General

EOG Resources, Inc., a Delaware corporation organized in 1985, together with its subsidiaries (collectively, EOG), explores for, develops, produces and markets crude oil, natural gas liquids (NGLs) and natural gas primarily in major producing basins in the United States of America (United States or U.S.), The Republic of Trinidad and Tobago (Trinidad), The People's Republic of China (China), Canadathe Sultanate of Oman (Oman) and, from time to time, select other international areas.  EOG's principal producing areas are further described in "Exploration and Production" below.  EOG's Annual Reports on Form 10-K, Quarterly Reports on Form 10‑Q, Current Reports on Form 8-K and any amendments to those reports (including related exhibits and supplemental schedules,schedules) filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act)Act of 1934 (as amended) are made available, free of charge, through EOG's website, as soon as reasonably practicable after such reports have been filed with, or furnished to, the United States Securities and Exchange Commission (SEC).  EOG's website address is www.eogresources.com. Information on our website is not incorporated by reference into, and does not constitute a part of, this report.

At December 31, 2018,2020, EOG's total estimated net proved reserves were 2,9283,220 million barrels of oil equivalent (MMBoe), of which 1,5321,514 million barrels (MMBbl) were crude oil and condensate reserves, 614813 MMBbl were natural gas liquids (NGLs)NGLs reserves and 4,6875,360 billion cubic feet (Bcf), or 782893 MMBoe, were natural gas reserves (see "Supplemental Information to Consolidated Financial Statements").  At such date, approximately 98% of EOG's net proved reserves, on a crude oil equivalent basis, were located in the United States, 1% in Trinidad and 1% in other international areas.  Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet (Mcf) of natural gas.

EOG's operations are all crude oil and natural gas exploration and production related. For information regarding the risks associated with EOG's domestic and foreign operations, see ITEM 1A, Risk Factors.

EOG's business strategy is to maximize the rate of return on investment of capital by controlling operating and capital costs and maximizing reserve recoveries.  Pursuant to this strategy, each prospective drilling location is evaluated by its estimated rate of return. This strategy is intended to enhance the generation of cash flow and earnings from each unit of production on a cost-effective basis, allowing EOG to deliver long-term production growth while maintainingin shareholder value and maintain a strong balance sheet.  EOG is focused on innovation and cost-effective utilization of advanced technology associated with three-dimensional seismic and microseismic data, the development of reservoir simulation models, the use of improved drilling equipment and completion technologies for horizontal drilling and formation evaluation.  These advanced technologies are used, as appropriate, throughout EOG to reduce the risks and costs associated with all aspects of oil and gas exploration, development and exploitation.  EOG implements its strategy primarily by emphasizing the drilling of internally generated prospects in order to find and develop low-cost reserves.  Maintaining the lowest possible operating cost structure, that is consistentcoupled with efficient and safe operations and environmentally responsible operationsrobust environmental stewardship practices and performance, is also an important goalintegral 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.

Exploration and Production

United States Operations

EOG's operations are located in most of the productive basins in the United States with a focus on crude oil and, to a lesser extent, liquids-rich natural gas plays.

At December 31, 2018,2020, on a crude oil equivalent basis, 53%48% of EOG's net proved reserves in the United States were crude oil and condensate, 21%26% were NGLs and 26% were natural gas. The majority of these reserves are in long-lived fields with well-established production characteristics. EOG believes that opportunities exist to increase production through continued development in and around many of these fields and through the utilization of applicable technologies. EOG also maintains an active exploration program designed to extend fields and add new trends and resource plays to its already broad portfolio.

The following is a summary of significant developments during 20182020 and certain 2019anticipated 2021 plans for certain areas of EOG's United States operations.

In the PermianDelaware Basin, EOG completed 265247 net wells during 2018,2020, primarily in the Delaware Basin Wolfcamp, Shale, Bone Spring and Leonard plays. The Delaware Basin consists of approximately 4,800 feet of oil rich stacked pay potential offering EOG continued to consolidatemultiple co-development opportunities throughout its 404,000 total net acreage position in each of these world-class assets through small leasing transactions andposition.

In the exchange of acreage with other nearby operators.Delaware Basin Upper Wolfcamp play, EOG has approximately 346,000226,000 net acres and completed 166 net wells in 2020. EOG continued its Upper Wolfcamp development plan with well spacing as close as 500 feet in the crude oil portion of the play and 880 feet in the combination crude oil and natural gas portion. In addition to the Upper Wolfcamp, EOG completed 7 net wells in 2020 in the newly announced Middle Wolfcamp play and has identified 193,000 net prospective acres. Continued improvement and excellent results in the Delaware Basin Wolfcamp Shale play where it completed 219 net wells in 2018. The success of the 2018 Wolfcamp program was due towere supported by optimized well spacing, enhanced well completions, precision targeting, high-density stimulationsdrilling and continued cost reductions. The program shifted towardMoving forward into 2021, the development of larger packages of wells during 2018, which also contributed to cost reductions. The high-return Delaware Basin Wolfcamp Shale play will continue to be a primary area of focus in 2019. focus.

In the Bone Spring play, EOG has three main sub-plays: the First, Second and Third Bone Spring. In 2020, EOG completed 56 total net Bone Spring wells within the three sub-plays on its combined 289,000 net prospective acres. Of the three sub-plays, the Second Bone Spring play,had the majority of the activity in 2020 with EOG holds approximately 289,000completing 42 net acres and completed 18 net wells in 2018.wells. The Second Bone Spring play is anotherplays continue to be an integral part of EOG's PermianEOG’s Delaware Basin plans and portfolio.

In the Leonard Shale play, EOG hasholds approximately 160,000 net acres and continuedmaintained its development plan with 1718 net wells completed in 2018. EOG also had strong results in2020. With a strategy of developing deeper targets first while simultaneously collecting data from the First Bone Spring where it holds approximately 100,000 net acres and completed eight net wells in 2018. shallow targets, the Leonard play will progressively become a more active part of EOG’s program.

Activity in 20192021 will continue to beremain focused inon the Delaware Basin Wolfcamp, Shale, Second Bone Spring, First Bone Spring, and Leonard plays, where EOG expects to complete approximately 270275 net wells.

Activity in the Rocky Mountain area increased in 2018 with a focus2020 was focused on the Wyoming Powder River and DJ Basins.Basin. In the Powder River Basin, EOG operated a two-rigone-rig program completing 41and completed 35 net wells and identified future drilling locations, mostly in the Niobrara, Mowry, Turner and Parkman formations. In addition, key infrastructure was added in order to lower operating costs and increase price realizations going forward. In the DJ Basin, EOG operated one rig for a partial year and completed 17 net wells in both the Codell and the Niobrara formations. The focusActivity in 2019 will be to add infrastructure and operate a drilling program to further delineate the basin and test additional targets, to better position the company for a more robust development program in 2020 and beyond. In the Wyoming DJ Basin drilling, completion, and operating costs continuedis expected to decline and there is a significant high-returnbe minimal in 2021 as development program scheduled for 2019. Drilling activity increased incontinues to shift to the Powder River Basin. In the Williston Basin, in 2018 after pausing for several years while the company reduced its inventory of drilled uncompleted wells (DUCs). The 20EOG completed 3 net wells completed in 2018 targeted the Bakken and Three Forks formationsForks. In 2020, production in the Rocky Mountain area and benefited fromWilliston Basin was significantly curtailed, primarily in the application of precision targeting. Activitysecond quarter, in 2019response to crude oil price declines, but has subsequently returned to normal levels. In 2021, activity will be similar, as will the seasonal program of completing wells mostlyfocused on development in the summer while drilling operations are conducted throughout the year.Powder River Basin with plans to complete approximately 45 net wells. EOG currently holds approximately 1.2 million net acres in the Rocky Mountain area.

In the Mid-Continent area, EOG continued its development of the Woodford Oil Window play with 2615 net wells completed during 2018.2020. EOG holds 47,000approximately 37,000 net acres in the play and plans to build on its initial success in the Woodford Oil Window with 30 net well completions in 2019. In 2018, EOG completed 22 gross (four net) wells in the Western Anadarko Basin Marmaton Sand.

Operations Outside the United States

EOG has operations offshore Trinidad, in the China Sichuan Basin, Oman and in Canada and is evaluating additional exploration, development and exploitation opportunities in these and other select international areas. EOG sold its operations in the United Kingdom (U.K.) East Irish Sea in the fourth quarter of 2018.

Several fields in the SECC, Block, Modified U(a) Block,, Modified U(b) Block, Blockand 4(a), the Blocks, Banyan Field and the Sercan Area have been developed and are producing natural gas and crude oil and condensate. Natural gas from EOG's Trinidad operations currently is sold under various contracts with the National Gas Company of Trinidad and Tobago Limited and its subsidiary (NGC). Crude oil and condensate from EOG's Trinidad operations currently is sold to the Petroleum Company of Trinidad and Tobago Limited and its successor, Heritage Petroleum Company Limited. 

In 2018,2020, EOG's net production from Trinidad averaged approximately 266180 MMcfd of natural gas and approximately 0.81.0 MBbld of crude oil and condensate. In 2020, EOG drilled three net wells and completed two net wells. The remaining net well made a discovery that is being evaluated. All wells discovered commercially economic reserves.

In 2018, EOG conducted an ocean bottom nodal seismic survey in the SECC Block and the Pelican Field and continues to process and review the initial data.

In 2018, net production in Canada averaged approximately 8 MMcfd of natural gas.

In 2018,2020, EOG processed certain of its United States wellhead natural gas production, either at EOG-owned facilities or at third-party facilities, extracting NGLs. NGLs were sold at prevailing market prices, into either local markets or downstream locations. In certain instances, EOG exchanged its NGL production for purity products received downstream, which were sold at prevailing market prices. In 2019, the2021, such pricing mechanism for such production ismechanisms are expected to remain the same.

In 2018,2020, consistent with its diversified marketing strategy, the majority of EOG's United States wellhead natural gas production was sold into local markets or transported by pipeline to various locations, including Katy, Texas; East Texas; the Agua Dulce Hub in South Texas; the Cheyenne Hub;Hub in Weld County, Colorado; Southern California; orand Chicago, Illinois. PricingRemaining natural gas production was sold into local markets. In each case, pricing was based on the spot market price at the ultimate sales point. In 2019,2021, the pricing mechanism for such production is expected to remain the same. Additionally, EOG sells natural gas to a liquefied natural gas liquefaction facility near Corpus Christi, Texas, and receives pricing based on the Platts Japan Korea Marker. At December 31, 2018,2020, EOG iswas committed to deliver to multiple parties fixed quantities of natural gas of 64 Bcf in 2019, 15 Bcf in 2020, 10170 Bcf in 2021, 2105 Bcf in 2022, 91 Bcf in 2023, 94 Bcf in 2024, 81 Bcf in 2025 and 111,609 Bcf thereafter, all of which is expected to be delivered from future production of available reserves.

In 2018,2020, 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 remaining volumes were sold under a contract at prices partially dependent on United States Henry Hub market prices andor under a fixed price contract. The pricing mechanisms for these contractsIn 2021, natural gas volumes from Trinidad will be sold under a fixed price contract ending in Trinidad are expected to remain the same in 2019.2026.

In 2018,2020, all wellhead natural gas volumes from China were sold at regulated prices based on the purchaser's pipeline sales volumes to various local market segments. The pricing mechanism for production in China is expected to remain the same in 2019.2021.

In certain instances, EOG purchases and sells third-party crude oil and natural gas in order to balance firm transportation capacity with production in certain areas and to utilize excess capacity at EOG-owned facilities.

During 2018, two2020, three purchasers each accounted for more than 10% of EOG's total wellhead crude oil and condensate, NGLNGLs and natural gas revenues and gathering, processing and marketing revenues. The twothree purchasers are in the crude oil refining industry. EOG does not believe that the loss of any single purchaser would have a materialmaterially adverse effect on its financial condition or results of operations.

Wellhead Volumes and Prices

The following table sets forth certain information regarding EOG's wellhead volumes of, and average prices for, crude oil and condensate, NGLs and natural gas. The table also presents crude oil equivalent volumes which are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 Mcf of natural gas for each of the years ended December 31, 2018, 20172020, 2019 and 2016.2018. See ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations, for wellhead volumes on a per-day basis.

EOG competes with major integrated oil and gas companies, government-affiliated oil and gas companies and other independent oil and gas companies for the acquisition of licenses and leases, properties and reserves and access to the facilities, equipment, materials, services, and employees and other contract personnel (including geologists, geophysicists, engineers and other specialists) required to explore for, develop, produce, market and transport crude oil, NGLs and natural gas. In addition, certainCertain of EOG's competitors have financial and other resources substantially greater than those EOG possesses and have established strategic long-term positions or strong governmental relationships in countries or areas in which EOG may seek new or expanded entry. As a consequence, EOG may be at a competitive disadvantage in certain respects, such as in bidding for drilling rights or in accessing necessary services, facilities, equipment, materials and personnel. In addition, EOG's larger competitors may have a competitive advantage when responding to factors that affect demand for crude oil, NGLs and natural gas, such as changing worldwide prices and levels of production and the cost and availability of alternative fuels. EOG also faces competition to a lesser extent, from competing energy sources, such as alternativerenewable energy sources. See ITEM 1A, Risk Factors.

The transportation and sale for resale of natural gas in interstate commerce are regulated pursuant to the Natural Gas Act of 1938, as amended (NGA), and the Natural Gas Policy Act of 1978. These statutes are administered by the Federal Energy Regulatory Commission (FERC). Effective January 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, may be subject in the future to greater federal oversight, including the possibility that the FERC might prospectively impose more restrictive conditions on such sales. Conversely, sales of crude oil and condensate and NGLs by EOG are made at unregulated market prices.

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. EOG also could incur costs related to the clean-up of third-party 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 third-party sites. In addition, EOG could be responsible under environmental laws and regulations for oil and gas properties in which EOG previously owned or currently owns an interest, but was or is not the operator. Moreover, EOG is subject to the United States (U.S.)U.S. Environmental Protection Agency's (U.S. EPA) rule requiring annual reporting of greenhouse gas (GHG)GHG emissions and, as discussed further below, is also subject to federal, state and local laws and regulations regarding hydraulic fracturing.fracturing and other aspects of our operations.

Compliance with environmental laws and regulations increases EOG's overall cost of business, but has not had, to date, a material adverse effect on EOG's operations, financial condition or results of operations. In addition, it is not anticipated, based on current laws and regulations, that EOG will be required in the near future to expend amounts (whether for environmental control facilities or otherwise) that are material in relation to its total exploration and development expenditure program in order to comply with such laws and regulations. However, given that such laws and regulations are subject to change, EOG is unable to predict the ultimate cost of compliance or the ultimate effect on EOG's operations, financial condition and results of operations.

At the international level, the U.S., in December 2015, the U.S. participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The Paris Agreement (adopted at the conference) calls for nations to undertake efforts with respect to global temperatures and GHG emissions. The Paris Agreement went into effect on November 4, 2016. However,While the U.S. has announced its intentionwithdrew from the Paris Agreement on November 4, 2020, President Biden issued an executive order on January 20, 2021 recommitting the United States to withdraw from the Paris Agreement. In response,addition, many state and local officials have stated their intent to intensify efforts to uphold the commitments set forth in the international accord. Further, on January 27, 2021, President Biden issued Executive Order 14008 entitled "Tackling the Climate Crisis at Home and Abroad," directing the Secretary of the Interior, to the extent consistent with applicable law and in consultation with other agencies and stakeholders, to, among other things, consider whether to adjust royalties associated with oil and gas resources extracted from federal lands and offshore waters to account for corresponding climate costs.

EOG believes that its strategy to reduce GHG emissions throughout its operations is both in the best interest of the environment and a prudent business practice. EOG has developed a system that is utilized in calculating GHG emissions from its operating facilities. This emissions management system calculates emissions based on recognized regulatory methodologies, where applicable, and on commonly accepted engineering practices. EOG reports GHG emissions for facilities covered under the U.S. EPA's Mandatory Reporting of Greenhouse Gases Rule published in 2009, as amended.

The regulation of hydraulic fracturing is primarily conducted at the state and local level through permitting and other compliance requirements. In April 2012, however, the U.S. EPA issued regulations specifically applicable to the oil and gas industry that require operators to significantly reduce VOC emissions from natural gas wells that are hydraulically fractured through the use of "green completions" to capture natural gas that would otherwise escape into the air. The U.S. EPA has also issued regulations that establish standards for VOC emissions from several types of equipment, including storage tanks, compressors, dehydrators, and valves and sweetening units at gas processing plants. In addition, in May 2016, the U.S. EPA issued regulations that require operators to reduce methane and VOC emissions from new, modified and reconstructed crude oil and natural gas wells and equipment located at natural gas production gathering and booster stations, gas processing plants and natural gas transmission compressor stations. In September 2020, the U.S. EPA issued amendments to the 2012 and 2016 new source performance standards, which removed the transmission and storage segment from the new source performance standards, rescinded VOC and methane emissions standards for the transmission and storage segment, and rescinded methane emissions standards for the production and processing segments.

In November 2016, the BLM issued a final rule that limits venting, flaring and leaking of natural gas from oil and gas wells and equipment on federal and Indian lands, though, in September 2018, the BLM issued a final rule rescinding certain requirements of that rule. ThereFrom time to time, there have been various other proposals to regulate hydraulic fracturing at the federal level. Any new federal regulations that may be imposed onIn addition, there were proposals and positions taken by President Biden during his campaign regarding the use of hydraulic fracturing could resulton federal lands and waters. Further, on January 27, 2021, President Biden issued Executive Order 14008 entitled "Tackling the Climate Crisis at Home and Abroad," directing the Secretary of the Interior, to the extent consistent with applicable law and in additionalconsultation with other agencies and stakeholders, to, among other things, pause approval of new oil and natural gas leases on federal lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and disclosure requirements, additional operating and compliance costs and additional operating restrictions.leasing practices.

In addition to thesethe above-described federal regulations, some state and local governments have imposed, or have considered imposing, various conditions and restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; restrictions on access to, and usage of, water; disclosure of the chemical additives used in hydraulic fracturing operations; restrictions on the type of chemical additives that may be used in hydraulic fracturing operations; and restrictions on drilling or injection activities on certain lands lying within wilderness wetlands, ecologically or seismically sensitive areas, and other protected areas. Such federal, state and local permitting and disclosure requirements, and operating restrictions, and conditions or prohibition could lead to operational delays and increased operating and compliance costs and, moreover, could delay or effectively prevent the development of crude oil and natural gas from formations which would not be economically viable without the use of hydraulic fracturing.

Compliance with laws and regulations relating to hydraulic fracturing and other aspects of our operations increases EOG's overall cost of business, but has not had, to date, a material adverse effect on EOG's operations, financial condition or results of operations. In addition, 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 such laws and regulations. However, EOG is unable to predict (i) the timing, scope and effect of any currently proposed or future laws or regulations regarding hydraulic fracturing in the United States butor other aspects of our operations and (ii) the ultimate cost of compliance or the ultimate effect on EOG's operations, financial condition and results of operations relating to such future laws and regulations. The direct and indirect costs of such laws and regulations (if enacted) could materially and adversely affect EOG's operations, financial condition and results of operations.

Other Matters

Due to the many uncertainties associated with the world political and economic environment (for example, the actions of other crude oil exporting nations, including the Organization of Petroleum Exporting Countries)Countries, and the duration and impact of the ongoing COVID-19 pandemic), the global supply of, and demand for, crude oil, NGLs and natural gas and the availability of other energy supplies, the relative competitive relationships of the various energy sources in the view of consumers and other factors, EOG is unable to predict what changes may occur in the prices of crude oil and condensate, NGLs and natural gas in the future. For additional discussion regarding changes in crude oil and condensate, NGLs and natural gas prices and the risks that such changes may present to EOG, see ITEM 1A, Risk Factors.

BasedIncluding the impact of EOG's crude oil and NGL derivative contracts (exclusive of basis swaps) and based on EOG's tax position, EOG's price sensitivity (exclusive of basis swaps) in 20192021 for each $1.00 per barrel increase or decrease in wellhead crude oil and condensate price, combined with the estimated change in NGL price, is approximately $133$99 million for net income and $173$127 million for pretax cash flows from operating activities. BasedIncluding the impact of EOG's natural gas derivative contracts and based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 20192021 for which prices have not been determined under long-term marketing contracts, EOG's price sensitivity for each $0.10 per Mcf increase or decrease in wellhead natural gas price is approximately $29$31 million for net income and $37$40 million for pretax cash flows from operating activities. For a summary of EOG's financial commodity derivative contracts through February 19, 2019,18, 2021, see ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Commodity Derivative Transactions. For a summary of EOG's financial commodity derivative contracts for the twelve months ended December 31, 2018,2020, see Note 12 to Consolidated Financial Statements.

All of EOG's crude oil, NGL and natural gas activities are subject to the risks normally incident to the exploration for, and development, production and transportation of, crude oil, NGL and natural gas, including rig and well explosions, cratering, fires, loss of well control and leaks and spills, each of which could result in damage to life, property and/or the environment. EOG's operations are also subject to certain perils, including hurricanes, flooding and other adverse weather events. Moreover, EOG's activities are subject to governmental regulations as well as interruption or termination by governmental authorities based on environmental and other considerations. Losses and liabilities arising from such events could reduce EOG's revenues and increase costs to EOG to the extent not covered by insurance.

Insurance is maintained by EOG against some, but not all, of these risks in accordance with what EOG believes are customary industry practices and in amounts and at costs that EOG believes to be prudent and commercially practicable. Specifically, EOG maintains commercial general liability and excess liability coverage provided by third-party insurers for bodily injury or death claims resulting from an incident involving EOG's operations (subject to policy terms and conditions). Moreover, in the event an incident involving EOG's operations results in negative environmental effects, EOG maintains operators extra expense coverage provided by third-party insurers for obligations, expenses or claims that EOG may incur from such an incident, including obligations, expenses or claims in respect of seepage and pollution, cleanup and containment, evacuation expenses and control of the well (subject to policy terms and conditions). In the event of a well control incident resulting in negative environmental effects, such operators extra expense coverage would be EOG's primary coverage, with the commercial general liability and excess liability coverage referenced above also providing certain coverage to EOG. All of EOG's drilling activities are conducted on a contractual basis with independent drilling contractors and other third-party service contractors. The indemnification and other risk allocation provisions included in such contracts are negotiated on a contract-by-contract basis and are each based on the particular circumstances of the services being provided and the anticipated operations.

In addition to the above-described risks, EOG's operations outside the United States are subject to certain risks, including the risk of increases in taxes and governmental royalties, changes in laws and policies governing the operations of foreign-based companies, expropriation of assets, unilateral or forced renegotiation, modification or modificationnullification of existing contracts with governmental entities, currency restrictions and exchange rate fluctuations. Please refer to ITEM 1A, Risk Factors, for further discussion of the risks to which EOG is subject with respect to its operations outside the United States.

The current executive officers of EOG and their names and ages (as of February 26, 2019)25, 2021) are as follows:

William R. Thomas was elected Chairman of the Board and Chief Executive Officer effective January 2014. He was elected Senior Vice President and General Manager of EOG's Fort Worth, Texas, office in June 2004, Executive Vice President and General Manager of EOG's Fort Worth, Texas, office in February 2007 and Senior Executive Vice President, Exploitation in February 2011. He subsequently served as Senior Executive Vice President, Exploration from July 2011 to September 2011, as President from September 2011 to July 2013 and as President and Chief Executive Officer from July 2013 to December 2013. Mr. Thomas joined a predecessor of EOG in January 1979. Mr. Thomas is EOG's principal executive officer.

Lloyd W. Helms, Jr. was elected Chief Operating Officer in December 2017. Prior to that, he served as Executive Vice President, Exploration and Production from August 2013 to December 2017. He was elected Vice President, Engineering and Acquisitions in September 2006, Vice President and General Manager of EOG's Calgary, Alberta, Canada office in March 2008, and served as Executive Vice President, Operations from February 2012 to August 2013. Mr. Helms joined a predecessor of EOG in February 1981.

Kenneth W. Boedeker was elected Executive Vice President, Exploration and Production in December 2018.  He served as Vice President and General Manager of EOG's Denver, Colorado, office from October 2016 to December 2018, and as Vice President, Engineering and Acquisitions from July 2015 to October 2016.  Prior to that, Mr. Boedeker held technical and managerial positions of increasing responsibility across multiple offices and functional areas within EOG.  Mr. Boedeker joined EOG in July 1994.

Timothy K. Driggers was elected Executive Vice President and Chief Financial Officer in April 2016. Previously, Mr. Driggers served as Vice President and Chief Financial Officer from July 2007 to April 2016. He was elected Vice President and Controller of EOG in October 1999, was subsequently named Vice President, Accounting and Land Administration in October 2000 and Vice President and Chief Accounting Officer in August 2003. Mr. Driggers is EOG's principal financial officer. Mr. Driggers joined a predecessor of EOG in August 1995.

Michael P. Donaldson was elected Executive Vice President, General Counsel and Corporate Secretary in April 2016. Previously, Mr. Donaldson served as Vice President, General Counsel and Corporate Secretary from May 2012 to April 2016. He was elected Corporate Secretary in May 2008, and was appointed Deputy General Counsel and Corporate Secretary in July 2010. Mr. Donaldson joined EOG in September 2007.

Crude oil, natural gas and NGL prices are volatile, and a substantial and extended decline in commodity prices can have a material and adverse effect on us.

Prices for crude oil and natural gas (including prices for natural gas liquids (NGLs) and condensate) fluctuate widely. Among the interrelated factors that can or could cause these price fluctuations are:

The above-described factors and the volatility of commodity prices make it difficult to predict future crude oil, natural gasNGLs and NGL prices. For example, during the fourth quarter of 2018, there was a substantial decline in the prices for crude oil and NGLs, whereas natural gas prices increased significantly during such period.in 2021 and thereafter. As a result, there can be no assurance that the prices for crude oil, NGLs and/or natural gas and/or NGLs will sustain, orcontinue to increase from, or sustain, their current levels, andnor can there be any assurance that the prices for crude oil, NGLs and/or natural gas will not again decline.

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

Lower crude oil, NGLs and natural gas prices, however, reduce our cash flows and could also delay or impair our ability to consummate certain planned non-core asset sales and divestitures. Further, if the condition of the credit and capital markets materially declines, we might not be able to obtain financing on terms we consider acceptable, if at all. In addition, weakness and/or volatility in domestic and global financial markets or economic conditions or a depressed commodity price environment may increase the interest rates that lenders and commercial paper investors require us to pay or adversely affect our ability to finance our capital expenditures through equity or debt offerings or other borrowings.

The inability of our customers and other contractual counterparties to satisfy their obligations to us may have a material and adverse effect on us.

The inability of our customers and other contractual counterparties to pay amounts owed to us and to otherwise satisfy their contractual obligations to us may materially and adversely affect our business, financial condition, results of operations and cash flows.

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

We compete with major integrated oil and gas companies, government-affiliated oil and gas companies and other independent oil and gas companies for the acquisition of licenses and leases, properties and reserves and access to the facilities, equipment, materials, services and employees and other contract personnel (including geologists, geophysicists, engineers and other specialists) necessary to explore for, develop, produce, market and transport crude oil, NGLs and natural gas. In addition, certainCertain of our competitors have financial and other resources substantially greater than those we possess and have established strategic long-term positions or strong governmental relationships in countries or areas in which we may seek new or expanded entry. As a consequence, we may be at a competitive disadvantage in certain respects, such as in bidding for drilling rights or in accessing necessary services, facilities, equipment, materials and personnel. In addition, our larger competitors may have a competitive advantage when responding to factors that affect demand for crude oil, NGLs and natural gas, such as changing worldwide prices and levels of production and the cost and availability of alternative fuels. We also face competition to a lesser extent, from competing energy sources, such as alternativerenewable energy sources.

We operate in other countries and, assumptions that may turn outas a result, are subject to be inaccurate. Any significant inaccuraciescertain political, economic and other risks.

Our international operations may also be adversely affected by U.S. laws and policies affecting foreign trade and taxation, including tariffs or trade or other economic conditionssanctions; modifications to, or withdrawal from, international trade treaties; and improvements and other changesU.S. laws with respect to participation in geological, geophysical and engineering evaluation methods.

In November 2020, Joseph R. Biden Jr. was elected President of the United States. New or revised rules, regulations and policies may be issued, and new legislation may be proposed, during the current administration that could impact the oil and gas exploration and production industry. Such rules, regulations, policies and legislation may affect, among other things, (i) permitting for oil and gas drilling on federal lands, (ii) the leasing of federal lands for oil and gas development, (iii) the regulation of greenhouse gas (GHG) emissions and/or other climate change-related matters associated with oil and gas operations, (iv) the use of hydraulic fracturing on federal lands, (v) the calculation of royalty payments in respect of oil and gas production from federal lands and (vi) U.S. federal income tax laws applicable to oil and gas exploration and production companies. On January 27, 2021, President Biden issued Executive Order 14008 entitled “Tackling the Climate Crisis at Home and Abroad,” directing the Secretary of the Interior, to the extent consistent with applicable law and in turn, the trading priceconsultation with other agencies and stakeholders, to (i) pause approval of our common stock. For related discussion, see ITEM 2, Properties - Oil and Gas Exploration and Production - Properties and Reserves and Supplemental Information to Consolidated Financial Statements.

Further, such regulatory, legislative and policy changes may, among other things, the price we receive for the commodities we produce and, in turn, our cash flows and results of operations. For example, relatively warm temperatures during a winter season generally result in relatively lower demand for natural gas (as less natural gas is used to heat residencesadditional permitting and businesses)disclosure requirements, additional operating restrictions and/or the imposition of various conditions and as a result, lower prices for natural gas production.

Our hedging activitiesIn addition, the achievement of our current or future internal initiatives relating to the reduction of GHG emissions may preventincrease our costs, including requiring us from benefiting fully from increases into purchase emissions credits or offsets, or may impact or otherwise limit our ability to execute on our business plans.

Tax laws and regulations applicable to crude oil and natural gas pricesexploration and production companies may expose uschange over time, and such changes could materially and adversely affect our cash flows, results of operations and financial condition.

From time to other risks, including counterparty risk.

We are unable to fluctuating market prices. If we do not hedge additional production volumes for 2019predict the timing, scope and beyond, weeffect of any proposed or enacted tax law changes, but any such changes (if enacted) could materially and adversely affect our business, results of operations and financial condition. We will be impacted by commodity price declines, which may result in lower net cash provided by operating activities. In addition,continue to monitor and assess any proposed or enacted tax law changes to determine the impact on our hedging activities may expose us to the riskbusiness, results of operations and financial loss in certain circumstances, including instances in which the counterparties to our hedging contracts fail to perform under the contracts.condition and take appropriate actions, where necessary.

Federal legislation and related regulations regarding derivatives transactions could have a material and adverse impact on our hedging activities.

Outbreaks of communicable diseases can adversely affect our business, financial condition and prospectsresults of operations.

Global or national health concerns, including a widespread outbreak of contagious disease, can, among other impacts, negatively impact the global economy, reduce demand and pricing for future success dependcrude oil, natural gas and NGLs, lead to a significant extent upon the continued serviceoperational disruptions and performancelimit our ability to execute on our business plan, any of our management team.

There are still too many variables and uncertainties regarding the COVID-19 pandemic, including the duration and severity of the outbreak and the extent of travel restrictions and business closures imposed in affected countries, to fully assess the potential impact on our business, financial condition and results of operations.

Our business could be materially and adversely affected by security threats, including cybersecurity threats.threats, and other disruptions.

Terrorist activities and military and other actions could materially and adversely affect us.

Any such actions and the threat of such actions, including any resulting political instability or societal disruption, could materially and adversely affect us in unpredictable ways, including, but not limited to, the disruption of energy supplies and markets, the reduction of overall demand for crude oil and natural gas, increased volatility in crude oil and natural gas prices or the possibility that the facilities and other infrastructure on which we rely could be a direct target or an indirect casualty of an act of terrorism, and, in turn, could materially and adversely affect our business, financial condition and results of operations.

Oil and Gas Exploration and Production - Properties and Reserves

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 complex, subjective process of estimating underground accumulations of crude oil and condensate, NGLs and natural gas 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 by different engineers normally vary.  In addition, results of drilling, testing and production or fluctuations in commodity prices 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.  Further, the meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based.  For related discussion, see ITEM 1A, Risk Factors, and "Supplemental Information to Consolidated Financial Statements."

In general, the rate of production from crude oil and natural gas properties declines as reserves are produced.  Except to the extent EOG acquires additional properties containing proved reserves, conducts successful exploration, exploitation and development activities or, through engineering studies, identifies additional behind-pipe zones or secondary recovery reserves, the proved reserves of EOG will decline as reserves are produced.  The volumes to be generated from future activities of EOG areFuture production is, therefore, highly dependent upon the level of success in finding or acquiring additional reserves.of these activities.  For related discussion, see ITEM 1A, Risk Factors. EOG's estimates of reserves filed with other federal agencies are consistent with the information set forth in "Supplemental Information to Consolidated Financial Statements."

Many of December 31, 2018, there were no provedour oil and gas leases are large enough to accommodate more than one producing unit. Included in our undeveloped reservesacreage is non-producing acreage within such larger producing leases.

The agreement governing the acreage associated with our exploration program in Oman is set to expire in 2024, with certain provisions allowing for extension of such undeveloped acreage.term if commercial discoveries are found.