60 3.81 Average Crude Oil and Condensate Prices ($/Bbl) United States $30.24 $24.79 $25.06 Canada 28.54 23.62 22.70 Trinidad 28.88 23.58 24.14 Composite 29.92 24.56 24.83 Average Natural Gas Liquids Prices ($/Bbl) United States $21.53 $14.76 $17.17 Canada 19.13 11.17 15.05 Composite 21.13 14.05 16.89 Lease and Well Expenses ($/Mcfe) United States $ 0.53 $ 0.45 $ 0.45 Canada 0.82 0.72 0.62 Trinidad 0.18 0.17 0.15 Composite 0.52 0.45 0.44
Competition EOG 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 worldwide energy supplies, such as liquefied natural gas imported into the United States from other countries. 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 (BLM) and the Minerals Management Service (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. For non-arm's length transactions, the revised rules replace a familiar set of benchmarks (e.g., posted prices, comparable sales) with an indexing system based on spot prices at nearby market centers. In addition, the revised rules limit deductions on post-production transportation costs and disallow altogether deductions for post-production marketing costs. Together, these changes are expected to somewhat increase EOG's royalty obligation. Two industry trade association have sought judicial review of the revised regulations but the MMS has already proposed additional changes to the regulations, some of which are beneficial to the industry. EOG cannot predict what effect the outcome of the pending litigation or the pending rulemaking will be or what net effect, if any, it will have on EOG's operations. The revised regulations are expected to be promulgated in April 2004 and effective in June 2004. 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. However, on appeal by the government, a federal court of appeals in 2002 reversed a 2000 district court decision, reinstating MMS's categorical disallowance of deductions for post-production marketing costs, except for firm demand charges. While this litigation was directed at a gas transportation rule, the disallowance of marketing costs applies to crude oil as well. As in the still pending oil valuation litigation, two trade associations brought the legal challenge of the gas transportation rules; the trade associations' petition seeking Supreme Court review of the court of appeals decision was denied. 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 (NGA) and the Natural Gas Policy Act of 1978 (NGPA). These statutes are administered by the Federal Energy Regulatory Commission (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 that the FERC might prospectively impose more restrictive conditions on such sales. 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 mandated 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. Order No. 636 led directly to the MMS gas transportation regulations addressed above, which limit deductions for post- production marketing costs and result in a somewhat expanded royalty obligation. 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 conducted a broad review of its transportation regulations, including how they operate in conjunction with state proposals for retail natural 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 - United States. 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. In addition, EOG could be responsible under environmental laws and regulations for oil and gas properties in which EOG owns an interest but is not the operator. 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 environmental laws and regulations, but inasmuch as such laws and regulations are frequently changed, EOG is unable to predict the ultimate cost of compliance. EOG also could incur costs related to the clean up of sites to which it sent regulated substances for disposal or to which it sent equipment for cleaning, and for damages to natural resources or other claims related to releases of regulated substances at such sites. In this regard, EOG has been named as a potentially responsible party in certain proceedings initiated pursuant to the Comprehensive Environmental Response, Compensation, and Liability Act and may be named as a potentially responsible party in other similar proceedings in the future. It is not anticipated that the costs incurred by EOG in connection with the presently pending proceedings will, individually or in the aggregate, have a materially adverse effect on the financial condition or results of operations of EOG. Canadian Regulation. The crude oil and natural gas industry in Canada is subject to extensive controls and regulations imposed by various levels of government. It is not expected that any of these controls or regulations will affect EOG operations in a manner materially different than they would affect other oil and gas companies of similar size. EOG is unable to predict what additional legislation or amendments may be enacted. In addition, each province has regulations that govern land tenure, royalties, production rates and other matters. The royalty regime is a significant factor in the profitability of crude oil and natural gas production. Royalties payable on production from private lands are determined by negotiations between the mineral owner and the lessee, although production from such lands is also subject to certain provincial taxes and royalties. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production, and the rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date and the type or quality of the petroleum product produced. Environmental Matters - Canada. In Canada, the crude oil and natural gas industry is currently subject to environmental regulation pursuant to provincial and federal legislation that provides for restrictions and prohibitions on releases or emissions of various substances produced or utilized with oil and gas industry operations. In addition, wells and facility sites must be abandoned and reclaimed to the satisfaction of provincial authorities. Compliance with such legislation can require significant expenditures. A breach of such legislation may result in the imposition of fines and penalties, the revocation of licenses and authorizations or civil liability for pollution damage. 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 in offshore Trinidad and the United Kingdom North Sea. Enron Corp. Bankruptcy In December 2001, Enron Corp. and certain of its affiliates, including Enron North America Corp., filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code. EOG recorded $19.2 million in charges associated with the Enron bankruptcies in the fourth quarter of 2001 related to certain contracts with Enron affiliates, including 2001 and 2002 natural gas and crude oil derivative contracts. Based on EOG's review of all matters related to Enron Corp. and its affiliates, EOG believes that Enron Corp.'s Chapter 11 proceedings will not have a material adverse effect on EOG's financial position. 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 9% increase in the average wellhead natural gas price for North America received by EOG from 2000 to 2001, a decrease of 32% from 2001 to 2002, and an increase of 75% from 2002 to 2003. Wellhead natural gas volumes from Trinidad are sold under either a contract with a fixed price schedule with annual escalations, or a contract that is price dependent on Caribbean ammonia index prices. 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 consumers, EOG is unable to predict what changes may occur in natural gas, crude oil and condensate, and ammonia prices in the future. Risk Management. EOG engages in price risk management activities from time to time. These activities are intended to manage EOG's exposure to fluctuations in commodity prices for natural gas and crude oil. EOG utilizes derivative financial instruments, primarily price swaps and collars, as the means to manage this price risk. In addition to these financial transactions, EOG is a party to various physical commodity contracts for the sale of hydrocarbons that cover varying periods of time and have varying pricing provisions. Under SFAS No. 133 - "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS Nos. 137, 138 and 149, these various physical commodity contracts qualify for the normal purchases and normal sales exception and therefore, are not subject to hedge accounting or mark-to-market accounting. The financial impact of these various physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices. Presented below is a summary of EOG's natural gas financial collar contracts and natural gas and crude oil financial price swap contracts as of March 11, 2004 with prices expressed in dollars per million British thermal units ($/MMBtu) and in dollars per barrel ($/Bbl), as applicable, and notional volumes in million British thermal units per day (MMBtud) and in barrels per day (Bbld), as applicable. As indicated, EOG does not have any financial collar or swap contracts that cover periods beyond October 2004. Moreover, EOG has not entered into any additional natural gas financial collar contracts or natural gas or crude oil financial price swap contracts since December 31, 2003. EOG accounts for these collar and swap contracts using mark-to-market accounting.
Natural Gas Financial Collar Contracts Financial Price Swap Contracts Floor Price Ceiling Price Natural Gas Crude Oil Weighted Weighted Floor Weighted Ceiling Weighted Average Average Volume Range Average Range Average Volume Price Volume Price 2004(1) (MMBtud) ($/MMBtu) ($/MMBtu) ($/MMBtu) ($/MMBtu) (MMBtud) ($/MMBtu) (Bbld) ($/Bbl) Jan 330,000 $5.06 - 5.88 $5.38 $5.86 - 6.69 $6.29 30,000 $5.57 4,000 $30.61 Feb 330,000 5.02 - 5.78 5.31 5.82 - 6.62 6.24 30,000 5.50 4,000 30.12 Mar 330,000 4.93 - 5.53 5.16 5.73 - 6.40 6.10 30,000 5.37 4,000 29.58 Apr 375,000 4.47 - 4.71 4.59 4.93 - 5.30 5.13 30,000 4.89 4,000 29.08 May 375,000 4.47 - 4.75 4.58 4.93 - 5.19 5.09 30,000 4.80 4,000 28.66 Jun 375,000 4.47 - 4.75 4.58 4.93 - 5.19 5.09 30,000 4.80 4,000 28.27 Jul 375,000 4.47 - 4.75 4.58 4.93 - 5.19 5.09 30,000 4.80 3,000 27.91 Aug 375,000 4.47 - 4.75 4.58 4.93 - 5.19 5.09 30,000 4.80 2,000 28.11 Sep 375,000 4.47 - 4.75 4.58 4.93 - 5.19 5.09 30,000 4.78 -- -- Oct 375,000 4.47 - 4.75 4.58 4.93 - 5.19 5.09 30,000 4.80 -- -- (1) The collar contracts for January 2004 to March 2004 were purchased at a total premium of $3 million or $0.10 per MMBtu. The collar contracts for April 2004 to October 2004 were purchased without a premium.
Severance Tax Exemption. Natural gas production from wells spudded or completed after May 24, 1989 and before September 1, 1996 in tight formations in Texas qualified for a ten-year exemption from severance taxes, subject to certain limitations. This ten-year exemption began September 1, 1991 and ended August 31, 2001. Natural gas production from qualifying wells spudded or completed after August 31, 1996, is entitled to use a reduced severance tax rate for the first 120 consecutive months. 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. Preferred Stock. 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 or each year beginning March 15, 2000. EOG may redeem all or 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 Series A preferred shares are not convertible into, or exchangeable for, common stock of EOG. 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 (Initial Period-End Dividend Payment Date). Through the Initial Period-End Dividend Payment Date, dividends will be payable, if declared, 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 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. 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/or 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, 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. 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 57 Chairman of the Board and Chief Executive Officer; Director Edmund P. Segner, III 50 President and Chief of Staff; Director Loren M. Leiker 50 Executive Vice President, Exploration and Development Gary L. Thomas 54 Executive Vice President, Operations Barry Hunsaker, Jr. 53 Senior Vice President and General Counsel Timothy K. Driggers 42 Vice President and Chief Accounting Officer Mark G. Papa was elected Chairman of the Board and Chief Executive Officer of EOG in August 1999, President and Chief Executive Officer and Director 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. 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. He was a director of EOG from January 1997 to October 1997. Mr. Segner is EOG's principal financial officer. Loren M. Leiker was elected Executive Vice President, Exploration in May 1998 and was subsequently named Executive Vice President, Exploration and Development. He was previously Senior Vice President, Exploration. Mr. Leiker joined EOG in April 1989 as International Exploration Manager. Gary L. Thomas was elected Executive Vice President, North America Operations in May 1998 and was subsequently named Executive Vice President, Operations. He was previously Senior Vice President and General Manager of EOG in Midland. 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. Timothy K. Driggers was elected Vice President and Controller of EOG in October 1999 and was subsequently named Vice President and Chief Accounting Officer in August 2003. He was previously Vice President, Accounting and Land Administration. Mr. Driggers held management positions in EOG's former majority shareholder company from October 1998 through September 1999. Mr. Driggers is EOG's principal accounting officer. 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 meeting immediately prior to 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. 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 Form 8-K filed on February 24, 2004 and attached hereto as Exhibit 99.1. 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 (upward or downward). 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 EOG's oil and gas properties 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. Acreage. The following table summarizes EOG's developed and undeveloped acreage at December 31, 2003. 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 526,306 329,543 870,711 765,670 1,397,017 1,095,213 Wyoming 312,540 188,844 625,945 375,986 938,485 564,830 Utah 223,675 81,269 362,683 214,758 586,358 296,027 Oklahoma 221,291 141,423 183,696 140,998 404,987 282,421 New Mexico 163,723 92,801 302,864 176,136 466,587 268,937 Pennsylvania 82,450 69,642 163,012 154,246 245,462 223,888 West Virginia 96,428 96,188 87,858 60,784 184,286 156,972 Offshore Gulf of Mexico 279,717 81,988 147,880 73,516 427,597 155,504 Montana 119,566 758 120,977 101,978 240,543 102,736 New York - - 109,445 92,781 109,445 92,781 Ohio 61,497 58,888 28,406 28,386 89,903 87,274 California 4,154 1,414 71,605 69,782 75,759 71,196 Colorado 24,884 1,414 129,760 52,589 154,644 54,003 Louisiana 16,972 11,887 27,825 21,672 44,797 33,559 Kansas 10,086 8,705 34,711 24,854 44,797 33,559 Mississippi 13,281 12,645 20,337 18,615 33,618 31,260 Nevada - - 23,805 23,805 23,805 23,805 Michigan - - 43,035 23,405 43,035 23,405 North Dakota 3,784 1,590 4,680 4,499 8,464 6,089 Arkansas 3,042 1,143 1,105 230 4,147 1,373 Alabama - - 212 193 212 193 Total United States 2,163,396 1,180,142 3,360,552 2,424,883 5,523,948 3,605,025 Canada Alberta 1,278,478 995,779 650,758 588,888 1,929,236 1,584,667 Saskatchewan 375,316 344,933 234,316 208,178 609,632 553,111 Northwest Territories - - 706,706 209,863 706,706 209,863 Manitoba 17,660 16,558 36,858 36,858 54,518 53,416 British Columbia 9,176 2,733 45,920 38,897 55,096 41,630 New Brunswick 219 33 - - 219 33 Total Canada 1,680,849 1,360,036 1,674,558 1,082,684 3,355,407 2,442,720 Trinidad 41,492 40,325 240,540 194,532 282,032 234,857 United Kingdom - - 190,837 78,150 190,837 78,150 Total 3,885,737 2,580,503 5,466,487 3,780,249 9,352,224 6,360,752
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 in the United States, Canada and Trinidad at December 31, 2003. Gross gas and oil wells include 546 with multiple completions.
Productive Wells Gross Net Gas 15,356 11,712 Oil 1,722 1,373 Total 17,078 13,085
Drilling and Acquisition Activities. During the years ended December 31, 2003, 2002 and 2001, EOG expended approximately $1,333 million, $836 million and $1,163 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, 2003 2002 2001 Gross Net Gross Net Gross Net Development Wells Completed North America Gas 1,586 1,439.99 1,465 1,204.93 1,550 1,311.86 Oil 89 78.98 88 64.27 124 107.06 Dry 89 78.02 84 74.88 95 81.68 Total 1,764 1,596.99 1,637 1,344.08 1,769 1,500.60 Outside North America Gas - - - - 3 2.90 Oil - - - - - - Dry - - - - - - Total - - - - 3 2.90 Total Development 1,764 1,596.99 1,637 1,344.08 1,772 1,503.50 Exploratory Wells Completed North America Gas 46 28.91 22 17.97 24 18.38 Oil 5 4.22 4 3.00 10 7.10 Dry 39 29.22 22 17.87 29 23.05 Total 90 62.35 48 38.84 63 48.53 Outside North America Gas 2 0.55 1 0.95 - - Oil - - - - - - Dry 2 1.50 - - 1 0.25 Total 4 2.05 1 0.95 1 0.25 Total Exploratory 94 64.40 49 39.79 64 48.78 Total 1,858 1,661.39 1,686 1,383.87 1,836 1,552.28 Wells in Progress at end of period 90 79.49 50 42.93 71 59.04 Total 1,948 1,740.88 1,736 1,426.80 1,907 1,611.32 Wells Acquired* Gas 1,274 1,079.02 664 374.06 1,089 981.53 Oil 108 68.03 7 4.21 53 51.04 Total 1,382 1,147.05 671 378.27 1,142 1,032.57 __________________ *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. ITEM 3. Legal Proceedings The information required by this Item is incorporated by reference from the Contingencies section in Note 8 of Notes to Consolidated Financial Statements included in the Form 8-K filed on February 24, 2004 and attached hereto as Exhibit 99.1. 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 2003. PART II ITEM 5. Market for Registrant's Common Equity 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 Dividend 2003 First Quarter $42.83 $35.70 $ 0.04 Second Quarter 45.56 36.56 0.04 Third Quarter 42.87 37.70 0.05 Fourth Quarter 47.52 40.85 0.05 2002 First Quarter $41.32 $30.50 $ 0.04 Second Quarter 44.15 37.11 0.04 Third Quarter 39.68 30.02 0.04 Fourth Quarter 42.00 32.40 0.04
As of March 8, 2004, there were approximately 285 record holders of EOG's common stock, including individual participants in security position listings. There are an estimated 75,000 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. ITEM 6. Selected Financial Data
Year Ended December 31, (In Thousands, Except Per Share Amounts) 2003 2002 2001 2000 1999 Statement of Income Data: Net Operating Revenues $1,744,675 $1,094,682 $1,655,722 $1,484,356 $ 847,701 Operating Income 697,314 180,977 675,387 691,324 23,790 Net Income Before Cumulative Effect of Change in Accounting Principle 437,276 87,173 398,616 396,931 569,094 Cumulative Effect of Change in Accounting Principle, Net of Income Tax (1) (7,131) - - - - Net Income 430,145 87,173 398,616 396,931 569,094(2) Preferred Stock Dividends 11,032 11,032 10,994 11,028 535 Net Income Available to Common $ 419,113 $ 76,141 $ 387,622 $ 385,903 $ 568,559 Net Income Per Share Available to Common Basic Net Income Available to Common Before Cumulative Effect of Change in Accounting Principle $ 3.72 $ 0.66 $ 3.35 $ 3.30 $ 4.04 Cumulative Effect of Change in Accounting Principle, Net of Income Tax (1) (0.06) - - - - Net Income Per Share Available to Common $ 3.66 $ 0.66 $ 3.35 $ 3.30 $ 4.04 Diluted Net Income Available to Common Before Cumulative Effect of Change in Accounting Principle $ 3.66 $ 0.65 $ 3.30 $ 3.24 $ 4.01 Cumulative Effect of Change in Accounting Principle, Net of Income Tax (1) (0.06) - - - - Net Income Per Share Available to Common $ 3.60 $ 0.65 $ 3.30 $ 3.24 $ 4.01 Average Number of Common Shares Basic 114,597 115,335 115,765 116,934 140,648 Diluted 116,519 117,245 117,488 119,102 141,627 (1) EOG adopted Statement of Financial Accounting Standards (SFAS) No. 143 - "Accounting for Asset Retirement Obligations" on January 1, 2003. Pro forma net income for 2002 through 1999 is not presented since the pro forma application of SFAS No. 143 to the prior periods would not result in pro forma net income materially different from the actual amount reported. (2) Included a $575 million tax-free gain on the share exchange transactions with a former majority shareholder, recorded in Other Income (Expense), Net.
At December 31, (In Thousands) 2003 2002 2001 2000 1999 Balance Sheet Data: Net Oil and Gas Properties $4,248,917 $3,321,548 $3,055,910 $2,525,007 $2,334,928 Total Assets 4,749,015 3,813,568 3,414,044 3,001,253 2,610,793 Long-Term Debt 1,108,872 1,145,132 855,969 859,000 990,306 Shareholders' Equity 2,223,381 1,672,395 1,642,686 1,380,925 1,129,611
Off-Balance Sheet Arrangements. EOG does not participate in financial transactions that generate relationships with unconsolidated entities or financial partnerships. Such entities, often referred to as variable interest entities (VIE) or special purpose entities (SPE), are generally established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. EOG was not involved in any unconsolidated VIE or SPE financial transactions during any of the reporting periods in this document and has no intention to participate in such transactions in the foreseeable future. Long-Term Debt, Lease Obligations and Other Commitments. The following table summarizes EOG's long-term debt, lease obligations and other commitments at December 31, 2003 (in thousands):
2010 & Total 2004 2005 - 2007 2008 - 2009 beyond Long-Term Debt $1,108,872 $198,050 $376,870 $173,952 $360,000 Non-cancelable Operating Leases 54,650 18,187 25,954 3,898 6,611 Drilling Rig Commitments 2,364 1,033 998 333 -- Pipeline Transportation Service Commitments (1) 45,702 13,615 25,811 3,666 2,610 Total $1,211,588 $230,885 $429,633 $181,849 $369,221 (1) Amounts shown are based on current pipeline transportation rates and the Canadian foreign currency exchange rate at December 31, 2003. Management does not believe that any future changes in these rates before the expiration dates of these commitments will have a materially adverse effect on the financial condition or results of operations of EOG.
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 4 through 16 of the Form 8-K filed on February 24, 2004 and attached hereto as Exhibit 99.1. 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, the ability to replace or increase reserves or to increase production, or the ability 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: the timing and extent of changes in commodity prices for crude oil, natural gas and related products, foreign currency exchange rates and interest rates; the timing and impact of liquefied natural gas imports and changes in demand or prices for ammonia or methanol; the extent and effect of any hedging activities engaged in by EOG; the extent of EOG's success in discovering, developing, marketing and producing reserves and in acquiring oil and gas properties; the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise; political developments around the world, acts of war and terrorism and responses to these acts; 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 10 through 14 of the Form 8-K filed on February 24, 2004 and attached hereto as Exhibit 99.1. ITEM 8. Financial Statements and Supplementary Data Information required by this Item is incorporated by reference from portions of the Form 8-K filed on February 24, 2004 and attached hereto as Exhibit 99.1 as indicated: Cross Reference to Applicable Sections Beginning of Form 8-K filed on February 24, 2004 on Page Reports of Independent Public Accountants 18 Consolidated Financial Statements 20 Notes to Consolidated Financial Statements 24 Supplemental Information to Consolidated Financial Statements 42 Unaudited Quarterly Financial Information 50 ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. ITEM 9A. Controls and Procedures EOG's management, with the participation of EOG's principal executive officer (CEO) and principal financial officer (CFO), evaluated the effectiveness of EOG's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (Exchange Act)) as of the end of the fiscal quarter ended December 31, 2003. Based on this evaluation, the CEO and CFO have concluded that EOG's disclosure controls and procedures were effective as of the end of the fiscal quarter ended December 31, 2003 to ensure that information that is required to be disclosed by EOG in the reports it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms. There were no changes in EOG's internal control over financial reporting that occurred during the fiscal quarter ended December 31, 2003 that has materially affected, or is reasonably likely to materially affect, EOG's internal control over financial reporting. PART III ITEM 10. Directors and Executive Officers of the Registrant 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, 2003, under the caption entitled "Election of Directors" of Item 1. Audit Committee Related Matters and Code of Ethics for the CEO and CFO. The information required by this Item regarding audit committee related matters is incorporated by reference from the Proxy Statement to be filed within 120 days after December 31, 2003, under the caption entitled "Board of Directors and Committees" of Item 1. 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, 2003, under the caption "Compensation of Directors and Executive Officers" of Item 1. ITEM 12. Security Ownership of Certain Beneficial Owners and Management Information required by this Item is incorporated by reference from the Proxy Statement to be filed within 120 days after December 31, 2003, under the captions "Election of Directors" and "Compensation of Directors and Executive Officers" of Item 1. ITEM 13. Certain Relationships and Related Transactions None. ITEM 14. Principal Accounting Fees and Services Information regarding auditor fees, audit-related fees, tax fees and all other fees and services billed by the principal accountant is incorporated by reference from the Proxy Statement to be filed within 120 days after December 31, 2003, under the caption "Ratification of Appointment of Auditors - General" of Item 2. PART IV ITEM 15. Financial Statements and Financial Statement Schedule, Exhibits and Reports on Form 8-K Information required by this Item is incorporated by reference from portions of the Form 8-K filed on February 24, 2004 and attached hereto as Exhibit 99.1 as indicated: (a)(1) Financial Statements and Supplemental Data Cross Reference to Applicable Sections Beginning of Form 8-K filed on February 24, 2004 on Page Consolidated Financial Statements 20 Notes to Consolidated Financial Statements 24 Supplemental Information to Consolidated Financial Statements 42 Unaudited Quarterly Financial Information 50 (a)(2) Financial Statement Schedules Schedule II - Valuation and Qualifying Accounts and Reserves for the Years Ended December 31, 2003, 2002 and 2001 (see page 24 for Schedule II). 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. REPORTS OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors and Stockholders of EOG Resources, Inc. Houston, Texas We have audited the consolidated financial statements of EOG Resources, Inc. as of December 31, 2003 and 2002, and for the two years in the period ended December 31, 2003, and have issued our report thereon dated February 23, 2004; such consolidated financial statements and report are included in your Current Report on Form 8-K dated February 24, 2004, and are incorporated herein by reference. Our audits also included the financial statement schedule of EOG Resources, Inc., listed in Item 15. This financial statement schedule is the responsibility of the Corporation's management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein. DELOITTE & TOUCHE LLP Houston, Texas February 23, 2004 REPORTS OF INDEPENDENT PUBLIC ACCOUNTANTS (Continued) EOG dismissed Arthur Andersen LLP on February 27, 2002 and subsequently engaged Deloitte & Touche LLP as its independent auditors. The predecessor auditor's report appearing below is a copy of Arthur Andersen's previously issued report dated February 21, 2002. Since EOG is unable to obtain a current manually signed audit report, a copy of Arthur Andersen's most recent signed and dated report has been included to satisfy filing requirements, as permitted under Rule 2-02(e) of Regulation S-X. The only information in the financial statements and the related footnotes included in EOG's Current Report on Form 8-K dated February 24, 2004, incorporated by reference in this Annual Report on Form 10-K that is referred to in the report of Arthur Andersen LLP is the information included in the Consolidated Statements of Income and Comprehensive Income, Consolidated Statements of Shareholders' Equity, Consolidated Statements of Cash Flows and the related footnotes for the year ended December 31, 2001. 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 Current Report on Form 8-K dated February 27, 2002, incorporated by reference in this Form 10-K, and have issued our report thereon dated February 21, 2002. 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 states 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 21, 2002 (a)(3) Exhibits See pages 25 through 30 for a listing of the exhibits. (b) Reports on Form 8-K Current Report on Form 8-K filed on October 1, 2003 to report Canadian Acquisition and to provide updated summaries of natural gas and crude oil financial swap and natural gas financial collar contracts for the third quarter and to report anticipated results of the price risk management activities for 2003 fourth quarter and 2004 in Item 9 - Regulation FD Disclosure. Current Report on Form 8-K filed on October 16, 2003 to provide updated summaries of natural gas and crude oil financial swap and natural gas financial collar contracts for the third quarter and to report anticipated results of the price risk management activities for 2003 fourth quarter and 2004 in Item 9 - Regulation FD Disclosure. Current Report on Form 8-K filed on November 3, 2003 to provide estimates for the fourth quarter and full year 2003 and updated summaries of natural gas and crude oil financial swap and natural gas financial collar contracts for 2003 fourth quarter and 2004 in Item 9 - Regulation FD Disclosure. Current Report on Form 8-K filed on November 3, 2003 to furnish the press release issued November 3, 2003 for the third quarter 2003 financial and operational results in Item 7 - Financial Statement and Exhibits and Item 12 - Results of Operations and Financial Condition. Schedule II EOG RESOURCES, INC. VALUATION AND QUALIFYING ACCOUNTS AND RESERVES For the Years Ended December 31, 2003, 2002 and 2001 (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 2003 Reserves deducted from assets to which they apply-- Allowance for Doubtful Accounts $20,287 $ 506 $ 45 $20,748 2002 Reserves deducted from assets to which they apply-- Allowance for Doubtful Accounts $20,114 $ 182 $ 9 $20,287 2001 Reserves deducted from assets to which they apply-- Allowance for Doubtful Accounts $ 1,558 $19,211 $ 655 $20,114
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 and restated effective as of February 24, 2004. 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). 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 -- Form of Rights Certificate (Exhibit 3 to EOG's Registration Statement on Form 8-A, filed February 18, 2000). 4.4 -- 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). 4.5 -- 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). 4.6 -- Amendment, dated as of December 13, 2001, to the Rights Agreement, dated as of February 14, 2000, between EOG and First Chicago Trust Company of New York, as rights agent (Exhibit 2 to Amendment No. 1 to EOG's Registration Statement on Form 8-A/A filed December 14, 2001). 4.7 -- Letter dated December 13, 2001, from First Chicago Trust Company of New York to EOG resigning as rights agent effective January 12, 2002 (Exhibit 3 to Amendment No. 2 to EOG's Registration Statement on Form 8-A/A filed February 7, 2002). 4.8 -- Amendment, dated as of December 20, 2001, to the Rights Agreement, dated as of February 14, 2000, as amended, between EOG and First Chicago Trust Company of New York, as rights agent (Exhibit 4 to Amendment No. 2 to EOG's Registration Statement on Form 8-A/A filed February 7, 2002). 4.9 -- Letter dated December 20, 2001, from EOG Resources, Inc. to EquiServe Trust Company, N.A. appointing EquiServe Trust Company, N.A. as successor rights agent (Exhibit 5 to Amendment No. 2 to EOG's Registration Statement on Form 8-A/A filed February 7, 2002). 4.10 -- Amendment, dated as of April 11, 2002, to the Rights Agreement, dated as of February 14, 2000, as amended, between EOG and EquiServe Trust Company, N.A., as rights agent (Exhibit 4.1 to EOG's Current Report on Form 8-K, filed April 12, 2002). 4.11 -- Amendment, dated as of December 10, 2002, to the Rights Agreement, dated as of February 14, 2000, as amended, between EOG and EquiServe Trust Company, N.A., as rights agent (Exhibit 4.1 to EOG's Current Report on Form 8-K, filed December 11, 2002). 10.1(a) -- Amended and Restated 1994 Stock Plan (Exhibit 4.3 to Form S-8 Registration Statement No. 33-58103, filed March 15, 1995). 10.1(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). 10.1(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). 10.1(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). 10.1(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). 10.1(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). 10.1(g) -- Sixth Amendment to Amended and Restated 1994 Stock Plan, dated effective as of May 8, 2001 (Exhibit 10.1(g) to EOG's Annual Report on Form 10-K for the year ended December 31, 2001). 10.2 -- Amended and Restated 1993 Nonemployee Directors Stock Option Plan (Exhibit A to EOG's Proxy Statement, dated March 28, 2002, with respect to EOG's Annual Meeting of Shareholders). 10.3(a) -- 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). 10.3(b) -- First Amendment to 1992 Stock Plan (As Amended and Restated Effective June 28, 1999) dated effective as of May 8, 2001 (Exhibit 10.7(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 2001). 10.4(a) -- 1996 Deferral Plan (Exhibit 10.63(a) to EOG's Annual Report on Form 10-K for the year ended December 31, 1997). 10.4(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). 10.4(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). 10.4(d) -- 1996 Deferral Plan, as amended and restated effective May 8, 2001 (Exhibit 4.4 to Form S-8 Registration Statement No. 333-84014, filed March 8, 2002). 10.4(e) -- First Amendment to 1996 Deferral Plan, as amended and restated effective May 8, 2001, effective as of September 10, 2002 (Exhibit 10.9(e) to EOG's Annual Report on Form 10-K for the year ended December 31, 2002). 10.5(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). 10.5(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). 10.5(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). 10.5(d) -- Third Amendment to Executive Employment Agreement between EOG and Mark G. Papa, entered into on June 20, 2001, and made effective as of June 1, 2001 (Exhibit 10.10(d) to EOG's Annual Report on Form 10-K for the year ended December 31, 2001). 10.5(e) -- Change of Control Agreement between EOG and Mark G. Papa, effective as of June 20, 2001 (Exhibit 10.10(e) to EOG's Annual Report on Form 10-K for the year ended December 31, 2001). 10.6(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). 10.6(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). 10.6(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). 10.6(d) -- Third Amendment to Executive Employment Agreement between EOG and Edmund P. Segner, III, entered into on June 22, 2001, and made effective as of June 1, 2001 (Exhibit 10.11(d) to EOG's Annual Report on Form 10-K for the year ended December 31, 2001). 10.6(e) -- Change of Control Agreement between EOG and Edmund P. Segner, III, effective as of June 22, 2001 (Exhibit 10.11(e) to EOG's Annual Report on Form 10-K for the year ended December 31, 2001). 10.7(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). 10.7(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). 10.7(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). 10.7(d) -- Third Amendment to Executive Employment Agreement between EOG and Barry Hunsaker, Jr., entered into on June 29, 2001, and made effective as of June 1, 2001 (Exhibit 10.12(d) to EOG's Annual Report on Form 10-K for the year ended December 31, 2001). 10.7(e) -- Change of Control Agreement between EOG and Barry Hunsaker, Jr., effective as of June 29, 2001 (Exhibit 10.12(e) to EOG's Annual Report on Form 10-K for the year ended December 31, 2001). 10.8(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). 10.8(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). 10.8(c) -- Second Amendment to Executive Employment Agreement between EOG and Loren M. Leiker, entered into on July 1, 2001, and made effective as of June 1, 2001 (Exhibit 10.13(c) to EOG's Annual Report on Form 10-K for the year ended December 31, 2001). 10.8(d) -- Change of Control Agreement between EOG and Loren M. Leiker, effective as of July 1, 2001 (Exhibit 10.13(d) to EOG's Annual Report on Form 10-K for the year ended December 31, 2001). 10.9(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). 10.9(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). 10.9(c) -- Second Amendment to Executive Employment Agreement between EOG and Gary L. Thomas, entered into on July 1, 2001, and made effective as of June 1, 2001 (Exhibit 10.14(c) to EOG's Annual Report on Form 10-K for the year ended December 31, 2001). 10.9(d) -- Change of Control Agreement between EOG and Gary L. Thomas, effective as of July 1, 2001 (Exhibit 10.14(d) to EOG's Annual Report on Form 10-K for the year ended December 31, 2001). 10.10(a) -- Change of Control Severance Plan (As Amended and Restated Effective May 8, 2001) (Exhibit 10.15 to EOG's Annual Report on Form 10-K for the year ended December 31, 2001). 10.10(b) -- First Amendment to Change of Control Severance Plan (As Amended and Restated Effective May 8, 2001), effective as of September 10, 2002 (Exhibit 10.15(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 2002). 10.11 -- Employee Stock Purchase Plan (Exhibit 4.4 to Form S-8 Registration Statement No. 333-62256, filed June 4, 2001). 10.12(a) -- Amended and Restated Savings Plan (Exhibit 10.17 to EOG's Annual Report on Form 10-K for the year ended December 31, 2002). *10.12(b) -- First Amendment to Amended and Restated Savings Plan, dated effective as of December 15, 2003. 10.13 -- Executive Officer Annual Bonus Plan (Exhibit C to EOG's Proxy Statement, dated March 30, 2001, with respect to EOG's Annual Meeting of Shareholders). 10.14 -- Form of Grant Agreement to Non-Employee Directors of EOG (Exhibit 10.21 to EOG's Annual Report on Form 10-K for the year ended December 31, 2002). *12 -- Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Dividends. *21 -- List of subsidiaries. *23.1 -- Consent of DeGolyer and MacNaughton. *23.2 -- Opinion of DeGolyer and MacNaughton dated March 1, 2004. *23.3 -- Consent of Deloitte & Touche LLP. *24 -- Powers of Attorney. *31.1 -- Section 302 Certification of Annual Report of Chief Executive Officer. *31.2 -- Section 302 Certification of Annual Report of Principal Financial Officer. *32.1 -- Section 906 Certification of Annual Report of Chief Executive Officer. *32.2 -- Section 906 Certification of Annual Report of Principal Financial Officer. *99.1 -- Current Report on Form 8-K, filed on February 24, 2004. 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 11th day of March, 2004. EOG RESOURCES, INC. (Registrant) By /s/TIMOTHY K. DRIGGERS Timothy K. Driggers Vice President and Chief Accounting Officer (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 11th day of March, 2004. Signature Title /s/ MARK G. PAPA Chairman and Chief Executive Officer and (Mark G. Papa) Director (Principal Executive Officer) /s/ EDMUND P. SEGNER, III President and Chief of Staff and Director (Edmund P. Segner, III) (Principal Financial Officer) /s/ TIMOTHY K. DRIGGERS Vice President and Chief Accounting Officer (Timothy K. Driggers) (Principal Accounting Officer) *GEORGE A. ALCORN Director (George A. Alcorn) *CHARLES R. CRISP Director (Charles R. Crisp) *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) EOG RESOURCES, INC. AND SUBSIDIARIES EXHIBITS TO FORM 10-K FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003 INDEX OF EXHIBITS Exhibit Number Description *3.2 -- By-laws, dated August 23, 1989, as amended and restated effective as of February 24, 2004. *10.12(b) -- First Amendment to Amended and Restated Savings Plan, dated effective as of Decembr 15, 2003. *12 -- Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Dividends. *21 -- List of subsidiaries. *23.1 -- Consent of DeGolyer and MacNaughton. *23.2 -- Opinion of DeGolyer and MacNaughton dated March 1, 2004. *23.3 -- Consent of Deloitte & Touche LLP. *24 -- Powers of Attorney. *31.1 -- Section 302 Certification of Annual Report of Chief Executive Officer. *31.2 -- Section 302 Certification of Annual Report of Principal Financial Officer. *32.1 -- Section 906 Certification of Annual Report of Chief Executive Officer. *32.2 -- Section 906 Certification of Annual Report of Principal Financial Officer. *99.1 -- Current Report on Form 8-K, filed on February 24, 2004. *Exhibits filed herewith.