EOG Resources - 10-K annual report

For the fiscal year ended December 31, 2005

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number: 1-9743

Registrant's telephone number, including area code: 713-651-7000

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:

None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes xNo o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.
Yes oNo x

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 xNo o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer xAccelerated Filer oNon-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes oNo x

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 February 17, 2006 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 February 17, 2006: $17,354,275,342 and as of June 30, 2005: $13,626,764,801.

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 February 17, 2006, Shares Outstanding: 242,547,524.

Documents incorporated by reference. Portions of the following document are incorporated by reference into the indicated parts of this report: Proxy Statement for the May 2, 2006 Annual Meeting of Shareholders to be filed within 120 days after December 31, 2005 (Proxy Statement) - Part III.

PART II

PART III

PART IV

SIGNATURES

(i)

PART I

ITEM 1. Business

(1) Million cubic feet equivalent per day or billion cubic feet equivalent, as applicable; includes natural gas, crude oil, condensate and natural gas liquids.
(2) Dollars per thousand cubic feet or per barrel, as applicable.
(3) Includes $0.23 per Mcf as a result of a revenue adjustment related to an amended Trinidad take-or-pay contract.

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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.

A substantial portion of EOG's oil and gas leases in Utah, Wyoming and 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. 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.

In 2002, the D.C. Circuit reversed a 2000 district court decision and upheld a 1997 MMS gas valuation rule categorically denying allowances for post-production marketing costs such as long-term storage fees and marketer fees; however, the D.C. Circuit decision expressly allows firm demand charges to be deducted. Two trade associations had sought judicial review of the 1997 gas valuation rule and procured a favorable district court decision; however, the D.C. Circuit decision and denial of certorari by the Supreme Court ended the litigation in early 2003. On March 10, 2005, the MMS published a final rule further revising the gas valuation regulations. The 2005 gas rule revision clarifies the deductibility of transportation costs and adopts the 2004 oil valuation rule's cost of capital approach for calculating non-arm's length transportation allowances described below. EOG cannot predict what effect these changes will have on EOG operations but nothing significant is anticipated.

In 2004, the MMS further amended its royalty regulations governing the valuation of crude oil produced from federal leases. The MMS's 2000 oil valuation rule had replaced a set of valuation benchmarks based on posted prices and comparable sales with an indexing system based on spot prices at nearby market centers. Among other things, the 2000 oil valuation rule (like the 1997 gas valuation rule) also categorically disallowed deductions for post-production marketing costs. Two industry trade associations sought judicial review of the 2000 oil valuation rule, but voluntarily dismissed their suit after late 2002 negotiations led the MMS to amend its oil valuation rule further in 2004. The amended rule retained indexing for valuation but replaced spot prices with New York Mercantile Exchange future prices, except in the Rocky Mountain Region and California. The 2004 oil valuation rule also liberalized allowances for non-arm's length transportation arrangements by increasing the multip lier used for calculating the cost of capital. While the 2000 oil valuation rule was likely to increase EOG's royalty obligation somewhat, the 2004 oil valuation rule is likely to lessen that increase.

Sales of crude oil, condensate and natural gas liquids by EOG are made at unregulated market prices.

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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 r estrictive conditions on such sales.

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. 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 and/or adopted from time to time. Although EOG cannot predict what effect, if any, such legislation might have on its operations, the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, the state legislatures, the FERC, the state regulatory commissions and the federal and state 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 followed 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 properti es 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.

Canadian Regulation of Natural Gas and Crude Oil Production. The crude oil and natural gas industry in Canada is subject to extensive controls and regulations imposed by various levels of government. These regulatory authorities may impose regulations on or otherwise intervene in the oil and natural gas industry with respect to prices, taxes, transportation rates, the exportation of the commodity and, possibly, expropriation or cancellation of contract rights. Such regulations may be changed from time to time in response to complaints or economic or political conditions. The implementation of new regulations or the modification of existing regulations affecting the oil and natural gas industry could reduce demand for these commodities, increase EOG's costs and may have a material adverse impact on its operations.

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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 Regulation - Canada. All phases of the crude oil and natural gas industry in Canada are subject to environmental regulation pursuant to a variety of Canadian federal, provincial, and municipal laws and regulations. Such laws and regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and wastes and in connection with spills, releases and emissions of various substances to the environment. These laws and regulations also require that facility sites and other properties associated with EOG's operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, new projects or changes to existing projects may require the submission and approval of environmental assessments or permit applications. These laws and regulations are subject to frequent change and t he clear trend is to place increasingly stringent limitations on activities that may affect the environment. While compliance with such legislation can require significant expenditures, failure to comply with these environmental laws and regulations could result in the assessment of administrative, civil or criminal penalties, suspension or revocation of licenses and, in some instances, the issuance of injunctions to limit or cease operations.

Spills and releases from EOG's properties may have resulted or result in soil and groundwater contamination in certain locations. Such contamination is not unusual within the crude oil and natural gas industries. Any contamination found on, under or originating from the properties may be subject to remediation requirements under Canadian laws. EOG could be required to remove or remediate wastes disposed of or released by prior owners or operators. In addition, EOG could be held responsible for oil and gas properties in which EOG owns an interest but is not the operator.

In December 2002, the Canadian federal government ratified the Kyoto Protocol to the United Nations Framework Convention on Climate Change, which requires Canada to reduce its greenhouse gas emissions to 6% below 1990 levels over the 2008-2012 periods. The Climate Change Plan for Canada, which was released in November 2002, outlines, in very general terms, the approach the Canadian government intends to take to implement its emissions reduction commitment. The Canadian government issued a further climate change plan, Moving Forward on Climate Change: A Plan for Honouring our Kyoto Commitment, in April of 2005. Companies designated as Large Final Emitters of Greenhouse Gases (LFEs), which will include a number of companies in the oil and gas sector, will be assigned targets for emissions reduction. LFEs may meet their targets through investments in their own activities, the purchase of emissions credits from other emitters, investment in domestic offset credits, and the purchase of international credits. The Canadian government has renewed its promise that the cost to industry of compliance will not exceed $15 per tonne of carbon dioxide equivalent. The Canadian government has also committed that post-2012 emissions reduction targets will not make Canadian oil and gas production uncompetitive, and that industry will be consulted on the technical feasibility and economic impacts of targets for the period post-2012. The Canadian government's stated preference is to use the Canadian Environmental Protection Act to regulate industry where necessary. It is expected, however, that the Canadian government will largely delegate regulatory responsibility to the provinces through equivalency agreements, whereby a province will perform the necessary regulatory function if it has a substantively identical (or more onerous) program in place, as compared to that implemented by the Canadian government. The final rules, once known, could affect operations and pr ofitability.

Other International Regulation. EOG's exploration and production operations outside the United States and Canada 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 Trinidad and the United Kingdom.

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Other Matters

Energy Prices. Since EOG is primarily a natural gas producer, it is more significantly impacted by changes in prices for natural gas than changes in prices for crude oil, condensate or natural gas liquids. Average United States and Canada wellhead natural gas prices have fluctuated, at times rather dramatically, during the last three years. These fluctuations resulted in a 75% increase in the average wellhead natural gas price for production in the United States and Canada received by EOG from 2002 to 2003, an increase of 12% from 2003 to 2004, and an increase of 37% from 2004 to 2005. In 2005, a large majority of the wellhead natural gas volumes from Trinidad were sold under contracts with prices which were either wholly or partially dependent on Caribbean ammonia index prices and/or methanol prices. The pricing mechanisms for these contracts will remain the same in 2006. Also in Trinidad, in late December 2005, EOG began selling wellhead natural gas volumes under a new c ontract at prices partially dependent on the United States Henry Hub market prices. In the United Kingdom, wellhead natural gas production is currently being sold on the spot market. 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, ammonia and methanol prices in the future.

Assuming a totally unhedged position for 2006, based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2006 for which prices have not been determined under long-term marketing contracts, EOG's price sensitivity for each $0.10 per Mcf change in average wellhead natural gas price is approximately $24 million for net income and operating cash flow. EOG is not impacted as significantly by changing crude oil prices. EOG's price sensitivity in 2006 for each $1.00 per barrel change in average wellhead crude oil price is approximately $6 million for net income and operating cash flow. Summarized below and in Note 11 to Consolidated Financial Statements is information regarding EOG's current 2006 natural gas hedge position. As of February 22, 2006, EOG had no crude oil hedges.

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 financial commodity derivative instruments, primarily collars and price swaps, as the means to manage this price risk. In addition to 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 Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS Nos. 137, 138 and 149, these 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 physical commodity contracts is included in revenues at the time of settlement, wh ich in turn affects average realized hydrocarbon prices.

Presented below is a summary of EOG's 2006 natural gas financial collar and price swap contracts at February 22, 2006, with prices expressed in dollars per million British thermal units ($/MMBtu) and notional volumes in million British thermal units per day (MMBtud). As indicated, EOG does not have any financial collar or price swap contracts that cover periods beyond October 2006. EOG accounts for these collar and price swap contracts using mark-to-market accounting.

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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. Please refer to Item 1A. Risk Factors beginning on page 14 for further discussion of the risks to which EOG is subject.

EOG's operations outside of the United States and Canada 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.

Texas Severance Tax Exemption. Natural gas production from qualifying Texas wells spudded or completed after August 31, 1996, is entitled to use a reduced severance tax rate for the first 120 consecutive months of production. 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.

Common Stock Rights Agreement. On February 14, 2000, EOG's Board of Directors declared a dividend of one preferred share purchase right (a "Right," and the agreement governing the terms of such Rights, the "Rights Agreement") for each outstanding share of common stock, par value $0.01 per share. The Board of Directors has adopted this Rights Agreement to protect stockholders from coercive or otherwise unfair takeover tactics. The dividend was distributed to the stockholders of record on February 24, 2000. In accordance with the Rights Agreement, each share of common stock issued in connection with the two-for-one stock split effective March 1, 2005, also had one Right associated with it. Each Right, expiring February 24, 2010, represents a right to buy from EOG one hundredth (1/100) of a share of Series E Junior Participating Preferred Stock (Series E) for $90, once the Rights become exercisable. This portion of a Series E share will give th e stockholder approximately the same dividend, voting, and liquidation rights as would one share of common stock. Prior to exercise, the Right does not give its holder any dividend, voting, or liquidation rights. If issued, each one hundredth (1/100) of a Series E share (i) will not be redeemable; (ii) will entitle holders to quarterly dividend payments of $0.01 per share, or an amount equal to the dividend paid on one share of common stock, whichever is greater; (iii) will entitle holders upon liquidation either to receive $1 per share or an amount equal to the payment made on one share of common stock, whichever is greater; (iv) will have the same voting power as one share of common stock; and (v) if shares of EOG's common stock are exchanged via merger, consolidation, or a similar transaction, will entitle holders to a per share payment equal to the payment made on one share of common stock.

The Rights will not be exercisable until ten days after a public announcement that a person or group has become an acquiring person (Acquiring Person) by obtaining beneficial ownership of 10% or more of EOG's common stock, or if earlier, ten business days (or a later date determined by EOG's Board of Directors before any person or group becomes an Acquiring Person) after a person or group begins a tender or exchange offer which, if consummated, would result in that person or group becoming an Acquiring Person. On February 24, 2005, the Rights Agreement was amended to create an exception to the definition of Acquiring Person to permit a qualified institutional investor to hold 10% or more, but less than 20%, of EOG's common stock without being deemed an Acquiring Person if the institutional investor meets the following requirements: (i) the institutional investor is described in Rule 13d-1(b)(1) promulgated under the Securities Exchange Act of 1934 and is eligible to report (and, if s uch institutional investor is the beneficial owner of greater than 5% of EOG's common stock, does in fact report) beneficial ownership of common stock on Schedule 13G; (ii) the institutional investor is not required to file a Schedule 13D (or any successor or comparable report) with respect to its beneficial ownership of EOG's common stock; (iii) the institutional investor does not beneficially own 15% or more of EOG's common stock (including in such calculation the holdings of all of the institutional investor's affiliates and associates other than those which, under published interpretations of the United States Securities and Exchange Commission or its staff, are eligible to file separate reports on Schedule 13G with respect to their beneficial ownership of EOG's common stock); and (iv) the institutional investor does not beneficially own 20% or more of EOG's common stock (including in such calculation the holdings of all of the institutional investor's affiliates and associates). On June 15, 2005, the R ights Agreement was amended again to revise the exception to the definition of Acquiring Person to permit a qualified institutional investor to hold 10% or more but less than 30% of EOG's common stock without being deemed an Acquiring Person if the institutional investor meets the other requirements described above.

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If a person or group becomes an Acquiring Person, all holders of Rights, except the Acquiring Person, may for $90, purchase shares of EOG's common stock with a market value of $180, based on the market price of the common stock prior to such acquisition. If EOG is later acquired in a merger or similar transaction after the Rights become exercisable, all holders of Rights except the Acquiring Person may, for $90, purchase shares of the acquiring corporation with a market value of $180 based on the market price of the acquiring corporation's stock, prior to such merger.

EOG's Board of Directors may redeem the Rights for $0.005 per Right at any time before any person or group becomes an Acquiring Person. If the Board of Directors redeems any Rights, it must redeem all of the Rights. Once the Rights are redeemed, the only right of the holders of Rights will be to receive the redemption price of $0.005 per Right. The redemption price has been adjusted for the two-for-one stock split effective March 1, 2005 and will be adjusted for any future stock split or stock dividends of EOG's common stock. After a person or group becomes an Acquiring Person, but before an Acquiring Person owns 50% or more of EOG's outstanding common stock, the Board of Directors may exchange the Rights for common stock or equivalent security at an exchange ratio of one share of common stock or an equivalent security for each such Right, other than Rights held by the Acquiring Person.

Preferred Stock. EOG currently has two authorized series of preferred stock. On February 14, 2000, EOG's Board of Directors, in connection with the Rights Agreement described above, authorized 1,500,000 shares of the Series E with the rights and preferences described above. On February 24, 2005, EOG's Board of Directors increased the authorized shares of Series E to 3,000,000 as a result of the two-for-one stock split of EOG's common stock effective March 1, 2005. Currently, there are no shares of the Series E outstanding.

On July 19, 2000, EOG's Board of Directors authorized 100,000 shares of Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series B, with a $1,000 Liquidation Preference per share (Series B). Dividends are payable on the shares only if declared by EOG's Board of Directors and will be cumulative. If declared, dividends will be payable at a rate of $71.95 per share, per year on March 15, June 15, September 15 and December 15 of each year beginning September 15, 2000. EOG may redeem all or part of the Series B at any time beginning on December 15, 2009 at $1,000 per share, plus accrued and unpaid dividends. The Series B is not convertible into, or exchangeable for, common stock of EOG. There are 100,000 shares of the Series B currently outstanding.

Following the December 2004 redemption of all outstanding shares of EOG's Flexible Money Market Cumulative Preferred Stock, Series D, EOG filed a Certificate of Elimination with the Secretary of State of the State of Delaware on February 24, 2005 to eliminate the series from EOG's Restated Certificate of Incorporation, as amended.

Current Executive Officers of the Registrant

The current executive officers of EOG and their names and ages are as follows:

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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. Mr. Papa is EOG's principal executive officer.

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 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 duly elected or appointed and shall have qualified.

ITEM 1A. Risk Factors

Our business faces many risks. The risks described below may not be the only risks we face. Additional risks that we do not yet know of, or that we currently think are immaterial, may also impair our business operations or financial results. If any of the events or circumstances described below actually occurs, our business, financial condition or results of operations could suffer and the trading price of our common stock could decline. The following risk factors should be read in conjunction with the other information contained in this report, including the consolidated financial statements and the related notes.

A substantial or extended decline in natural gas or crude oil prices would have a material adverse effect on us.

Prices for natural gas and crude oil fluctuate widely. Since we are primarily a natural gas company, we are more significantly affected by changes in natural gas prices than changes in the prices for crude oil, condensate or natural gas liquids. Among the factors that can cause these price fluctuations are:

• the level of consumer demand;
• weather conditions;
• domestic drilling activity;
• the price and availability of alternative fuels;
• the proximity to, and capacity of, transportation facilities;
• worldwide economic and political conditions;
• the effect of worldwide energy conservation measures; and
• the nature and extent of governmental regulation and taxation.

Our cash flow and earnings depend to a great extent on the prevailing prices for natural gas and crude oil. Prolonged or substantial declines in these commodity prices may adversely affect our liquidity, the amount of cash flow we have available for capital expenditures and our ability to maintain our credit quality and access to the credit and capital markets.

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Our ability to sell our crude oil and natural gas production could be materially harmed if we fail to obtain adequate services such as transportation and processing.

The sale of our crude oil and natural gas production depends on a number of factors beyond our control, including the availability, proximity and capacity of pipelines, natural gas gathering systems and processing facilities. Any significant change in market factors affecting these infrastructure facilities or our failure to obtain these services on acceptable terms could materially harm our business. We deliver crude oil and natural gas through gathering systems and pipelines that we do not own. These facilities may be temporarily unavailable due to market conditions or mechanical reasons, or may not be available to us in the future.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our underlying assumptions could cause the quantities of our reserves to be overstated.

Estimating quantities of proved crude oil and natural gas reserves is a complex process. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions or changes of conditions could cause the quantities of our reserves to be overstated.

To prepare estimates of economically recoverable crude oil and natural gas reserves and future net cash flows, we analyze many variable factors, such as historical production from the area compared with production rates from other producing areas. We also analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also involves economic assumptions relating to commodity prices, production costs, severance and excise taxes, capital expenditures and workover and remedial costs. Actual results most likely will vary from our estimates. Any significant variance could reduce our estimated quantities and present value of reserves.

If we fail to acquire or find sufficient additional reserves, our reserves and production will decline from their current levels.

The rate of production from crude oil and natural gas properties generally declines as reserves are depleted. Except to the extent that we conduct successful exploration and development activities, acquire additional properties containing proved reserves, or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline as reserves are produced. Future crude oil and natural gas production is, therefore, highly dependent upon our level of success in acquiring or finding additional reserves.

Drilling crude oil and natural gas wells is a high-risk activity and subjects us to a variety of factors that we cannot control.

Drilling crude oil and natural gas wells, including development wells, involves numerous risks, including the risk that we may not encounter commercially productive crude oil and natural gas reservoirs. We may not recover all or any portion of our investment in new wells. The presence of unanticipated pressures or irregularities in formations, miscalculations or accidents may cause our drilling activities to be unsuccessful and result in a total loss of our investment. In addition, we often are uncertain as to the future cost or timing of drilling, completing and operating wells. Further, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

• unexpected drilling conditions;
• title problems;
• pressure or irregularities in formations;
• equipment failures or accidents;
• adverse weather conditions;
• compliance with environmental and other governmental requirements, which may increase our costs or restrict our activities; and
• costs of, or shortages or delays in the availability of, drilling rigs, tubular materials and equipment.

We incur certain costs to comply with government regulations, especially regulations relating to environmental protection, and could incur even greater costs in the future.

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Our exploration, production and marketing operations are regulated extensively at the federal, state and local levels, as well as by other countries in which we do business. We have and will continue to incur costs in our efforts to comply with the requirements of environmental and other regulations. Further, the crude oil and natural gas industry regulatory environment could change in ways that might substantially increase these costs.

As an owner or lessee and operator of oil and gas properties, we are subject to various federal, state, local and foreign regulations relating to discharge of materials into, and protection of, the environment. These regulations may, among other things, impose liability on us for the cost of pollution clean-up resulting from operations, subject us to liability for pollution damages, and require suspension or cessation of operations in affected areas. Changes in or additions to regulations regarding the protection of the environment could hurt our business.

We do not insure against all potential losses and could be seriously harmed by unexpected liabilities.

Exploration for and production of crude oil and natural gas can be hazardous, involving natural disasters and other unforeseen occurrences such as blowouts, cratering, fires and loss of well control, which can damage or destroy wells or production facilities, injure or kill people, and damage property and the environment. Offshore operations are subject to usual marine perils, including hurricanes and other adverse weather conditions, and governmental regulations as well as interruption or termination by governmental authorities based on environmental and other considerations. We maintain insurance against many, but not all, potential losses or liabilities arising from our operations in accordance with what we believe are customary industry practices and in amounts that we believe to be prudent. Losses and liabilities arising from such events could reduce our revenues and increase our costs to the extent not covered by insurance.

The occurrence of any of these events and any payments made as a result of such events and the liabilities related thereto, would reduce the funds available for exploration, drilling and production and could have a material adverse effect on our financial position or results of operations.

Our hedging activities may prevent us from benefiting from price increases and may expose us to other risks.

From time to time, we use derivative instruments (primarily collars and price swaps) to hedge the impact of market fluctuations on natural gas and crude oil prices and net income and cash flow. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of price increases above the levels of the hedges. In addition, we are subject to risks associated with differences in prices at different locations, particularly where transportation constraints restrict our ability to deliver oil and gas volumes to the delivery point to which the hedging transaction is indexed.

If we acquire oil and gas properties, our failure to fully identify potential problems, to properly estimate reserves or production rates or costs, or to effectively integrate the acquired operations could seriously harm us.

From time to time, we seek to acquire oil and gas properties. Although we perform reviews of acquired properties that we believe are consistent with industry practices, reviews of records and properties may not necessarily reveal existing or potential problems, nor do they permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Even when problems with a property are identified, we often assume environmental and other risks and liabilities in connection with acquired properties.

There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and actual future production rates and associated costs with respect to acquired properties. Actual results may vary substantially from those assumed in the estimates.

In addition, acquisitions may have adverse effects on our operating results, particularly during the periods in which the operations of acquired properties are being integrated into our ongoing operations.

Terrorist activities and military and other actions could adversely affect our business.

Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as the military or other actions taken in response to these acts, cause instability in the global financial and energy markets. The United States government has issued public warnings that indicate that energy assets might be specific targets of terrorist organizations. These actions could adversely affect us in unpredictable ways, including the disruption of fuel supplies and markets, increased volatility in crude oil and natural gas prices, or the possibility that the infrastructure on which we rely could be a direct target or an indirect casualty of an act of terror.

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Competition in the oil and gas exploration and production industry is intense, and many of our competitors have greater resources than we have.

We compete with major integrated and other independent oil and gas companies for acquisition of oil and gas leases, properties and reserves, equipment and labor required to explore, develop and operate those properties and the marketing of crude oil and natural gas production. Higher recent crude oil and natural gas prices have increased the costs of properties available for acquisition and there are a greater number of companies with the financial resources to pursue acquisition opportunities.

Many of our competitors have financial and other resources substantially larger than those we possess and have established strategic long-term positions and maintain strong governmental relationships in countries in which we may seek new or expanded entry. As a consequence, we may be at a competitive disadvantage in bidding for drilling rights. In addition, many of our larger competitors may have a competitive advantage when responding to factors that affect demand for crude oil and natural gas production, such as changing worldwide prices and levels of production, the cost and availability of alternative fuels and the application of government regulations. We also compete in attracting and retaining personnel, including geologists, geophysicists, engineers and other specialists.

We have substantial capital requirements, and we may be unable to obtain needed financing on satisfactory terms.

We make, and will continue to make, substantial capital expenditures for the acquisition, development, production, exploration and abandonment of our oil and gas reserves. We intend to finance our capital expenditures primarily through cash flow from operations, commercial paper and to a lesser extent and if necessary, bank borrowings and public and private equity and debt offerings. Lower crude oil and natural gas prices, however, would reduce our cash flow and our access to the capital markets. Further, if the condition of the capital markets materially declines, we might not be able to obtain financing on terms we consider acceptable. In addition, a substantial rise in interest rates would decrease our net cash flows available for reinvestment.

ITEM 1B. Unresolved Staff Comments

None.

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.

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 qu antities ultimately recovered. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based.

In general, 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.

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Acreage. The following table summarizes EOG's developed and undeveloped acreage at December 31, 2005. Excluded is acreage in which EOG's interest is limited to owned royalty, overriding royalty and other similar interests.

Producing Well Summary. The following table reflects EOG's ownership in natural gas and crude oil wells located in Texas, the Gulf of Mexico, Oklahoma, New Mexico, Utah, Louisiana, Mississippi, Pennsylvania, Wyoming, and various other states in the United States, Canada, Trinidad and the United Kingdom at December 31, 2005. Gross natural gas and crude oil wells include 809 with multiple completions.

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Drilling and Acquisition Activities. During the years ended December 31, 2005, 2004 and 2003, EOG expended $1,878 million, $1,510 million and $1,333 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:

(1) 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 included in this report as set forth in the Contingencies section in Note 7 of Notes to Consolidated Financial Statements on page F-24.

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 2005.

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PART II

ITEM 5. Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

The following table sets forth, for the periods indicated, the high and low price per share for the common stock of EOG, as reported on the New York Stock Exchange Composite Tape, and the amount of common stock dividend declared per share.

(1) Restated for two-for-one stock split effective March 1, 2005, as discussed below.

On February 2, 2005, EOG announced that the Board of Directors had approved a two-for-one stock split in the form of a stock dividend, payable to record holders as of February 15, 2005 and to be issued on March 1, 2005. In addition, the Board increased the quarterly cash dividend on the common stock by 33%, resulting in a quarterly cash dividend of $0.08 per share pre-split, or $0.04 per share post-split.

On February 1, 2006, the Board increased the quarterly cash dividend on the common stock from the previous $0.04 per share to $0.06 per share.

As of February 17, 2006, there were approximately 270 record holders of EOG's common stock, including individual participants in security position listings. There are an estimated 122,000 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.

The following table sets forth, for the periods indicated, EOG's repurchase activity:

(1) The quarterly total number of shares of 992 consists solely of zero shares (33,079 shares for the full year 2005) that were returned to EOG
     in payment of the exercise price of employee stock options and 992 shares (121,969 shares for the full year 2005) that were withheld by or returned
     to EOG to satisfy tax withholding obligations that arose upon the exercise of employee stock options or the vesting of restricted stock or units.
(2) In September 2001, EOG announced that its Board authorized the repurchase of up to 10,000,000 shares of EOG's common stock. During
     2005, EOG did not repurchase any shares under the Board authorized repurchase program.

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ITEM 6. Selected Financial Data
(In Thousands, Except Per Share Data)

(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 2000 through 2002 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) Years 2001 through 2004 restated for two-for-one stock split effective March 1, 2005.

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ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

Overview

EOG Resources, Inc. (EOG) is one of the largest independent (non-integrated) oil and natural gas companies in the United States with proved reserves in the United States, Canada, offshore Trinidad and the United Kingdom North Sea. EOG operates under a consistent strategy which focuses predominantly on achieving a strong reinvestment rate of return, drilling internally generated prospects, delivering long-term production growth and maintaining a strong balance sheet.

Net income available to common for 2005 of $1,252 million was up 104% compared to 2004 net income available to common of $614 million, attributable primarily to higher commodity prices and increased production. At December 31, 2005, EOG's total reserves were 6.2 trillion cubic feet equivalent, an increase of 548 billion cubic feet equivalent (Bcfe) from December 31, 2004.

Operations

Several important developments have occurred since January 1, 2005.

United States and Canada. The Fort Worth, Texas office was opened in 2004 to expand on EOG's drilling success in the Barnett Shale play of the Fort Worth Basin. EOG has successfully expanded the play beyond its conventional limits by using horizontal drilling and enhanced completion technology. By year-end 2005, EOG had over 500,000 acres under lease in several counties. EOG plans on substantially increasing its drilling program in 2006.

EOG's effort to identify plays with larger reserve potential has proven a successful supplement to its base development and exploitation program in the United States and Canada. EOG plans to continue to drill numerous wells in large acreage plays, which in the aggregate are expected to contribute substantially to EOG's crude oil and natural gas production. EOG has several larger potential plays under way in Wyoming, Utah, Texas, Oklahoma and western Canada.

International. During 2005, EOG commenced natural gas production in Trinidad to supply two new long-term contracts. First, EOG is supplying natural gas that is being used as feedstock for the M5000 methanol plant which commenced operations in September 2005. Second, the Atlantic LNG Train 4 (ALNG) began taking gas in December 2005, prior to commercial operations, and volumes supplied by EOG during this pre-start up period have been higher than EOG's contractual rate.

Although EOG continues to focus on United States and Canada natural gas, EOG sees an increasing linkage between United States and Canada natural gas demand and Trinidad natural gas supply. For example, liquefied natural gas (LNG) imports from existing and planned facilities in Trinidad are serious contenders to meet increasing United States demand. In addition, ammonia, methanol and chemical production has been relocating from the United States and Canada to Trinidad, driven by attractive natural gas feedstock prices in the island nation. EOG believes that its existing position with the supply contracts to the two ammonia plants, the new methanol plant and the ALNG, will continue to give its portfolio an even broader exposure to United States and Canada natural gas fundamentals.

In 2005, EOG continued its progress in the Southern Gas Basin of the United Kingdom North Sea. Production commenced in January 2005 from the Arthur 1 well and in July 2005 from the Arthur 2 well. The Arthur 3 well is expected to spud in the first half of 2006. EOG expects only modest activity in 2006 due to the difficulty in obtaining rigs in the North Sea.

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Capital Structure

As noted, one of management's key strategies is to keep a strong balance sheet with a consistently below average debt-to-total capitalization ratio. At December 31, 2005, EOG's debt-to-total capitalization ratio was 19%, down from 27% at year-end 2004. By primarily utilizing cash provided from its operating activities and proceeds from stock options exercised in 2005, EOG funded its $1,858 million exploration and development expenditures, paid down $93 million of debt and paid dividends to common shareholders of $36 million. In addition, in 2006, EOG's Board of Directors increased the cash dividend on common stock to an annual rate of $0.24 per share, which represents a 50% increase in the annual cash dividend. As management currently assesses price forecast and demand trends for 2006, EOG believes that operations and capital expenditure activity can essentially be funded by cash from operations.

For 2006, EOG's estimated exploration and development expenditure budget is approximately $2.5 billion, excluding acquisitions. United States and Canada natural gas continues to be a key component of this effort. When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer EOG incremental exploration and/or production opportunities. Management believes that EOG continues to maintain one of the strongest prospect inventories in EOG's history.

The following review of operations for each of the three years in the period ended December 31, 2005 should be read in conjunction with the consolidated financial statements of EOG and notes thereto beginning with page F-1.

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Results of Operations

Net Operating Revenues

During 2005, net operating revenues increased $1,349 million to $3,620 million from $2,271 million in 2004. Total wellhead revenues, which are revenues generated from sales of natural gas, crude oil, condensate and natural gas liquids, increased $1,306 million, or 57%, to $3,607 million as compared to $2,301 million in 2004. Natural gas, crude oil, condensate and natural gas liquids revenues solely represent wellhead revenues for these products. Wellhead volume and price statistics for the years ended December 31, were as follows:

(1) Million cubic feet per day or thousand barrels per day, as applicable.
(2) Dollars per thousand cubic feet or per barrel, as applicable.
(3) Includes $0.23 per Mcf as a result of a revenue adjustment related to an amended Trinidad take-or-pay contract.
(4) Million cubic feet equivalent per day or billion cubic feet equivalent, as applicable; includes natural gas, crude oil, condensate and natural gas liquids.

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(1) Total per-unit costs do not include exploration costs, dry hole costs and impairments.

The per-unit costs of lease and well, including transportation, DD&A, taxes other than income and interest expense, net for 2005 compared to 2004 were due primarily to the reasons set forth below.

Lease and well expense includes expenses for EOG operated properties, as well as expenses billed to EOG from other operators where EOG is not the operator of a property. Lease and well expense can be divided into the following categories: costs to operate and maintain EOG's oil and natural gas wells, the cost of workovers, transportation costs associated with selling hydrocarbon products and lease and well administrative expenses. Operating and maintenance expenses include, among other service costs, pumping services, salt water disposal, equipment repair and maintenance, compression expense, lease upkeep, fuel and power. Workovers are costs to restore or maintain production from existing wells.

Each of these categories of costs individually fluctuates from time to time as EOG attempts to maintain and increase production while maintaining efficient, safe and environmentally responsible operations. EOG continues to increase its operating activities by drilling new wells in existing and new areas. Operating costs within these existing and new areas, as well as the costs of services charged to EOG by vendors, fluctuate over time.

Lease and well expenses, including transportation, of $373 million were $102 million higher than 2004 due primarily to higher operating and maintenance expenses in the United States ($40 million); increased transportation related costs in the United States ($28 million) and the United Kingdom ($7 million); higher lease and well administrative expenses in the United States ($11 million); changes in the Canadian exchange rate ($6 million); and higher workover expenditures in the United States ($3 million) and Trinidad ($2 million).

DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method. EOG's DD&A rate and expense are the composite of numerous individual field calculations. There are several factors that can impact an individual field, such as the field production profile; drilling or acquisition of new wells; disposition of existing wells; reserve revisions (upward or downward), primarily related to well performance; and impairments. Changes to the individual fields, due to any of these factors, may cause EOG's composite DD&A rate and expense to fluctuate from year to year.

DD&A expenses of $654 million were $150 million higher than 2004 primarily as a result of increased production in the United States ($46 million), Canada ($6 million) and Trinidad ($5 million) and the commencement of production in the United Kingdom ($14 million). DD&A rates increased in the United States due to a gradual proportional increase in production from higher cost properties ($59 million) and in Canada predominantly from the development of acquired proved reserves ($9 million). The Canadian exchange rate also contributed to the DD&A expense increase ($8 million).

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Taxes other than income include severance/production taxes, ad valorem/property taxes, payroll taxes, franchise taxes and other miscellaneous taxes. Taxes other than income of $199 million were $65 million higher than 2004.

Severance/production taxes increased due primarily to increased wellhead revenues in the United States ($41 million), Trinidad ($7 million) and Canada ($3 million), partially offset by the increase in credits taken for a Texas high cost gas severance tax exemption ($10 million) and a production tax audit lawsuit in the first quarter of 2004 ($5 million). Other items contributing to the increase were an additional Trinidadian Supplemental Petroleum Tax expense as a result of 2005 tax legislation that increased the tax expense retroactively to January 2004 ($7 million) and 2004 production tax relief in Trinidad ($6 million). Ad valorem/property taxes increased primarily due to higher property valuation in the United States ($11 million).

Net interest expense in 2005 included costs associated with the early retirement of 2008 Notes ($8 million) (see Note 2 to Consolidated Financial Statements). Excluding these early retirement costs, the 2005 net interest expense decreased $8 million compared to 2004 primarily due to higher capitalized interest ($5 million), an interest charge related to the results of a production tax audit lawsuit in the first quarter of 2004 ($2 million) and lower average debt balance in the United States ($1 million).

Exploration costs of $133 million were $39 million higher than 2004 due primarily to increased geological and geophysical expenditures in the Barnett Shale area.

Impairments include amortization of unproved leases, as well as impairments under the Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which requires an entity to compute impairments to the carrying value of long-lived assets based on future cash flow analysis. Impairments of $78 million were $4 million lower than 2004 due primarily to lower amortization of unproved leases in the United States ($12 million) and lower impairments to the carrying value of certain long-lived assets in Canada ($8 million), partially offset by higher impairments to the carrying value of certain long-lived assets in the United States ($14 million) and higher amortization of unproved leases in Canada ($2 million). EOG recorded impairments of $31 million and $25 million for 2005 and 2004, respectively, under SFAS No. 144 for certain properties in the United States and Canada.

Other income, net of $36 million increased $26 million compared to 2004 primarily as a result of higher gains on sales of properties ($7 million), interest income ($6 million) and equity income from investments in the Caribbean Nitrogen Company Limited (CNCL) and Nitrogen (2000) Unlimited (N2000) ammonia plants in 2005 ($5 million); decreased net foreign currency transaction losses ($4 million); and a gain on the sale of part of EOG's interest in the N2000 ammonia plant in the first quarter of 2005 ($2 million).

Income tax provision of $706 million increased $404 million as compared to 2004, due primarily to higher pre-tax income ($383 million) and income taxes associated with the repatriation of foreign earnings ($24 million). The effective tax rate for 2005 increased to 36% from 33% in 2004.

2004 compared to 2003. During 2004, operating expenses of $1,292 million were $245 million higher than the $1,047 million incurred in 2003. The following table presents the costs per Mcfe for the years ended December 31:

The higher per-unit costs of lease and well, including transportation, DD&A and taxes other than income for 2004 compared to 2003 were due primarily to the reasons set forth below.

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Lease and well expenses, including transportation, of $271 million were $58 million higher than 2003 due primarily to a general increase in service costs related to increased operating activities, including an increase in the number of wells, in the United States ($18 million), Canada ($16 million), and Trinidad ($1 million); increased transportation related costs in the United States ($14 million), Canada ($2 million) and the United Kingdom ($2 million); and changes in the Canadian exchange rate ($5 million).

DD&A expenses of $504 million increased $63 million from 2003 due primarily to increased production in Canada ($18 million), the United States ($10 million), and Trinidad ($4 million); the commencement of production in the United Kingdom ($2 million); increased DD&A rates in the United States due to a gradual proportional increase in production from higher cost properties ($13 million); increased DD&A rates in Canada mainly from developing acquired proved reserves ($8 million); and changes in the Canadian exchange rate ($7 million).

G&A expenses of $115 million were $15 million higher than 2003 due primarily to expanded operations.

Taxes other than income of $134 million were $48 million higher than 2003 due primarily to a decrease in credits taken against severance taxes resulting from the qualification of additional wells for a Texas high cost gas severance tax exemption ($19 million); an increase as a result of higher wellhead revenues in the United States ($13 million), Trinidad ($2 million) and Canada ($1 million); higher property taxes as a result of higher property valuation in the United States ($6 million); the results of a production tax audit lawsuit in the first quarter of 2004 ($5 million); and an increase in the number of wells and facilities in Canada ($2 million).

Exploration costs of $94 million were $18 million higher than 2003 due primarily to increased geological and geophysical expenditures in the United States ($6 million), Canada ($3 million), the United Kingdom ($3 million) and Trinidad ($1 million); and increased exploration administrative expenses across EOG ($4 million).

Impairments of $82 million were $8 million lower than 2003 due primarily to lower amortization of unproved leases in the United States ($10 million), partially offset by higher amortization of unproved leases in Canada ($2 million). Total impairments under SFAS No. 144 were $25 million in each of 2004 and 2003.

Net interest expense of $63 million was $4 million higher than 2003 due primarily to a slightly higher average debt balance.

Other income (expense), net for 2004 included income from equity investments of $11 million, gains on sales of reserves and related assets of $6 million and foreign currency transaction losses of $7 million as a result of applying the changes in the Canadian exchange rate to certain intercompany short-term loans that eliminate in consolidation.

Income tax provision increased $85 million to $301 million compared to 2003, primarily resulting from higher income before income taxes ($95 million), offset by lower deferred income taxes associated with the Alberta, Canada corporate tax rate ($5 million) and lower effective foreign income tax rates ($2 million). The net effective tax rate for 2004 remained unchanged from the 2003 rate of 33%.

In November 2003, Canada enacted legislation reducing the Canadian federal income tax rate for companies in the resource sector from 28% to 27% for 2003, with further reductions to 21% phased in over the next four years. This legislation also made changes to the tax treatment of crown royalties and the resource allowance. Beginning in 2003, Canadian taxpayers are allowed to deduct 10% of actual provincial and other crown royalties. This percentage increases each year through 2007, at which time 100% of crown royalties will be deductible. The resource allowance, a statutory deduction calculated as 25% of adjusted resource profits, will be phased out through 2007, when the deduction will be completely eliminated.

Capital Resources and Liquidity

Cash Flow

The primary sources of cash for EOG during the three-year period ended December 31, 2005 included funds generated from operations, funds from new borrowings, proceeds from sales of treasury stock attributable to employee stock option exercises and the employee stock purchase plan, proceeds from the sale of oil and gas properties and proceeds from sales of partial interests in certain equity investments in Trinidad. Primary cash outflows included funds used in operations, exploration and development expenditures, oil and gas property acquisitions, repayment of debt, dividend payments to shareholders, redemption of preferred stock and common stock repurchases.

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2005 compared to 2004. Net cash provided by operating activities of $2,369 million in 2005 increased $925 million as compared to 2004 primarily reflecting an increase in wellhead revenues ($1,306 million), a favorable change in the net cash flows from settlement of financial commodity derivative contracts ($93 million) and favorable changes in working capital and other liabilities ($35 million), partially offset by an increase in cash operating expenses ($217 million) and an increase in cash paid for income taxes ($279 million).

Net cash used in investing activities of $1,678 million in 2005 increased by $281 million as compared to 2004 due primarily to increased additions to oil and gas properties ($308 million) and unfavorable changes in working capital related to investing activities ($28 million), partially offset by an increase in proceeds from the sale of oil and gas properties in 2005 ($40 million) and the sale of part of EOG's interest in the N2000 ammonia plant in 2005 ($18 million). Changes in Components of Working Capital Associated with Investing Activities included changes in accounts payable associated with the accrual of exploration and development expenditures and changes in inventories which represent material and equipment used in drilling and related activities.

Cash used in financing activities of $72 million in 2005 increased $29 million as compared to 2004. Cash provided by financing activities for 2005 included a long-term debt borrowing ($250 million) and proceeds from sales of treasury stock attributable to employee stock option exercises and the employee stock purchase plan ($65 million). Cash used by financing activities for 2005 included repayments of long-term debt borrowings ($343 million) and cash dividend payments ($43 million).

2004 compared to 2003. Net cash provided by operating activities of $1,444 million in 2004 increased $195 million as compared to 2003 primarily reflecting an increase in wellhead revenues of $482 million, partially offset by an increase in cash operating expenses of $139 million, an increase in current tax expense of $72 million, unfavorable changes in working capital and other liabilities of $48 million and an increase in realized losses from mark-to-market commodity derivative contracts of $38 million.

Net cash used in investing activities of $1,397 million in 2004 increased by $189 million as compared to 2003 due primarily to increased additions to oil and gas properties of $171 million and unfavorable changes in working capital related to investing activities of $12 million. Changes in Components of Working Capital Associated with Investing Activities included changes in accounts payable associated with the accrual of exploration and development expenditures and changes in inventories which represent material and equipment used in drilling and related activities.

Cash used in financing activities was $43 million in 2004 versus $57 million in 2003. Cash provided by financing activities for 2004 included long-term debt borrowing of $150 million and proceeds from sales of treasury stock attributable to employee stock option exercises and the employee stock purchase plan of $76 million. Cash used by financing activities for 2004 included repayments of long-term debt borrowings of $175 million, redemption of all 500 outstanding shares of Series D Preferred Stock of $50 million and cash dividend payments of $38 million.

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Total Exploration and Development Expenditures

The table below sets out components of total exploration and development expenditures for the years ended December 31, 2005, 2004 and 2003, along with the total budgeted for 2006, excluding acquisitions (in millions):

(1) Asset Retirement Costs for 2003 does not include the cumulative effect of adoption of SFAS No. 143, "Accounting for Asset Retirement Obligations" on January 1, 2003.

Exploration and development expenditures of $1,858 million for 2005 were $347 million higher than the prior year due primarily to (i) increased drilling and facilities expenditures of $338 million resulting from higher drilling and facilities expenditures in the United States ($377 million) and changes in the Canadian exchange rate related to drilling and facilities expenditures ($17 million), partially offset by decreased drilling and facilities expenditures in the United Kingdom ($24 million), Trinidad ($21 million) and Canada ($11 million) and; (ii) increased exploration costs ($39 million) primarily in the Barnett Shale area; partially offset by decreased dry hole costs ($27 million). The 2005 exploration and development expenditures of $1,858 million includes $1,300 million in development, $487 million in exploration, $56 million in property acquisitions and $15 million in capitalized interest. The 2004 exploration and development expenditures of $1,511 million includes $1,009 m illion in development, $440 million in exploration, $52 million in property acquisitions and $10 million in capitalized interest. The 2003 exploration and development expenditures of $1,321 million included $651 million in development, $256 million in exploration, $405 million in property acquisitions and $9 million in capitalized interest.

The level of exploration and development expenditures, including acquisitions, will vary in future periods depending on energy market conditions and other related economic factors. EOG has significant flexibility with respect to financing alternatives and the ability to adjust its exploration and development expenditure budget as circumstances warrant. There are no material continuing commitments associated with current expenditure plans.

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Derivative Transactions

During 2005, EOG recognized gains on mark-to-market financial commodity derivative contracts of $10 million, which included realized gains of $10 million. During 2004, EOG recognized losses on mark-to-market financial commodity derivative contracts of $33 million, which included realized losses of $82 million and collar premium payments of $1 million. (See Note 11 to Consolidated Financial Statements.)

Presented below is a summary of EOG's 2006 natural gas financial collar and price swap contracts at February 22, 2006, with prices expressed in dollars per million British thermal units ($/MMBtu) and notional volumes in million British thermal units per day (MMBtud). As indicated, EOG does not have any financial collar or price swap contracts that cover periods beyond October 2006. As of February 22, 2006, EOG had no crude oil hedges. EOG accounts for these collar and price swap contracts using mark-to-market accounting.

Financing

EOG's debt-to-total capitalization ratio was 19% as of December 31, 2005 compared to 27% as of December 31, 2004.

During 2005, total debt decreased $93 million to $985 million (see Note 2 to Consolidated Financial Statements). The estimated fair value of EOG's debt at December 31, 2005 and 2004 was $1,025 million and $1,146 million, respectively. The estimated fair value was based upon quoted market prices and, where such prices were not available, upon interest rates currently available to EOG at year-end. EOG's debt is primarily at fixed interest rates. At December 31, 2005, a 1% decline in interest rates would result in a $46 million increase in the estimated fair value of the fixed rate obligations (see Note 11 to Consolidated Financial Statements).

During 2005 and 2004, EOG utilized cash provided by operating activities and commercial paper to fund its operations. While EOG maintains a $600 million commercial paper program, the maximum outstanding at any time during 2005 was $380 million, and the amount outstanding at year-end was zero. EOG considers this excess availability, which is backed by the $600 million Revolving Credit Agreement with domestic and foreign lenders described in Note 2 to Consolidated Financial Statements, combined with approximately $688 million of availability under its shelf registration described below, to be ample to meet its ongoing operating needs.

In 2005, the short-term commercial paper loan balance was reduced by $92 million; the $174 million, 6.00% Notes due 2008 and the remaining $75 million outstanding under the Senior Unsecured Term Loan Facility were repaid primarily with cash generated from operating activities. On February 17, 2006, a foreign subsidiary of EOG repaid $50 million of the $250 million it borrowed in 2005 (see Note 2 to Consolidated Financial Statements). During 2006, based on resources available at December 31, 2005, EOG plans to pay off the $126 million, 6.70% Notes due 2006.

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Contractual Obligations

The following table summarizes EOG's contractual obligations at December 31, 2005 (in thousands):