None.

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company.  See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

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 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 June 30, 2020: $29,4442022: $64,556 million.

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, 583,563,479587,723,622 shares outstanding as of February 12, 2021.16, 2023.

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.), Thethe Republic of Trinidad and Tobago (Trinidad), The People's Republic of China (China), the 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) filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange 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, 2020,2022, EOG's total estimated net proved reserves were 3,2204,238 million barrels of oil equivalent (MMBoe), of which 1,5141,661 million barrels (MMBbl) were crude oil and condensate reserves, 8131,145 MMBbl were NGLs reserves and 5,3608,591 billion cubic feet (Bcf), or 8931,432 MMBoe, were natural gas reserves (see "Supplemental Information to Consolidated Financial Statements").  At such date, approximately 98%99% 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.Trinidad.  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'sEOG operates under a consistent business and operational strategy is to maximizethat focuses predominantly on maximizing 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 delivermaximize long-term growth in 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 and 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, coupled with efficient and safe operations and robust environmental stewardship practices and performance, is integral 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, 2020,2022, on a crude oil equivalent basis, 48%40% of EOG's net proved reserves in the United States were crude oil and condensate, 26%27% were NGLs and 26%33% 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 2020wellhead volume statistics and anticipated 2021 plansnet well completions for the year ended December 31, 2022, total net acres at December 31, 2022, and expected net well completions planned for 2023 for certain areas of EOG's United States operations.

In the Delaware Basin Upper Wolfcamp play, EOG has approximately 226,000 net acres and completed 166196 net wells in 2020.2022. EOG continued its Upperto focus on co-development of multiple Wolfcamp development plan with well spacing as close as 500 feet intargets to maximize the crude oil portionvalue of the play and 880 feet in the combination crude oil and natural gas portion.acreage. 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 program were supported by optimized well spacing, enhanced well completions, precision drilling and continued cost reductions. Moving forward into 2021,2023, the Delaware Basin Wolfcamp play will continue to be a primary area of focus.

In the Bone Spring play, EOG has three main sub-plays: the First, Second and Third Bone Spring. In 2020,2022, EOG completed 56141 total net Bone Spring wells within the three sub-plays on its combined 289,000 net prospective acres.sub-plays. Of the three sub-plays, the Second Bone Spring had the majority of the activity in 20202022 with EOG completing 42106 net wells. The Bone Spring plays continueplay continues to be an integral part of EOG’sEOG's Delaware Basin plans and portfolio.

In the Leonard play, EOG holds approximately 160,000 net acres and maintainedexecuted its development plan with 1821 net wells completed in 2020. With a strategy2022. EOG continued co-development of developing deeper targets first whilemultiple Leonard zones simultaneously, collecting data from the shallow targets,and expects the Leonard play will progressivelyto become a more active part of EOG’s program.EOG's program in the next several years.

Activity in 20212023 will remain focused on the Delaware Basin Wolfcamp, Bone Spring, and Leonard plays, where EOG expects to complete approximately 275365 net wells.

Activity in the Rocky Mountain area in 20202022 was focused on the Wyoming Powder River Basin. In the Powder River Basin, EOG operated a one-rigtwo-rig program and completed 3527 net wells 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.realizations. In addition, in the DJ Basin, EOG operated one rig for a partial yeardrilled and completed 17two net wells in both the Codell formation and, the Niobrara formations. Activity in the DJ Basin is expected to be minimal in 2021 as development continues to shift to the Powder River Basin. In the Williston Basin, EOG completed 3two net wells in the Bakken and Three Forks.Forks formations. In 2020, production2023, activity in the Rocky Mountain area andRockies is expected to increase. EOG plans to complete approximately 10 net Williston Basin was significantly curtailed, primarily in the second quarter, in response to crude oil price declines, but has subsequently returned to normal levels. In 2021, activity will be focused on developmentwells, five net DJ Basin wells and 40 net wells in the 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.Basin.

Operations Outside the United States

EOG has operations offshore Trinidad in the China Sichuan Basin, Oman and in Canada and is making preparations to drill offshore Australia, as well as evaluating additional exploration, development and exploitation opportunities in these and other select international areas. In addition, EOG is in the process of exiting Block 36 and Block 49 in the Sultanate of Oman (Oman) and is executing an abandonment and reclamation program in Canada.

Several fields in the SECC, Modified U(a), Modified U(b) and 4(a) Blocks, Banyan Field and Sercan Area have been developed and are producing natural gas and crude oil and condensate.condensate, with the exception of the Modified U(b) Block in which EOG ceased to have an interest in the production of natural gas and crude oil and condensate in the fourth quarter of 2022.

In 2020,March 2021, EOG signed a farmout agreement with Heritage Petroleum Company Limited (Heritage), which allows EOG to earn a 65% working interest in a portion of the contract area (EOG Area) governed by the Trinidad Northern Area License. The EOG Area is located offshore the southwest coast of Trinidad. In 2022, EOG drilled one net exploratory well, which was determined to be unsuccessful.

In 2022, EOG's net production in Trinidad averaged approximately 180 MMcfd of natural gas and approximately 1.00.6 MBbld of crude oil and condensate. In 2020,2022, 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 addition,2023, EOG expects to continue its exploration program.complete three developmental and two exploratory wells in the Modified U(a) Block. Additionally, EOG expects to make progress on the design and construction of a platform and related facilities in the Mento Area.

In 2022, EOG continued preparing for the Sichuan Basin, Sichuan Province, China with its partner, PetroChina, under a production sharing contract. In 2020, EOG's net production averaged approximately 26 MMcfddrilling of natural gas. EOG continues to work with PetroChina to ensure uninterrupted production.an exploration well, the timing of which will depend on obtaining regulatory approvals and subsequent equipment availability.

Marketing

In 2020,2022, EOG continued its diversified approach to marketing its wellhead crude oil and condensate production. The majority of EOG's United States wellhead crude oil and condensate production was transported by pipeline to downstream markets with the remainder sold into local markets. Major U.S. sales areas accessed by EOG were at various locations along the U.S. Gulf Coast, including Houston and Corpus Christi, Texas; Cushing, Oklahoma; the Permian Basin and the Midwest. In 2020,2022, EOG also sold crude oil at the Houston Ship Channel and the Port of Corpus Christi for export to foreign destinations. In each case, the price received was based on market prices at that specific sales point or based on the price index applicable for that location. In 2021,2023, the pricing mechanism for such production is expected to remain the same. At December 31, 2020,2022, EOG was committed to deliver to multiple parties fixed quantities of crude oil of 87 MMBbls in 2021,2023, 7 MMBbls in 2024 and 1 MMBbls in 2025, all of which is expected to be deliveredsourced from future production of available reserves.

In 2020,2022, 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 NGLNGLs production for purity products received downstream, which were sold at prevailing market prices. In 2021,2023, such pricing mechanisms are expected to remain the same. In 2022, EOG also sold purity products at the Houston Ship Channel for export to foreign destinations. In each case, the price received was based on market prices at that specific sales point or based on the price index applicable for that location. In 2023, the pricing mechanism for such production is expected to remain the same. At December 31, 2022, EOG was not committed to deliver fixed quantities of NGLs in 2023.

In 2020,2022, consistent with its diversified marketing strategy, the majority of EOG's United States wellhead natural gas production was transported by pipeline to various locations, including Katy, Texas; East Texas; the Agua Dulce Hub in South Texas; the Cheyenne Hub in Weld County, Colorado; Southern California; and Chicago, Illinois. Remaining 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 2021,2023, 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, 2020,2022, EOG was committed to deliver to multiple parties fixed quantities of natural gas of 170 Bcf in 2021, 105 Bcf in 2022, 91347 Bcf in 2023, 94321 Bcf in 2024, 81277 Bcf in 2025, 297 Bcf in 2026, 293 Bcf in 2027 and 1,6093,540 Bcf thereafter, all of which is expected to be deliveredsourced from future production of available reserves.

In 2020, a majority of the wellhead2022, 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 or under a fixed price contract. In 2021,July 2022, EOG amended the natural gas volumes fromsales contract with the National Gas Company of Trinidad will be sold under a fixedand Tobago Limited and its subsidiary (NGC) to (i) extend the term to 2026 and (ii) effective September 1, 2020, provide for an increase in price contract ending in 2026.

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

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, 2020, 20192022, 2021 and 2018.2020. 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.

Human Capital Management

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 unregulated 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 U.S. Environmental Protection Agency's (U.S. EPA) rule requiring annual reporting of GHG emissions and, as discussed further below, is also subject to federal, state and local laws and regulations regarding hydraulic 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.operations or capital expenditures (for environmental control facilities or otherwise). 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 (i) the timing, scope and effect of any currently proposed or future laws or regulations regarding the environment and (ii) the ultimate cost of compliance or the ultimate effect on EOG's operations, financial condition, and results of operations.operations and capital expenditures relating to such future laws and regulations. The direct and indirect cost of such laws and regulations (if enacted) could materially and adversely affect EOG's operations, financial condition, results of operations and capital expenditures.

In addition to the U.S. EPA's rule requiring annual reporting of GHG emissions from covered facilities (which is amended from time to time and under which EOG reports), the U.S. EPA has adopted regulations for certain large sources regulating GHG emissions as pollutants under the federal Clean Air Act. Further, the U.S. EPA, in May 2016, issued regulations that require operators to reduce methane emissions and emissions of volatile organic compounds (VOC) 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,November 2021, the EPA proposed a rule to further reduce methane and VOC emissions from new and existing sources in the oil and natural gas sector and, in November 2022, the U.S. EPA issued a finalsupplemental proposal to expand its November 2021 proposed rule, that removed the transmissionincluding proposed regulation of additional sources of methane and storage segment from the 2016 new source performance standards, rescinded VOC emissions, such as abandoned and methane emissions standards for the transmission and storage segment and rescinded methane emissions standards for the production and processing segments. Various states and industry and environmental groups are separately challenging the U.S. EPA's 2016 standards and its September 2020 final rule. Notwithstanding the current court challenges, the U.S. EPA under the Biden Administration may reconsider the September 2020 final rule, which could result in more stringent methane emission rulemaking.unplugged wells.

At the international level, the U.S., in December 2015, 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. While the U.S. withdrew from the Paris Agreement on November 4, 2020, President Biden issued an executive order on January 20, 2021 recommitting2016, and which the United States to the Paris Agreement.formally rejoined in February 2021. The United States has established economy-wide targets of (i) reducing its net GHG emissions by 50-52 percent below 2005 levels by 2030 and (ii) achieving net zero GHG emissions economy-wide by no later than 2050. In 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.

EOG is unable to predict the timing, scope and effect of any currently proposed or future investigations, laws, regulations, treaties or policies regarding climate change and GHG emissions (including any laws and regulations that may be enacted in the U.S. by the new administration)), but the direct and indirect costs of such developmentsinvestigations, laws, regulations, treaties or policies (if enacted, issued or applied) could materially and adversely affect EOG's operations, financial condition, and results of operations.operations and capital expenditures. The potential increase in the costs of our operations could include costs to operate and maintain our facilities, install new emissions controls on our facilities, acquire allowances or credits to cover our GHG emissions, pay taxes or fees related to our GHG emissions, or administer and manage a GHG emissions program. In addition, changes in regulatory policies that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to GHG emissions, or restrictions on their use, could also adversely affect market demand for, and in turn the prices we receive for our production of, crude oil, NGLs and natural gas. Further, the increasing attention to global climate change risks has created the potential for a greater likelihood of governmental investigations and private and public litigation, which could increase our costs or otherwise adversely affect our business. See ITEM 1A, Risk Factors, for additional discussion regarding climate change-related developments.

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,November 2021, the U.S. EPA proposed a rule to further reduce methane and VOC emissions from new and existing sources in the oil and natural gas sector and, in November 2022, the U.S. EPA issued amendmentsa supplemental proposal to the 2012further strengthen 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 addition to the 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, operating restrictions, conditions or prohibitionprohibitions 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.operations or capital expenditures (for environmental control facilities or otherwise). 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 or 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 and capital expenditures 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.operations and capital expenditures.

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, and the duration and impact of the ongoing COVID-19 pandemic)Countries), 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, the potential impacts on EOG and the risks that such changes may present to EOG, see ITEM 1A, Risk Factors.

Including the impact of EOG's crude oil and NGLfinancial derivative contracts (exclusive of basis swaps) and based on EOG's tax position, EOG's price sensitivity in 20212023 for each $1.00 per barrel increase or decrease in wellhead crude oil and condensate price, combined with the estimated change in NGLNGLs price, is approximately $99$137 million for net income and $127$175 million for pretax cash flows from operating activities. Including the impact of EOG's natural gas financial derivative contracts and based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 20212023 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 $31$35 million for net income and $40$44 million for pretax cash flows from operating activities. For a summary of EOG's financial commodity derivative contracts through February 18, 2021,16, 2023, see ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Financial Commodity Derivative Transactions. For a summary of EOG's financial commodity derivative contracts for the twelve monthsyear ended December 31, 2020,2022, see Note 12 to Consolidated Financial Statements.

All of EOG's crude oil, NGLNGLs and natural gas activities are subject to the risks normally incident to the exploration for, and development, production and transportation of, crude oil, NGLNGLs 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, tropical storms, flooding, winter storms 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 anfor any incident involving EOG's operations which 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 nullification 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.

Information About Our Executive Officers

The current executive officers of EOG and their names and ages (as of February 25, 2021)23, 2023) are as follows:

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.

Risks Related to our Financial Condition, Results of Operations and Cash Flows

Crude oil, NGLs and 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 crude oil, NGLs and natural gas prices in 20212023 and thereafter. As a result, there can be no assurance that the prices for crude oil, NGLs and/or natural gas will continue tosustain, or increase from, or sustain, their current levels, nor can there be any assurance that the prices for crude oil, NGLs and/or natural gas will not again decline.

Beginning in the second half of 2021 and continuing throughout 2022, we, similar to other companies in our industry, experienced inflationary pressures on our operating costs and capital expenditures - namely the costs of fuel, steel (i.e., wellbore tubulars and facilities manufactured using steel), labor and drilling and completion services. Such inflationary pressures on our operating and capital costs, which we currently expect to continue in 2023, have impacted our cash flows and results of operationsoperations. We have undertaken, and plan to continue with, certain initiatives and actions (such as agreements with service providers to secure the costs and availability of services) to mitigate such inflationary pressures. However, there can be no assurance that such efforts will be adversely affected and we may be limited in our ability to maintain our current leveloffset, largely or at all, the impacts of dividendsany future inflationary pressures on our common stock.In addition, we may be required to incur additional impairment charges and/or make additional downward adjustments tooperating costs and capital expenditures and, in turn, our proved reserve estimates.As a result, our financial conditioncash flows and results of operationsoperations. For additional discussion, see ITEM 7, Management's Discussion and the trading priceAnalysis of our common stock may be materiallyFinancial Condition and adversely affected.Results of Operations – Overview – Recent Developments.

Lower crude oil, NGLs and natural gas prices, however, reduce our cash flows and could also delay or impair our ability to consummate certainany 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 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.

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

Specifically, we often are uncertain as to the future cost or timing of drilling, completing and operating wells, and our drilling operations and those of our third-party operators may be curtailed, delayed or canceled, the cost of such operations may increase and/or our results of operations and cash flows from such operations may be impacted, as a result of a variety of factors, including:

Our crude oil, NGLs and natural gas operations and supporting activities and operations are subject to all of the risks associated with exploring and drilling for, and producing, gathering, processing, compressing, storing, transporting and transporting,exporting crude oil, NGLs and natural gas, including the risks of:

If any of these events occur, we could incur losses, liabilities and other additional costs as a result of:

Any significant change in market or other conditions affecting gathering, processing, compression, storage, transportation, refining and export facilities and equipment or the availability of these facilities and equipment, including due to our failure or inability to obtain access to these facilities and equipment on terms acceptable to us or at all, could materially and adversely affect our business and, in turn, our financial condition and results of operations.

In addition, there are numerous uncertainties inherent in estimating quantities of crude oil, NGLs and natural gas reserves (as discussed further above), actual future production rates and associated costs with respect to acquired properties. Actual reserves, production rates and costs may vary substantially from those assumed in our estimates. In addition, an acquisition may have a material and adverse effect on our business and results of operations, particularly during the periods in which the operations of the acquired properties are being integrated into our ongoing operations or if we are unable to effectively integrate the acquired properties into our ongoing operations.

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 personnel (including geologists, geophysicists, engineers and other specialists) necessary to explore for, develop, produce, market and transport crude oil, NGLs and natural gas. Certain 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 from competing energy sources, such as renewable energy sources.

Risks Related to Our International Operations

We operate in other countries and, as a result, are subject to certain 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 sanctions; modifications to, or withdrawal from, international trade treaties; and U.S. laws with respect to participation in boycotts that are not supported by the U.S. government. The realization of any of these factors could materially and adversely affect our business, financial condition and results of operations.

Our business could be materially and adversely affected by security threats, including cybersecurity 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, NGLs and natural gas, increased volatility in crude oil, NGLs 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."

Many of our oil and gas leases are large enough to accommodate more than one producing unit. Included in our undeveloped acreage is non-producing acreage within such larger producing leases.

The agreement governing the acreage associated with our exploration program in Omanoffshore Australia is set to expire in 2024,at various dates through 2025 depending on EOG's decision to move forward with certain provisions allowing forits defined work program or unless EOG is either granted a production license or an extension of such term if commercial discoveries are found.the permit. In the fourth quarter of 2022, EOG applied for a one-year extension of the permit.

The following tables set forth the results of the net crude oil and natural gas wells completed for the years ended December 31, 2020, 20192022, 2021 and 2018: