EDGAR 10-K Filing

Company CIK: 821189
Filing Year: 2021
Filename: 821189_10-K_2021_0000821189-21-000017.json

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ITEM 1. BUSINESS
ITEM 1. Business
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), 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, EOG's total estimated net proved reserves were 3,220 million barrels of oil equivalent (MMBoe), of which 1,514 million barrels (MMBbl) were crude oil and condensate reserves, 813 MMBbl were NGLs reserves and 5,360 billion cubic feet (Bcf), or 893 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 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, 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, on a crude oil equivalent basis, 48% of EOG's net proved reserves in the United States were crude oil and condensate, 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 2020 and anticipated 2021 plans for certain areas of EOG's United States operations.
2020 2021
Area of Operation Crude Oil & Condensate Volumes
(MBbld) (1)
Natural Gas Liquids Volumes
(MBbld) (1)
Natural Gas Volumes
(MMcfd) (1)
Total Net Acres (in thousands) Net Well Completions Expected Net Well Completions
South Texas 162 33 281 1,138 223 160
Delaware Basin 183 75 460 404 247 275
Rocky Mountain 49 14 159 1,167 56 50
Mid-Continent 10 14 87 310 15 <5
Other Areas 4 - 53 851 7 15
Total 408 136 1,040 3,870 548 ~500
(1)Thousand barrels per day or million cubic feet per day, as applicable.
The South Texas area includes our Eagle Ford play and our newly announced Dorado gas play. EOG holds approximately 516,000 total net acres in the prolific oil window of the Eagle Ford and approximately 163,000 net acres in the Dorado prospect area. During the second and third quarters of 2020, EOG significantly curtailed its Eagle Ford oil production due to low crude oil prices; operations in the Eagle Ford returned to normal by the end of the third quarter of 2020. In the Dorado play, with the onset of the pandemic and resulting market downturn, EOG elected to defer its 2020 drilling program and instead focus on gathering and analyzing data regarding the production performance of its 2019 Dorado drilling program. In 2020, EOG completed 213 net Eagle Ford wells and, late in 2020, acquired and completed one net Dorado well to further delineate the play. In 2021, EOG expects to complete approximately 145 net Eagle Ford wells and to drill and complete approximately 15 net Dorado wells.
In the Delaware Basin, EOG completed 247 net wells during 2020, primarily in the Delaware Basin Wolfcamp, Bone Spring and Leonard plays. The Delaware Basin consists of approximately 4,800 feet of oil rich stacked pay potential offering EOG multiple co-development opportunities throughout its 404,000 total net acreage position.
In the Delaware Basin Upper Wolfcamp play, EOG has approximately 226,000 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 program were supported by optimized well spacing, enhanced well completions, precision drilling and continued cost reductions. Moving forward into 2021, 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, 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 had the majority of the activity in 2020 with EOG completing 42 net wells. The Bone Spring plays continue to be an integral part of EOG’s Delaware Basin plans and portfolio.
In the Leonard play, EOG holds approximately 160,000 net acres and maintained its development plan with 18 net wells completed in 2020. With a strategy of developing deeper targets first while simultaneously collecting data from the shallow targets, the Leonard play will progressively become a more active part of EOG’s program.
Activity in 2021 will remain focused on the Delaware Basin Wolfcamp, Bone Spring, and Leonard plays, where EOG expects to complete approximately 275 net wells.
Activity in the Rocky Mountain area in 2020 was focused on the Wyoming Powder River Basin. In the Powder River Basin, EOG operated a one-rig program and completed 35 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. 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. 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 3 net wells in the Bakken and Three Forks. In 2020, production in the Rocky Mountain area and 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 development 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.
In the Mid-Continent area, EOG continued its development of the Woodford Oil Window play with 15 net wells completed during 2020. EOG holds approximately 37,000 net acres in the play and plans to have minimal activity in 2021.
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.
Trinidad. EOG, through its subsidiaries, including EOG Resources Trinidad Limited, holds interests in (i) the exploration and production licenses covering the South East Coast Consortium (SECC) Block, Pelican and Banyan Fields, Sercan Area and each of their related facilities and the Ska, Mento, Reggae and deep Teak, Saaman and Poui Areas, all of which are offshore Trinidad; and (ii) a production sharing contract with the Government of Trinidad and Tobago for each of the Modified U(a), Modified U(b) and 4(a) Blocks.
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.
In 2020, EOG's net production averaged approximately 180 MMcfd of natural gas and approximately 1.0 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 2021, EOG expects to focus on the design and fabrication of the platform and related infrastructure for the previously announced discovery made in the Modified U(a) Block. In addition, EOG expects to continue its exploration program.
China. Since 2008, EOG has been developing the Baijaochang Field in the Chuan Zhong Block exploration area in the Sichuan Basin, Sichuan Province, China with its partner, PetroChina, under a production sharing contract. In 2020, EOG's net production averaged approximately 26 MMcfd of natural gas. EOG continues to work with PetroChina to ensure uninterrupted production.
Oman. In September 2020, EOG reached an agreement with APEX Oman (Block 36) Inc. to acquire its entire interest in Block 36 in Oman. The Royal Decree was issued on October 28, 2020 at which point EOG became the operator and held all rights under the Exploration and Production Sharing Agreement for Block 36. Additionally, in December 2020 the Ministry of Energy and Minerals for Oman approved the assignment of Block 49 to EOG pursuant to the terms of the farm-in agreement with Tethys Oil Montasar Limited. In accordance with the terms of the farm-in agreement EOG participated in the drilling of an exploratory well which was in progress at December 31, 2020. In 2021, EOG expects to drill two net exploration wells in Block 36.
Canada. EOG maintains approximately 47,000 net acres in the Horn River area in Northeast British Columbia. In March 2020, EOG began the process of exiting its Canada operations.
Marketing
In 2020, 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, 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, the pricing mechanism for such production is expected to remain the same. At December 31, 2020, EOG was committed to deliver to multiple parties fixed quantities of crude oil of 8 MMBbls in 2021, all of which is expected to be delivered from future production of available reserves.
In 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 2021, such pricing mechanisms are expected to remain the same.
In 2020, 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, 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, EOG was committed to deliver to multiple parties fixed quantities of natural gas of 170 Bcf in 2021, 105 Bcf in 2022, 91 Bcf in 2023, 94 Bcf in 2024, 81 Bcf in 2025 and 1,609 Bcf thereafter, all of which is expected to be delivered from future production of available reserves.
In 2020, a 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 or under a fixed price contract. In 2021, natural gas volumes from Trinidad will be sold under a fixed price contract ending in 2026.
In 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 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 2020, three purchasers each accounted for more than 10% of EOG's total wellhead crude oil and condensate, NGLs and natural gas revenues and gathering, processing and marketing revenues. The three purchasers are in the crude oil refining industry. EOG does not believe that the loss of any single purchaser would have a materially 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, 2020, 2019 and 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.
Year Ended December 31 2020 2019 2018
Crude Oil and Condensate Volumes (MMBbl) (1)
United States:
Eagle Ford 54.6 68.3 62.4
Delaware Basin 67.0 63.4 46.3
Other 27.8 34.6 35.4
United States 149.4 166.3 144.1
Trinidad 0.4 0.2 0.3
Other International (2)
- 0.1 1.6
Total 149.8 166.6 146.0
Natural Gas Liquids Volumes (MMBbl) (1)
United States:
Eagle Ford 9.7 10.7 11.4
Delaware Basin 27.7 23.5 15.8
Other 12.4 14.7 15.3
United States 49.8 48.9 42.5
Other International (2)
- - -
Total 49.8 48.9 42.5
Natural Gas Volumes (Bcf) (1)
United States:
Eagle Ford 53 53 58
Delaware Basin 168 147 110
Other 160 190 169
United States 381 390 337
Trinidad 66 95 97
Other International (2)
11 14 11
Total 458 499 445
Crude Oil Equivalent Volumes (MMBoe) (3)
United States:
Eagle Ford 73.1 87.8 83.5
Delaware Basin 122.7 111.4 80.3
Other 66.9 81.0 78.8
United States 262.7 280.2 242.6
Trinidad 11.4 16.0 16.5
Other International (2)
1.8 2.4 3.4
Total 275.9 298.6 262.5
Year Ended December 31 2020 2019 2018
Average Crude Oil and Condensate Prices ($/Bbl) (4)
United States $ 38.65 $ 57.74 $ 65.16
Trinidad 30.20 47.16 57.26
Other International (2)
43.08 57.40 71.45
Composite 38.63 57.72 65.21
Average Natural Gas Liquids Prices ($/Bbl) (4)
United States $ 13.41 $ 16.03 $ 26.60
Other International (2)
- - -
Composite 13.41 16.03 26.60
Average Natural Gas Prices ($/Mcf) (4)
United States $ 1.61 $ 2.22 $ 2.88
Trinidad 2.57 2.72 2.94
Other International (2)
4.66 4.44 4.08
Composite 1.83 2.38 2.92
(1)Million barrels or billion cubic feet, as applicable.
(2)Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.
(3)Million barrels of oil equivalent; includes crude oil and condensate, NGLs and natural gas.
(4)Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments (see Note 12 to Consolidated Financial Statements).
Human Capital Management
As of December 31, 2020, EOG employed approximately 2,900 persons, including foreign national employees. EOG's approach to human capital management includes oversight by the Board of Directors and Compensation Committee and focuses on various areas, including the following:
Culture; Recruiting; Retention. EOG's unique culture is key to its sustainable success. By providing employees with a quality environment in which to work, and by maintaining a consistent college recruiting and internship program, EOG is able to attract and retain some of the industry's best and brightest. To help assess the effectiveness of its approach to human capital management, EOG conducts an annual employee engagement survey. Based on the results of the survey, EOG has received "top workplace" recognition in various office locations.
Compensation, Benefits, Health & Wellness. EOG places a high level of importance on attracting and retaining top talent, by providing competitive salaries, bonuses and a subsidized, comprehensive benefits package. EOG also offers a holistic wellness program, a matching gifts program, a flexible work schedule, paid family care leave, paid leave for illness or injury and an employee assistance program to support the mental well-being of employees and their dependents. In addition, with new-hire stock grants and an annual stock grant program, every employee is a participant in EOG's success.
In 2020, in response to the COVID-19 pandemic, EOG focused on keeping its employees and their families safe, including providing technology and support to employees enabling them to work productively from home. In addition, at its offices and work sites, EOG has instituted social distancing practices and protocols and has provided masks, hand sanitizer and additional cleaning.
Training and Development. EOG provides training in leadership, management skills, communication, team effectiveness, technical skills and development and use of EOG systems and applications. EOG's leadership training is focused on providing continuity of leadership at EOG by developing the skills needed to lead a multi-disciplined, diverse and decentralized workforce. In addition, EOG holds several internal technical conferences each year designed to share best practices and technical advances across the company, including safety and environmental topics. EOG also offers its employees a tuition reimbursement program as well as reimbursement for the cost of professional certification.
Diversity and Inclusion. Gender, racial, ethnic and cultural diversity, and diversity in background and experience, leads to diversity of thought, which is a tremendous asset and is actively embraced by EOG. As reflected in its Code of Business Conduct and Ethics for Directors, Officers and Employees, EOG is committed to providing equal opportunity in all aspects of employment and to hiring, evaluating and promoting employees based on skills and performance. EOG's collaborative culture fosters inclusiveness at all levels of the company. Further, EOG focuses on developing its employees, including those with diverse backgrounds, to allow for career opportunities, including promotion into supervisory and management positions.
Safety. EOG's safety management programs and processes are centered on a performance-based philosophy, pursuant to which EOG sets safety expectations and provides a framework within which management can achieve and assess safety performance in a systematic way. EOG's safety performance is also considered in evaluating employee performance and compensation. EOG provides initial, periodic and refresher safety training to employees as well as to contractors and others who may work at or visit EOG's facilities. These training programs address various topics, including operating procedures, safe work practices and emergency and incident response procedures.
Competition
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 personnel (including geologists, geophysicists, engineers and other specialists) required to explore for, develop, produce, market and transport crude oil, NGLs and natural gas. Certain 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 from competing energy sources, such as renewable energy sources. See ITEM 1A, Risk Factors.
Regulation
2020 Election. 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. See the below discussion and ITEM 1A, Risk Factors, for additional information.
United States Regulation of Crude Oil and Natural Gas Production. Crude oil and natural gas production operations are subject to various types of regulation, including regulation by federal and state agencies.
United States legislation affecting the oil and gas industry is under constant review for amendment or expansion. In addition, numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations applicable to the oil and gas industry. Such rules and regulations, among other things, require permits for the drilling of wells, regulate the spacing of wells, prevent the waste of natural gas through restrictions on flaring, require surety bonds for various exploration and production operations and regulate the calculation and disbursement of royalty payments (for federal and state leases), production taxes and ad valorem taxes.
A portion of EOG's oil and gas leases in New Mexico, North Dakota, Utah, Wyoming and the Gulf of Mexico, as well as in other areas, are granted by the federal government and administered by the Bureau of Land Management (BLM) and/or the Bureau of Indian Affairs (BIA) or, in the case of offshore leases (which, for EOG, are de minimis), by the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE), all federal agencies. Operations conducted by EOG on federal oil and gas leases must comply with numerous additional statutory and regulatory restrictions and, in the case of leases relating to tribal lands, certain tribal environmental and permitting requirements and employment rights regulations. In addition, the U.S. Department of the Interior (via various of its agencies, including the BLM, the BIA and the Office of Natural Resources Revenue) has certain authority over our calculation and payment of royalties, bonuses, fines, penalties, assessments and other revenues related to our federal and tribal oil and gas leases.
BLM, BIA and BOEM leases contain relatively standardized terms requiring compliance with detailed regulations and, in the case of offshore leases, orders pursuant to the Outer Continental Shelf Lands Act (which are subject to change by the BOEM or BSEE). Under certain circumstances, the BLM, BIA, BOEM or BSEE (as applicable) may require operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect EOG's interests on federal lands. 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, 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 leasing practices. Any limitation or ban on permitting for oil and gas exploration and production activities on federal lands could have a material and adverse effect on EOG's operations, financial condition and results of operations.
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.
EOG owns certain gathering and/or processing facilities in the Permian Basin in West Texas and New Mexico, the Fort Worth Basin Barnett Shale in North Texas, the Williston Basin Bakken and Three Forks plays in North Dakota, and the Eagle Ford in South Texas. State regulation of gathering and processing facilities generally includes various safety, environmental and, in some circumstances, nondiscrimination requirements with respect to the provision of gathering and processing services, but does not generally entail rate regulation. EOG's gathering and processing operations could be materially and adversely affected should they be subject in the future to the application of state or federal regulation of rates and services.
EOG's gathering and processing operations also may be, or become, subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of such facilities. Additional rules and legislation pertaining to these matters are considered and/or adopted from time to time. Although EOG cannot predict what effect, if any, such legislation might have on its operations and financial condition, EOG could be required to incur additional capital expenditures and increased compliance and operating costs depending on the nature and extent of such future legislative and regulatory changes.
EOG also owns crude oil rail loading facilities in North Dakota and crude oil truck unloading facilities in certain of its U.S. plays. Regulation of such facilities is conducted at the state and federal levels and generally includes various safety, environmental, permitting and packaging/labeling requirements. Additional regulation pertaining to these matters is considered and/or adopted from time to time. Although EOG cannot predict what effect, if any, any such new regulations might have on its crude-by-rail assets and the transportation of its crude oil production by truck, EOG could be required to incur additional capital expenditures and increased compliance and operating costs depending on the nature and extent of such future regulatory changes. EOG did not transport any crude oil by rail during 2020.
Proposals and proceedings that might affect the oil and gas industry are considered from time to time by Congress, the state legislatures, the FERC and other federal, state and local regulatory commissions, agencies, councils and courts. EOG cannot predict when or whether any such proposals or proceedings may become effective. It should also be noted that the oil and gas industry historically has been very heavily regulated; therefore, there is no assurance that the approach currently being followed by such legislative bodies and regulatory commissions, agencies, councils and courts will remain unchanged.
Environmental Regulation Generally - United States. EOG is subject to various federal, state and local laws and regulations covering the discharge of materials into the environment or otherwise relating to the protection of the environment. These laws and regulations affect EOG's operations and costs as a result of their effect on crude oil and natural gas exploration, development and production operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, including the assessment of monetary penalties, the imposition of investigatory and remedial obligations, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and the issuance of orders enjoining future operations or imposing additional compliance requirements.
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. 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.
Climate Change - United States. Local, state, federal and international regulatory bodies have been increasingly focused on GHG emissions and climate change issues in recent years. In addition to the U.S. EPA's rule requiring annual reporting of GHG emissions, 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, the U.S. EPA issued a final rule that removed the transmission and storage segment from the 2016 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. 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.
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 recommitting the United States to the Paris Agreement. 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 developments (if enacted, issued or applied) could materially and adversely affect EOG's operations, financial condition and results of operations. 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.
Regulation of Hydraulic Fracturing and Other Operations - United States. Substantially all of the onshore crude oil and natural gas wells drilled by EOG are completed and stimulated through the use of hydraulic fracturing. Hydraulic fracturing technology, which has been used by the oil and gas industry for more than 60 years and is constantly being enhanced, enables EOG to produce crude oil and natural gas that otherwise would not be recovered. Specifically, hydraulic fracturing is a process in which pressurized fluid is pumped into underground formations to create tiny fractures or spaces that allow crude oil and natural gas to flow from the reservoir into the well so that it can be brought to the surface. Hydraulic fracturing generally takes place thousands of feet underground, a considerable distance below any drinking water aquifers, and there are impermeable layers of rock between the area fractured and the water aquifers. The makeup of the fluid used in the hydraulic fracturing process typically includes water and sand, and less than 1% of highly diluted chemical additives; lists of the chemical additives used in fracturing fluids are available to the public via internet websites and in other publications sponsored by industry trade associations and through state agencies in those states that require the reporting of the components of fracturing fluids. While the majority of the sand remains underground to hold open the fractures, a significant amount of the water and chemical additives flow back and are then either reused or safely disposed of at sites that are approved and permitted by the appropriate regulatory authorities. EOG periodically conducts regulatory assessments of these disposal facilities to monitor compliance with applicable regulations.
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.
From time to time, there have been various other proposals to regulate hydraulic fracturing at the federal level. In addition, there were proposals and positions taken by President Biden during his campaign regarding the use of hydraulic fracturing on 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 consultation 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 leasing practices.
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 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 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 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 International Regulation. EOG's exploration and production operations outside the United States are subject to various types of regulations, including environmental regulations, imposed by the respective governments of the countries in which EOG's operations are conducted, and may affect EOG's operations and costs of compliance within those countries. EOG currently has operations in Trinidad, China and Canada, and an exploration program in Oman. EOG is unable to predict the timing, scope and effect of any currently proposed or future laws, regulations or treaties, including those regarding climate change and hydraulic fracturing, but the direct and indirect costs of such laws, regulations and treaties (if enacted) could materially and adversely affect EOG's operations, financial condition and results of operations. EOG will continue to review the risks to its business and operations outside the United States associated with all environmental matters, including climate change and hydraulic fracturing regulation. In addition, EOG will continue to monitor and assess any new policies, legislation, regulations and treaties in the areas outside the United States where it operates to determine the impact on its operations and take appropriate actions, where necessary.
Other Regulation. EOG has sand mining and processing operations in Texas and Wisconsin, which support EOG's exploration and development operations. EOG's sand mining operations are subject to regulation by the federal Mine Safety and Health Administration (in respect of safety and health matters) and by state agencies (in respect of air permitting and other environmental matters). The information concerning mine safety violations and other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95 to this report.
For additional discussion regarding the regulatory-related risks to which EOG's operations, financial condition and results of operations are or may be subject, see ITEM 1A, Risk Factors.
Other Matters
Energy Prices. EOG is a crude oil and natural gas producer and is impacted by changes in the prices for crude oil and condensate, NGLs and natural gas. During the last three years, average United States commodity prices have fluctuated, at times rather dramatically. Average crude oil and condensate prices received by EOG for production in the United States decreased 33% in 2020 and 11% in 2019 and increased 28% in 2018, each as compared to the immediately preceding year. EOG's quarterly price realizations ranged from $20.40 per barrel to $46.97 per barrel in 2020. Average NGL prices received by EOG for production in the United States decreased 16% in 2020 and 40% in 2019 and increased 18% in 2018, each as compared to the immediately preceding year. These fluctuations resulted in a 27% decrease in the average wellhead natural gas price received by EOG for production in the United States in 2020, a 23% decrease in 2019, and a 31% increase (inclusive of a positive revenue adjustment of $0.44 per Mcf related to the adoption of Accounting Standards Update 2014-09) in 2018, each as compared to the immediately preceding year.
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), 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.
Including 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 in 2021 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 $99 million for net income and $127 million for pretax cash flows from operating activities. Including 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 2021 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 million for net income and $40 million for pretax cash flows from operating activities. For a summary of EOG's financial commodity derivative contracts through February 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, 2020, see Note 12 to Consolidated Financial Statements.
Risk Management. EOG engages in price risk management activities from time to time. These activities are intended to manage EOG's exposure to fluctuations in prices of crude oil, NGLs and natural gas. EOG utilizes financial commodity derivative instruments, primarily price swap, option, swaption, collar and basis swap contracts, as a means to manage this price risk. See Note 12 to Consolidated Financial Statements. For a summary of EOG's financial commodity derivative contracts through February 18, 2021, see ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Commodity Derivative Transactions.
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 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) are as follows:
Name Age Position
William R. Thomas 68 Chairman of the Board and Chief Executive Officer
Lloyd W. Helms, Jr. 63 Chief Operating Officer
Ezra Y. Yacob 44 President
Kenneth W. Boedeker 58 Executive Vice President, Exploration and Production
Timothy K. Driggers 59 Executive Vice President and Chief Financial Officer
Michael P. Donaldson 58 Executive Vice President, General Counsel and Corporate Secretary
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.
Ezra Y. Yacob was elected President effective January 2021. Prior to that, he served as Executive Vice President, Exploration and Production from December 2017 to January 2021 and as Vice President and General Manager of EOG's Midland, Texas, office from May 2014 to December 2017. He also previously served as Manager, Division Exploration in EOG's Fort Worth, Texas, and Midland, Texas, offices from March 2012 to May 2014 as well as in various geoscience and leadership positions. Mr. Yacob joined EOG in August 2005.
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.

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ITEM 1A. RISK FACTORS
ITEM 1A. Risk Factors
Our business and operations are subject to many risks. The risks described below may not be the only risks we face, as our business and operations may also be subject to risks that we do not yet know of, or that we currently believe are immaterial. If any of the events or circumstances described below actually occurs, our business, financial condition, results of operations or cash flows could be materially and adversely affected and the trading price of our common stock could decline. The following risk factors should be read in conjunction with the other information contained herein, including the consolidated financial statements and the related notes. Unless the context requires otherwise, “we,” “us,” “our” and “EOG” refer to EOG Resources, Inc. and its subsidiaries.
Risks Related to our Financial Condition, Results of Operations and Cash Flows
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:
•domestic and worldwide supplies of crude oil, NGLs and natural gas;
•domestic and international drilling activity;
•the actions of other crude oil producing and exporting nations, including the Organization of Petroleum Exporting Countries;
•consumer and industrial/commercial demand for crude oil, natural gas and NGLs;
•worldwide economic conditions, geopolitical factors and political conditions, including, but not limited to, the imposition of tariffs or trade or other economic sanctions, political instability or armed conflict in oil and gas producing regions;
•the duration and economic and financial impact of epidemics, pandemics or other public health issues, such as the ongoing COVID-19 pandemic;
•the availability, proximity and capacity of appropriate transportation, gathering, processing, compression, storage and refining facilities;
•the price and availability of, and demand for, competing energy sources, including alternative energy sources;
•the effect of worldwide energy conservation measures, alternative fuel requirements and climate change-related initiatives;
•the nature and extent of governmental regulation, including any changes or other actions which may result from the recent elections in the United States of America (United States or U.S.) and change in administration, and including environmental and other climate change-related regulation, regulation of derivatives transactions and hedging activities, tax laws and regulations and laws and regulations with respect to the import and export of crude oil, NGLs, and natural gas and related commodities;
•the level and effect of trading in commodity futures markets, including trading by commodity price speculators and others; and
•weather conditions and changes in weather patterns.
In the first half of 2020, the prices for crude oil, NGLs and natural gas declined substantially as a result of the economic downturn and overall reduction of demand prompted by the COVID-19 pandemic and the oversupply of crude oil from certain foreign oil-exporting countries. In the second half of 2020, (i) the prices for NGLs and natural gas recovered to pre-pandemic levels and (ii) the prices for crude oil increased but remain significantly below pre-pandemic levels.
The above-described factors and the volatility of commodity prices make it difficult to predict crude oil, NGLs and natural gas prices in 2021 and thereafter. As a result, there can be no assurance that the prices for crude oil, NGLs and/or natural gas will continue to 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.
Our cash flows and results of operations depend to a great extent on prevailing commodity prices. Accordingly, substantial and extended declines in commodity prices can materially and adversely affect the amount of cash flows we have available for our capital expenditures and operating expenses, the terms on which we can access the credit and capital markets and our results of operations.
Lower commodity prices can also reduce the amount of crude oil, NGLs and natural gas that we can produce economically. Substantial and extended declines in the prices of these commodities can render uneconomic a portion of our exploration, development and exploitation projects, resulting in our having to make downward adjustments to our estimated proved reserves and also possibly shut in or plug and abandon certain wells. In addition, significant prolonged decreases in commodity prices may cause the expected future cash flows from our properties to fall below their respective net book values, which would require us to write down the value of our properties. Such reserve write-downs and asset impairments can materially and adversely affect our results of operations and financial position and, in turn, the trading price of our common stock.
In fact, the substantial declines in crude oil, NGLs and natural gas prices that occurred in the first half of 2020 materially and adversely affected the amount of cash flows we had available for our 2020 capital expenditures and operating expenses, our results of operations during the first half of 2020 and the trading price of our common stock. Such commodity price declines also resulted in aggregate impairment charges of approximately $1.8 billion in the first half of 2020 with respect to our proved oil and gas properties and related assets. Such declines in commodity prices also resulted in our making a downward adjustment of 278 million barrels of oil equivalent to our estimated net proved reserves at December 31, 2020.
If commodity prices decline from current levels for an extended period of time, our financial condition, cash flows and results of operations will be adversely affected and we may be limited in our ability to maintain our current level of dividends on our common stock. In addition, we may be required to incur additional impairment charges and/or make additional downward adjustments to our proved reserve estimates. As a result, our financial condition and results of operations and the trading price of our common stock may be materially and adversely affected.
We have substantial capital requirements, and we may be unable to obtain needed financing on satisfactory terms, if at all.
We make, and will continue to make, substantial capital expenditures for the acquisition, exploration, development, production and transportation of crude oil, NGLs and natural gas reserves. We intend to finance our capital expenditures primarily through our cash flows from operations and sales of non-core assets and, to a lesser extent and if and as necessary, commercial paper borrowings, bank borrowings, borrowings under our revolving credit facility and public and private equity and debt offerings.
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.
Similarly, a reduction in our cash flows (for example, as a result of lower crude oil, natural gas and/or NGLs prices or unanticipated well shut-ins) and the corresponding adverse effect on our financial condition and results of operations may also increase the interest rates that lenders and commercial paper investors require us to pay. A substantial increase in interest rates would decrease our net cash flows available for reinvestment. Any of these factors could have a material and adverse effect on our business, financial condition and results of operations.
Further, our ability to obtain financings, our borrowing costs and the terms of any financings are, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. The interrelated factors that may impact our credit ratings include our debt levels; planned capital expenditures and sales of assets; near-term and long-term production growth opportunities; liquidity; asset quality; cost structure; product mix; and commodity pricing levels (including, but not limited to, the estimates and assumptions of credit rating agencies with respect to future commodity prices). We cannot provide any assurance that our current credit ratings will remain in effect for any given period of time or that our credit ratings will be raised in the future, nor can we provide any assurance that any of our credit ratings will not be lowered.
Reserve estimates depend on many interpretations and assumptions. Any significant inaccuracies in these interpretations and assumptions could cause the reported quantities of our reserves to be materially misstated.
Estimating quantities of crude oil, NGLs and natural gas reserves and future net cash flows from such reserves is a complex, inexact process. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors, made by our management. Any significant inaccuracies in these interpretations or assumptions could cause the reported quantities of our reserves and future net cash flows from such reserves to be overstated or understated. Also, the data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, continual reassessment of the viability of production under varying economic conditions and improvements and other changes in geological, geophysical and engineering evaluation methods.
To prepare estimates of our economically recoverable crude oil, NGLs and natural gas reserves and future net cash flows from our reserves, we analyze many variable factors, such as historical production from the area compared with production rates from other producing areas. We also analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also involves economic assumptions relating to commodity prices, production costs, gathering, processing, compression, storage and transportation costs, severance, ad valorem and other applicable taxes, capital expenditures and workover and remedial costs. Many of these factors are or may be beyond our control. Our actual reserves and future net cash flows from such reserves most likely will vary from our estimates. Any significant variance, including any significant downward revisions to our existing reserve estimates, could materially and adversely affect our business, financial condition and results of operations and, in turn, the trading price 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.
If we fail to acquire or find sufficient additional reserves over time, our reserves and production will decline from their current levels.
The rate of production from crude oil and natural gas properties generally declines as reserves are produced. Except to the extent that we conduct successful exploration, exploitation and development activities resulting in additional reserves, acquire additional properties containing reserves or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our reserves will decline as they are produced. Maintaining our production of crude oil and natural gas at, or increasing our production from, current levels, is, therefore, highly dependent upon our level of success in acquiring or finding additional reserves, which may be adversely impacted by bans or restrictions on drilling. To the extent we are unsuccessful in acquiring or finding additional reserves, our future cash flows and results of operations and, in turn, the trading price of our common stock could be materially and adversely affected.
Our hedging activities may prevent us from fully benefiting from increases in crude oil, NGLs and natural gas prices and may expose us to other risks, including counterparty risk.
We use derivative instruments (primarily financial basis swap, price swap, option, swaption and collar contracts) to hedge the impact of fluctuations in crude oil, NGLs and natural gas prices on our results of operations and cash flows. To the extent that we engage in hedging activities to protect ourselves against commodity price declines, we may be prevented from fully realizing the benefits of increases in crude oil, NGLs and natural gas prices above the prices established by our hedging contracts. A portion of our forecasted production for 2021 and 2022 is subject to fluctuating market prices. If we are ultimately unable to hedge additional production volumes for 2021, 2022 and beyond, we may be materially and adversely impacted by any declines in commodity prices, which may result in lower net cash provided by operating activities. In addition, our hedging activities may expose us to the risk of financial loss in certain circumstances, including instances in which the counterparties to our hedging contracts fail to perform under the contracts.
The inability of our customers and other contractual counterparties to satisfy their obligations to us may have a material and adverse effect on us.
We have various customers for the crude oil, natural gas and related commodities that we produce as well as various other contractual counterparties, including several financial institutions and affiliates of financial institutions. Domestic and global economic conditions, including the financial condition of financial institutions generally, may adversely affect the ability of our customers and other contractual counterparties to pay amounts owed to us from time to time and to otherwise satisfy their contractual obligations to us, as well as their ability to access the credit and capital markets for such purposes.
Moreover, our customers and other contractual counterparties may be unable to satisfy their contractual obligations to us for reasons unrelated to these conditions and factors, such as the unavailability of required facilities or equipment due to mechanical failure or market conditions. Furthermore, if a customer is unable to satisfy its contractual obligation to purchase crude oil, natural gas or related commodities from us, we may be unable to sell such production to another customer on terms we consider acceptable, if at all, due to the geographic location of such production; the availability, proximity and capacity of appropriate gathering, processing, compression, storage, transportation and refining facilities; or market or other factors and conditions.
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.
Risks Related to our Operations
Drilling crude oil and natural gas wells is a high-risk activity and subjects us to a variety of risks that we cannot control.
Drilling crude oil and natural gas wells, including development wells, involves numerous risks, including the risk that we may not encounter commercially productive crude oil, NGLs and/or natural gas reserves. As a result, we may not recover all or any portion of our investment in new wells.
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:
•unexpected drilling conditions;
•title problems;
•pressure or irregularities in formations;
•equipment failures or accidents;
•adverse weather conditions, such as winter storms, flooding, tropical storms and hurricanes, and changes in weather patterns;
•compliance with, or changes in (including the adoption of new), environmental, health and safety laws and regulations relating to air emissions, hydraulic fracturing, access to and use of water, disposal or other discharge (e.g., into injection wells) of produced water, drilling fluids and other wastes, laws and regulations imposing conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas, and other laws and regulations, such as tax laws and regulations;
•the availability and timely issuance of required federal, state, tribal and other permits and licenses, which may be adversely affected by (among other things) bans or restrictions on drilling, government shutdowns or other suspensions of, or delays in, government services;
•the availability of, costs associated with and terms of contractual arrangements for properties, including mineral licenses and leases, pipelines, crude oil hauling trucks and qualified drivers and facilities and equipment to gather, process, compress, store, transport, market and export crude oil, natural gas and related commodities; and
•the costs of, or shortages or delays in the availability of, drilling rigs, hydraulic fracturing services, pressure pumping equipment and supplies, tubular materials, water, sand, disposal facilities, qualified personnel and other necessary facilities, equipment, materials, supplies and services.
Our failure to recover our investment in wells, increases in the costs of our drilling operations or those of our third-party operators, and/or curtailments, delays or cancellations of our drilling operations or those of our third-party operators, in each case, due to any of the above factors or other factors, may materially and adversely affect our business, financial condition and results of operations. For related discussion of the risks and potential losses and liabilities inherent in our crude oil and natural gas operations generally, see the immediately following risk factor.
Our crude oil, NGLs and natural gas operations and supporting activities and operations involve many risks and expose us to potential losses and liabilities, and insurance may not fully protect us against these risks and potential losses and liabilities.
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 and transporting, crude oil and natural gas, including the risks of:
•well blowouts and cratering;
•loss of well control;
•crude oil spills, natural gas leaks, formation water (i.e., produced water) spills and pipeline ruptures;
•pipe failures and casing collapses;
•uncontrollable flows of crude oil, natural gas, formation water or drilling fluids;
•releases of chemicals, wastes or pollutants;
•adverse weather events, such as winter storms, flooding, tropical storms and hurricanes, and other natural disasters;
•fires and explosions;
•terrorism, vandalism and physical, electronic and cybersecurity breaches;
•formations with abnormal or unexpected pressures;
•leaks or spills in connection with, or associated with, the gathering, processing, compression, storage and transportation of crude oil, NGLs and natural gas; and
•malfunctions of, or damage to, gathering, processing, compression and transportation facilities and equipment and other facilities and equipment utilized in support of our crude oil and natural gas operations.
If any of these events occur, we could incur losses, liabilities and other additional costs as a result of:
•injury or loss of life;
•damage to, or destruction of, property, facilities, equipment and crude oil and natural gas reservoirs;
•pollution or other environmental damage;
•regulatory investigations and penalties as well as cleanup and remediation responsibilities and costs;
•suspension or interruption of our operations, including due to injunction;
•repairs necessary to resume operations; and
•compliance with laws and regulations enacted as a result of such events.
We maintain insurance against many, but not all, such losses and liabilities in accordance with what we believe are customary industry practices and in amounts and at costs that we believe to be prudent and commercially practicable. However, the occurrence of any of these events and any losses or liabilities incurred as a result of such events, if uninsured or in excess of our insurance coverage, would reduce the funds available to us for our operations and could, in turn, have a material and adverse effect on our business, financial condition and results of operations.
Our ability to sell and deliver our crude oil, NGLs and natural gas production could be materially and adversely affected if adequate gathering, processing, compression, storage, transportation and export facilities and equipment are unavailable.
The sale of our crude oil, NGLs and natural gas production depends on a number of factors beyond our control, including the availability, proximity and capacity of, and costs associated with, gathering, processing, compression, storage, transportation and export facilities and equipment owned by third parties. These facilities and equipment may be temporarily unavailable to us due to market conditions, regulatory reasons, mechanical reasons or other factors or conditions, and may not be available to us in the future on terms we consider acceptable, if at all. In particular, in certain newer plays, the capacity of gathering, processing, compression, storage, transportation and export facilities and equipment may not be sufficient to accommodate potential production from existing and new wells. In addition, lack of financing, construction and permitting delays, permitting costs and regulatory or other constraints could limit or delay the construction, manufacture or other acquisition of new gathering, processing, compression, storage, transportation and export facilities and equipment by third parties or us, and we may experience delays or increased costs in accessing the pipelines, gathering systems or rail systems necessary to transport our production to points of sale or delivery.
Any significant change in market or other conditions affecting gathering, processing, compression, storage, transportation 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.
A portion of our crude oil, NGLs and natural gas production may be subject to interruptions that could have a material and adverse effect on us.
A portion of our crude oil, NGLs and natural gas production may be interrupted, or shut in, from time to time for various reasons, including, but not limited to, as a result of accidents, weather conditions, the unavailability of gathering, processing, compression, storage, transportation, refining or export facilities or equipment or field labor issues, or intentionally as a result of market conditions such as crude oil, NGLs or natural gas prices that we deem uneconomic. If a substantial amount of our production is interrupted or shut in, our cash flows and, in turn, our financial condition and results of operations could be materially and adversely affected.
We have limited control over the activities on properties that we do not operate.
Some of the properties in which we have an interest are operated by other companies and involve third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that we will be required to fund with respect to such properties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. In addition, a third-party operator could also decide to shut-in or curtail production from wells, or plug and abandon marginal wells, on properties owned by that operator during periods of lower crude oil, NGLs or natural gas prices. These limitations and our dependence on the operator and third-party working interest owners for these projects could cause us to incur unexpected future costs, lower production and materially and adversely affect our financial condition and results of operations.
If we acquire crude oil, NGLs and natural gas properties, our failure to fully identify existing and potential problems, to accurately estimate reserves, production rates or costs, or to effectively integrate the acquired properties into our operations could materially and adversely affect our business, financial condition and results of operations.
From time to time, we seek to acquire crude oil and natural gas properties - for example, our October 2016 mergers and related asset purchase transactions with Yates Petroleum Corporation and certain of its affiliated entities. Although we perform reviews of properties to be acquired in a manner that we believe is duly diligent and consistent with industry practices, reviews of records and properties may not necessarily reveal existing or potential problems (such as title or environmental issues), nor may they permit us to become sufficiently familiar with the properties in order to fully assess their deficiencies and potential. Even when problems with a property are identified, we often may assume environmental and other risks and liabilities in connection with acquired properties pursuant to the acquisition agreements.
In addition, there are numerous uncertainties inherent in estimating quantities of crude oil 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.
Competition in the oil and gas exploration and production industry is intense, and some 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 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 operations in jurisdictions outside the U.S. are subject to various risks inherent in foreign operations. These risks include, among other risks:
•increases in taxes and governmental royalties;
•changes in laws and policies governing operations of foreign-based companies;
•loss of revenue, loss of or damage to equipment, property and other assets and interruption of operations as a result of expropriation, nationalization, acts of terrorism, war, civil unrest and other political risks;
•unilateral or forced renegotiation, modification or nullification of existing contracts with governmental entities;
•difficulties enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations; and
•currency restrictions or exchange rate fluctuations.
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.
Unfavorable currency exchange rate fluctuations could materially and adversely affect our results of operations.
The reporting currency for our financial statements is the U.S. dollar. However, certain of our subsidiaries are located in countries other than the U.S. and have functional currencies other than the U.S. dollar. The assets, liabilities, revenues and expenses of certain of these foreign subsidiaries are denominated in currencies other than the U.S. dollar. To prepare our consolidated financial statements, we must translate those assets, liabilities, revenues and expenses into U.S. dollars at then-applicable exchange rates. Consequently, increases and decreases in the value of the U.S. dollar versus other currencies will affect the amount of these items in our consolidated financial statements, even if the amount has not changed in the original currency. These translations could result in changes to our results of operations from period to period. For the fiscal year ended December 31, 2020, less than 1% of our net operating revenues related to operations of our foreign subsidiaries whose functional currency was not the U.S. dollar.
Risks Related to Regulatory and Legal Matters
The regulatory, legislative and policy changes pursued by the new U.S. presidential administration may materially and adversely affect the oil and gas exploration and production industry.
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 consultation with other agencies and stakeholders, to (i) 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 leasing practices and (ii) consider whether to adjust royalties associated with oil and gas resources extracted from federal lands and offshore waters to account for corresponding climate costs.
Further, such regulatory, legislative and policy changes may, among other things, result in additional permitting and disclosure requirements, additional operating restrictions and/or the imposition of various conditions and restrictions on drilling and completion operations or other aspects of our business, any of which could lead to operational delays, increased operating and compliance costs and/or other impacts on our business and operations and could materially and adversely affect our business, results of operations and financial condition.
For related discussion, see the below risk factors regarding legislative and regulatory matters impacting the oil and gas exploration and production industry.
We incur certain costs to comply with government regulations, particularly regulations relating to environmental protection and safety, and could incur even greater costs in the future.
Our crude oil, NGLs and natural gas operations and supporting activities are regulated extensively by federal, state, tribal and local governments and regulatory agencies, both domestically and in the foreign countries in which we do business, and are subject to interruption or termination by governmental and regulatory authorities based on environmental, health, safety or other considerations. Moreover, we have incurred and will continue to incur costs in our efforts to comply with the requirements of environmental, health, safety and other regulations. Further, the regulatory environment could change in ways that we cannot predict and that might substantially increase our costs of compliance and/or adversely affect our business and operations and, in turn, materially and adversely affect our results of operations and financial condition, including any changes that may result from the recent U.S. elections and change in administration (see the risk factor above with respect to the new U.S. administration).
Specifically, as a current or past owner or lessee and operator of crude oil and natural gas properties, we are subject to various federal, state, tribal, local and foreign regulations relating to the discharge of materials into, and the protection of, the environment. These regulations may, among other things, impose liability on us for the cost of pollution cleanup resulting from current or past operations, subject us to liability for pollution damages and require suspension or cessation of operations in affected areas. Changes in, or additions to, these regulations, including any changes that may result from the recent U.S. elections and change in administration, could lead to increased operating and compliance costs and, in turn, materially and adversely affect our business, results of operations and financial condition.
The regulation of hydraulic fracturing is primarily conducted at the state and local level through permitting and other compliance requirements and, further, some state and local governments have imposed or have considered imposing various conditions and restrictions on drilling and completion operations. The U.S. Environmental Protection Agency (U.S. EPA) has issued regulations relating to hydraulic fracturing and there have been various other proposals to regulate hydraulic fracturing at the federal level. In addition, there were proposals and positions taken by President Biden during his campaign regarding the use of hydraulic fracturing on 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 consultation 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 leasing practices.
Any such requirements, restrictions, conditions or prohibition could lead to operational delays and increased operating and compliance costs and, further, 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. Accordingly, our production of crude oil and natural gas could be materially and adversely affected. For additional discussion regarding hydraulic fracturing regulation, see Regulation of Hydraulic Fracturing and Other Operations - United States under ITEM 1, Business - Regulation.
We will continue to monitor and assess any proposed or new policies, legislation, regulations and treaties in the areas where we operate to determine the impact on our operations and take appropriate actions, where necessary. We are unable to predict the timing, scope and effect of any currently proposed or future laws, regulations or treaties, but the direct and indirect costs of such laws, regulations and treaties (if enacted) could materially and adversely affect our business, results of operations and financial condition. See also the risk factor below regarding the provisions of the Dodd-Frank Wall Street Reform and Consumer Protection Act with respect to regulation of derivatives transactions and entities (such as EOG) that participate in such transactions.
Regulations, government policies and government and corporate initiatives relating to greenhouse gas emissions and climate change could have a significant impact on our operations and we could incur significant cost in the future to comply.
Local, state, federal and international regulatory bodies have been increasingly focused on GHG emissions and climate change issues in recent years. For example, we are subject to the U.S. EPA’s rule requiring annual reporting of GHG emissions. In addition, our oil and gas production and processing operations are subject to the U.S. EPA's new source performance standards applicable to emissions of volatile organic compounds from new, modified and reconstructed crude oil and natural gas wells and equipment located at natural gas production gathering and booster stations and gas processing plants.
At the international level, 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. While the U.S. withdrew from the Paris Agreement on November 4, 2020, President Biden issued an executive order on January 20, 2021 recommitting the United States to the Paris Agreement. 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.
It is possible that the Paris Agreement and subsequent domestic and international regulations and government policies will have adverse effects on the market for crude oil, natural gas and other fossil fuel products as well as adverse effects on the business and operations of companies engaged in the exploration for, and production of, crude oil, natural gas and other fossil fuel products. We are 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 developments (if enacted, issued or applied) could materially and adversely affect our operations, financial condition and results of operations. 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. For additional discussion regarding climate change regulation, see (i) Climate Change - United States under ITEM 1, Business - Regulation and (ii) the risk factor above with respect to the new U.S. administration.
In addition, the achievement of our current or future internal initiatives relating to the reduction of GHG emissions may increase our costs, including requiring us to purchase emissions credits or offsets, or may impact or otherwise limit our ability to execute on our business plans.
Further, 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.
Tax laws and regulations applicable to crude oil and natural gas exploration and production companies may change over time, and such changes could materially and adversely affect our cash flows, results of operations and financial condition.
From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal income tax laws applicable to crude oil and natural gas exploration and production companies, such as with respect to the intangible drilling and development costs deduction and bonus tax depreciation. While these specific changes were not included in the Tax Cuts and Jobs Act signed into law in December 2017, no accurate prediction can be made as to whether any such legislative changes or similar or other tax law changes will be proposed in the future (for example, by the new U.S. administration) and, if enacted, what the specific provisions or the effective date of any such legislation would be. The elimination of certain U.S. federal income tax deductions, as well as any other changes to, or the imposition of new, federal, state, local or non-U.S. taxes (including the imposition of, or increases in, production, severance or similar taxes), could materially and adversely affect our cash flows, results of operations and financial condition.
In addition, legislation may be proposed with respect to the enactment of a tax levied on the carbon content of fuels based on the GHG emissions associated with such fuels. A carbon tax would generally increase the prices for crude oil, natural gas and NGLs. Such price increases may, in turn, reduce demand for crude oil, natural gas and NGLs and materially and adversely affect our cash flows, results of operations and financial condition.
We are unable to predict the timing, scope and effect 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 continue to monitor and assess any proposed or enacted tax law changes to determine the impact on our business, results of operations and financial 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.
As discussed in the risk factor above regarding our hedging activities, we use derivative instruments to hedge the impact of fluctuations in crude oil, NGLs and natural gas prices on our results of operations and cash flows. In 2010, Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), which, among other matters, provides for federal oversight of the over-the-counter derivatives market and entities that participate in that market and mandates that the Commodity Futures Trading Commission (CFTC), the U.S. Securities and Exchange Commission (SEC) and certain federal agencies that regulate the banking and insurance sectors (the Prudential Regulators) adopt rules or regulations implementing the Dodd-Frank Act and providing definitions of terms used in the Dodd-Frank Act. The Dodd-Frank Act establishes margin requirements and requires clearing and trade execution practices for certain categories of swaps and may result in certain market participants needing to curtail their derivatives activities. Although some of the rules necessary to implement the Dodd-Frank Act are yet to be adopted, the CFTC, the SEC and the Prudential Regulators have issued numerous rules, including a rule establishing an “end-user” exception to mandatory clearing (End-User Exception), a rule regarding margin for uncleared swaps (Margin Rule) and a proposed rule imposing position limits (Position Limits Rule).
We qualify as a "non-financial entity" for purposes of the End-User Exception and, as such, we are eligible for such exception. As a result, our hedging activities are not subject to mandatory clearing or the margin requirements imposed in connection with mandatory clearing. We also qualify as a "non-financial end user" for purposes of the Margin Rule; therefore, our uncleared swaps are not subject to regulatory margin requirements. Finally, we believe our hedging activities would constitute bona fide hedging under the Position Limits Rule and would not be subject to limitation under such rule if it is enacted. However, many of our hedge counterparties and many other market participants are not eligible for the End-User Exception, are subject to mandatory clearing and the Margin Rule for swaps with some or all of their other swap counterparties, and may be subject to the Position Limits Rule. In addition, the European Union and other non-U.S. jurisdictions have enacted laws and regulations related to derivatives (collectively, Foreign Regulations) which apply to our transactions with counterparties subject to such Foreign Regulations.
The Dodd-Frank Act, the rules adopted thereunder and the Foreign Regulations could increase the cost of derivative contracts, alter the terms of derivative contracts, reduce the availability of derivatives to protect against the price risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, lessen the number of available counterparties and, in turn, increase our exposure to less creditworthy counterparties. If our use of derivatives is reduced as a result of the Dodd-Frank Act, related regulations or the Foreign Regulations, our results of operations may become more volatile, and our cash flows may be less predictable, which could adversely affect our ability to plan for, and fund, our capital expenditure requirements. Any of these consequences could have a material and adverse effect on our business, financial condition and results of operations.
Risks Related to COVID-19, Cybersecurity and Other External Factors
Outbreaks of communicable diseases can adversely affect our business, financial condition and results 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 crude oil, natural gas and NGLs, lead to operational disruptions and limit our ability to execute on our business plan, any of which could materially and adversely affect our business, financial condition and results of operations. Furthermore, uncertainty regarding the impact of any outbreak of contagious disease could lead to increased volatility in crude oil, natural gas and NGL prices.
For example, the current pandemic involving a highly transmissible and pathogenic coronavirus (COVID-19) and the measures being taken to address and limit the spread of the virus have adversely affected the economies and financial markets of the world, resulting in an economic downturn that has negatively impacted, and may continue to negatively impact, global demand and prices for crude oil, natural gas and NGLs. In fact, the substantial declines in crude oil, natural gas and NGL prices that occurred in the first half of 2020 as a result of the economic downturn and overall reduction of demand prompted by the COVID-19 pandemic (and the oversupply of crude oil from certain foreign oil-exporting countries) materially and adversely affected the amount of cash flows we had available for our 2020 capital expenditures and other operating expenses, our results of operations during the first half of 2020 and the trading price of our common stock.
While in the second half of 2020 the prices for natural gas and NGLs recovered to pre-pandemic levels and the prices for crude oil increased from their first half 2020 levels, if such price declines were to reoccur and continue for an extended period of time, our cash flows and results of operations would be further adversely affected, as could the trading price of our common stock. For further discussion regarding the potential impacts on us of lower commodity prices and extended declines in commodity prices, see the related discussion in the first risk factor in this section.
Further, if the COVID-19 outbreak should continue or worsen, we may also experience disruptions to commodities markets, equipment supply chains and the availability of our workforce, which could materially and adversely affect our ability to conduct our business and operations. In addition, if the resulting economic downturn should continue or worsen, our customers and other contractual parties may be unable to pay amounts owed to us from time to time and to otherwise satisfy their contractual obligations to us, and may be unable to access the credit and capital markets for such purposes. Such inability of our customers and other contractual counterparties may materially and adversely affect our business, financial condition, results of operations and cash flows.
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, and other disruptions.
As an oil and gas producer, we face various security threats, including (i) cybersecurity threats to gain unauthorized access to, or control of, our sensitive information or to render our data or systems corrupted or unusable; (ii) threats to the security of our facilities and infrastructure or to the security of third-party facilities and infrastructure, such as gathering, transportation, processing, fractionation, refining and export facilities; and (iii) threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material and adverse effect on our business.
We rely extensively on information technology systems, including internally developed software, data hosting platforms, real-time data acquisition systems, third-party software, cloud services and other internally or externally hosted hardware and software platforms, to (i) estimate our oil and gas reserves, (ii) process and record financial and operating data, (iii) process and analyze all stages of our business operations, including exploration, drilling, completions, production, transportation, pipelines and other related activities and (iv) communicate with our employees and vendors, suppliers and other third parties. Although we have implemented and invested in, and will continue to implement and invest in, controls, procedures and protections (including internal and external personnel) that are designed to protect our systems, identify and remediate on a regular basis vulnerabilities in our systems and related infrastructure and monitor and mitigate the risk of data loss and other cybersecurity threats, such measures cannot entirely eliminate cybersecurity threats and the controls, procedures and protections we have implemented and invested in may prove to be ineffective.
Our systems and networks, and those of our business associates, may become the target of cybersecurity attacks, including, without limitation, denial-of-service attacks; malicious software; data privacy breaches by employees, insiders or others with authorized access; cyber or phishing-attacks; ransomware; attempts to gain unauthorized access to our data and systems; and other electronic security breaches. If any of these security breaches were to occur, we could suffer disruptions to our normal operations, including our drilling, completion, production and corporate functions, which could materially and adversely affect us in a variety of ways, including, but not limited to, the following:
•unauthorized access to, and release of, our business data, reserves information, strategic information or other sensitive or proprietary information, which could have a material and adverse effect on our ability to compete for oil and gas resources, or reduce our competitive advantage over other companies;
•data corruption, communication interruption, or other operational disruptions during our drilling activities, which could result in our failure to reach the intended target or a drilling incident;
•data corruption or operational disruptions of our production-related infrastructure, which could result in loss of production or accidental discharges;
•unauthorized access to, and release of, personal information of our royalty owners, employees and vendors, which could expose us to allegations that we did not sufficiently protect such information;
•a cybersecurity attack on a vendor or service provider, which could result in supply chain disruptions and could delay or halt our operations;
•a cybersecurity attack on third-party gathering, transportation, processing, fractionation, refining or export facilities, which could result in reduced demand for our production or delay or prevent us from transporting and marketing our production, in either case resulting in a loss of revenues;
•a cybersecurity attack involving commodities exchanges or financial institutions could slow or halt commodities trading, thus preventing us from marketing our production or engaging in hedging activities, resulting in a loss of revenues;
•a deliberate corruption of our financial or operating data could result in events of non-compliance which could then lead to regulatory fines or penalties;
•a cybersecurity attack on a communications network or power grid, which could cause operational disruptions resulting in a loss of revenues; and
•a cybersecurity attack on our automated and surveillance systems, which could cause a loss of production and potential environmental hazards.
Further, strategic targets, such as energy-related assets, may be at a greater risk of terrorist attacks or cybersecurity attacks than other targets in the United States. Moreover, external digital technologies control nearly all of the crude oil and natural gas distribution and refining systems in the U.S. and abroad, which are necessary to transport and market our production. A cybersecurity attack directed at, for example, crude oil and natural gas distribution systems could (i) damage critical distribution and storage assets or the environment; (ii) disrupt energy supplies and markets, by delaying or preventing delivery of production to markets; and (iii) make it difficult or impossible to accurately account for production and settle transactions.
Any such terrorist attack or cybersecurity attack that affects us, our customers, suppliers, or others with whom we do business and/or energy-related assets could have a material adverse effect on our business, including disruption of our operations, damage to our reputation, a loss of counterparty trust, reimbursement or other costs, increased compliance costs, significant litigation exposure and legal liability or regulatory fines, penalties or intervention. Although we have business continuity plans in place, our operations may be adversely affected by significant and widespread disruption to our systems and the infrastructure that supports our business. While we continue to evolve and modify our business continuity plans as well as our cyber threat detection and mitigation systems, there can be no assurance that they will be effective in avoiding disruption and business impacts. Further, our insurance may not be adequate to compensate us for all resulting losses, and the cost to obtain adequate coverage may increase for us in the future and some insurance coverage may become more difficult to obtain, if available at all.
While we have experienced limited cybersecurity attacks in the past, we have not suffered any losses as a result of such attacks; however, there is no assurance that we will not suffer such losses in the future. Further, as technologies evolve and cybersecurity threats become more sophisticated, we are continually expending additional resources to modify or enhance our security measures to protect against such threats and to identify and remediate on a regular basis any vulnerabilities in our information systems and related infrastructure that may be detected, and these expenditures in the future may be significant. Additionally, the continuing and evolving threat of cybersecurity attacks has resulted in evolving legal and compliance matters, including increased regulatory focus on prevention, which could require us to expend significant additional resources to meet such requirements.
Terrorist activities and military and other actions could materially and adversely affect us.
Terrorist attacks and the threat of terrorist attacks (including cyber-related attacks), whether domestic or foreign, as well as military or other actions taken in response to these acts, could cause instability in the global financial and energy markets. The U.S. government has from time to time issued public warnings that indicate that energy-related assets, such as transportation and refining facilities, might be specific targets of terrorist organizations.
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.
Weather and climate may have a significant and adverse impact on us.
Demand for crude oil and natural gas is, to a degree, dependent on weather and climate, which impacts, among other things, the price we receive for the commodities that 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 residences and businesses) and, as a result, lower prices for natural gas production during that season.
In addition, there has been public discussion that climate change may be associated with more frequent or more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, and other related phenomena, which could affect some, or all, of our operations. Our exploration, exploitation and development activities and equipment could be adversely affected by extreme weather events, such as winter storms, flooding and tropical storms and hurricanes in the Gulf of Mexico, which may cause a loss of production from temporary cessation of activity or damaged facilities and equipment. Such extreme weather events could also impact other areas of our operations, including access to our drilling and production facilities for routine operations, maintenance and repairs, the installation and operation of gathering, processing, compression, storage, transportation and/or export facilities and the availability of, and our access to, necessary third-party services, such as gathering, processing, compression, storage and transportation services and export services. Such extreme weather events and changes in weather patterns may materially and adversely affect our business and, in turn, our financial condition and results of operations.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. Unresolved Staff Comments
Not applicable.

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ITEM 2. PROPERTIES
ITEM 2. Properties
Oil and Gas Exploration and Production - Properties and Reserves
Reserve Information. For estimates and discussions of EOG's net proved reserves of crude oil and condensate, natural gas liquids (NGLs) and natural gas, the qualifications of the preparers of EOG's reserve estimates, EOG's independent petroleum consultants and EOG's processes and controls with respect to its reserve estimates, see "Supplemental Information to Consolidated Financial Statements."
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth in "Supplemental Information to Consolidated Financial Statements" represent only estimates. Reserve engineering is a 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. Future production is, therefore, highly dependent upon the level of success 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."
Acreage. The following table summarizes EOG's gross and net developed and undeveloped acreage at December 31, 2020. Excluded is acreage in which EOG's interest is limited to owned royalty, overriding royalty and other similar interests.
Developed Undeveloped Total
Gross Net Gross Net Gross Net
United States 2,528,907 1,887,080 2,871,470 1,983,209 5,400,377 3,870,289
Trinidad 79,410 67,580 201,302 115,168 280,712 182,748
China 130,548 130,548 - - 130,548 130,548
Canada 30,771 27,513 19,197 19,197 49,968 46,710
Oman - - 8,400,348 7,828,089 8,400,348 7,828,089
Total 2,769,636 2,112,721 11,492,317 9,945,663 14,261,953 12,058,384
Most of our undeveloped oil and gas leases, particularly in the United States, are subject to lease expiration if initial wells are not drilled within a specified period, generally between three to five years. Approximately 0.2 million net acres will expire in 2021, 0.2 million net acres will expire in 2022 and 0.1 million net acres will expire in 2023 if production is not established or we take no other action to extend the terms of the leases or obtain concessions. As of December 31, 2020, there were no proved undeveloped reserves (PUDs) associated with such undeveloped acreage. In the ordinary course of business, based on our evaluations of certain geologic trends and prospective economics, we have allowed certain lease acreage to expire and may allow additional acreage to expire in the future.
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 Oman is set to expire in 2024, with certain provisions allowing for extension of such term if commercial discoveries are found.
Productive Well Summary. The following table represents EOG's gross and net productive wells, including 2,482 wells in which we hold a royalty interest.
Crude Oil Natural Gas Total
Gross Net Gross Net Gross Net
United States 9,658 6,724 3,985 1,942 13,643 8,666
Trinidad 2 1 33 27 35 28
China - - 36 36 36 36
Canada - - 1 - 1 -
Total (1)
9,660 6,725 4,055 2,005 13,715 8,730
(1) EOG operated 9,491 gross and 8,394 net producing crude oil and natural gas wells at December 31, 2020. Gross crude oil and natural gas wells include 142 wells with multiple completions.
Drilling and Acquisition Activities. During the years ended December 31, 2020, 2019 and 2018, EOG expended $3.7 billion, $6.6 billion and $6.4 billion, respectively, for exploratory and development drilling, facilities and acquisition of leases and producing properties, including asset retirement obligations of $117 million, $186 million and $70 million, respectively. The following tables set forth the results of the gross crude oil and natural gas wells completed for the years ended December 31, 2020, 2019 and 2018:
Gross Development Wells Completed Gross Exploratory Wells Completed
Crude Oil Natural Gas Dry Hole Total Crude Oil Natural Gas Dry Hole Total
United States
580 13 15 608 3 - 4 7
Trinidad
- - - - - 3 - 3
China
- - - - - - - -
Total
580 13 15 608 3 3 4 10
United States 833 26 14 873 4 - 1 5
Trinidad - 1 - 1 - - 1 1
China - 2 - 2 - - 1 1
Total 833 29 14 876 4 - 3 7
United States 834 39 22 895 - - 1 1
Trinidad - - - - - - - -
China - 1 - 1 - 2 - 2
Total 834 40 22 896 - 2 1 3
The following tables set forth the results of the net crude oil and natural gas wells completed for the years ended December 31, 2020, 2019 and 2018:
Net Development Wells Completed Net Exploratory Wells Completed
Crude Oil Natural Gas Dry Hole Total Crude Oil Natural Gas Dry Hole Total
United States
516 12 15 543 2 - 3 5
Trinidad
- - - - - 2 - 2
China
- - - - - - - -
Total
516 12 15 543 2 2 3 7
United States 721 22 12 755 4 - 1 5
Trinidad - 1 - 1 - - 1 1
China - 2 - 2 - - 1 1
Total 721 25 12 758 4 - 3 7
United States 704 37 18 759 - - 1 1
Trinidad - - - - - - - -
China - 1 - 1 - 2 - 2
Total 704 38 18 760 - 2 1 3
EOG participated in the drilling of wells that were in the process of being drilled or completed at the end of the period as set out in the table below for the years ended December 31, 2020, 2019 and 2018:
Wells in Progress at End of Period
2020 2019 2018
Gross Net Gross Net Gross Net
United States 155 147 317 286 297 238
Trinidad 1 1 1 1 - -
China 3 3 3 3 4 4
Oman 1 1 - - - -
Total 160 152 321 290 301 242
Included in the previous table of wells in progress at the end of the period were wells which had been drilled, but were not completed (DUCs). In order to effectively manage its capital expenditures and to provide flexibility in managing its drilling rig and well completion schedules, EOG, from time to time, will have an inventory of DUCs. At December 31, 2020, there were approximately 84 MMBoe of net PUDs associated with EOG's inventory of DUCs. Under EOG's current drilling plan, all such DUCs are expected to be completed within five years from the original booking date of such reserves. The following table sets forth EOG's DUCs, for which PUDs had been booked, as of the end of each period.
Drilled Uncompleted Wells at End of Period
2020 2019 2018
Gross Net Gross Net Gross Net
United States 89 86 188 165 168 137
China 3 3 3 3 3 3
Total 92 89 191 168 171 140
EOG acquired wells as set forth in the following tables as of the end of each period (excluding the acquisition of additional interests in 8, 11 and 114 net wells in which EOG previously owned an interest for the years ended December 31, 2020, 2019 and 2018, respectively):
Gross Acquired Wells Net Acquired Wells
Crude
Oil Natural Gas Total Crude
Oil Natural Gas Total
United States
80 3 83 70 3 73
Total
80 3 83 70 3 73
United States 9 45 54 9 37 46
Total 9 45 54 9 37 46
United States 15 13 28 10 6 16
Total 15 13 28 10 6 16
Other Property, Plant and Equipment. EOG's other property, plant and equipment primarily includes gathering, transportation and processing infrastructure assets, buildings and sand processing assets which support EOG's exploration and production activities. EOG does not own drilling rigs, hydraulic fracturing equipment or rail cars. All of EOG's drilling and completion activities are conducted on a contractual basis with independent drilling contractors and other third-party service contractors.

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ITEM 3. LEGAL PROCEEDINGS
ITEM 3. Legal Proceedings
See the information set forth under the "Contingencies" caption in Note 8 of the Notes to Consolidated Financial Statements, which is incorporated by reference herein.
Item 103 of Regulation S-K promulgated under the Securities Exchange Act of 1934, as amended, requires disclosure regarding certain proceedings arising under federal, state or local environmental laws when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions that EOG reasonably believes will exceed a specified threshold. Pursuant to recent amendments to this item, EOG will be using a threshold of $1 million for purposes of determining whether disclosure of any such proceedings is required; EOG believes proceedings under this threshold are not material to EOG's business and financial condition. Applying this threshold, there are no environmental proceedings to disclose for the quarter and year ended December 31, 2020.

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ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4. Mine Safety Disclosures
The information concerning mine safety violations and other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95 to this report.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
EOG's common stock is traded on the New York Stock Exchange under the ticker symbol "EOG."
As of February 12, 2021, there were approximately 2,060 record holders and approximately 321,000 beneficial owners of EOG's common stock.
The following table sets forth, for the periods indicated, EOG's share repurchase activity:
Period
(a)
Total
Number of
Shares
Purchased (1)
(b)
Average
Price Paid
per Share (c)
Total Number of
Shares Purchased as
Part of Publicly
Announced Plans or
Programs (d)
Maximum Number
of Shares that May Yet
Be Purchased Under
the Plans or Programs (2)
October 1, 2020 - October 31, 2020 3,892 $ 34.56 - 6,386,200
November 1, 2020 - November 30, 2020 3,678 41.84 - 6,386,200
December 1, 2020 - December 31, 2020 19,548 52.21 - 6,386,200
Total 27,118 $ 48.27
(1)The 27,118 total shares for the quarter ended December 31, 2020, and the 389,613 total shares for the full year 2020, consist solely of shares that were withheld by or returned to EOG (i) in satisfaction of tax withholding obligations that arose upon the exercise of employee stock options or stock-settled stock appreciation rights or the vesting of restricted stock, restricted stock unit or performance unit grants or (ii) in payment of the exercise price of employee stock options. These shares do not count against the 10 million aggregate share repurchase authorization of EOG's Board discussed below.
(2)In September 2001, the Board authorized the repurchase of up to 10,000,000 shares of EOG's common stock. During 2020, EOG did not repurchase any shares under the Board-authorized repurchase program. EOG last repurchased shares under this program in March 2003.
Comparative Stock Performance
The following performance graph and related information shall not be deemed "soliciting material" or to be "filed" with the United States Securities and Exchange Commission, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933, as amended, or Securities Exchange Act of 1934, as amended, except to the extent that EOG specifically requests that such information be treated as "soliciting material" or specifically incorporates such information by reference into such a filing.
The performance graph shown below compares the cumulative five-year total return to stockholders on EOG's common stock as compared to the cumulative five-year total returns on the Standard and Poor's 500 Index (S&P 500) and the Standard and Poor's 500 Oil & Gas Exploration & Production Index (S&P O&G E&P). The comparison was prepared based upon the following assumptions:
1.$100 was invested on December 31, 2015 in each of the following: common stock of EOG, the S&P 500 and the S&P O&G E&P.
2. Dividends are reinvested.
Comparison of Five-Year Cumulative Total Returns
EOG, S&P 500 and S&P O&G E&P
(Performance Results Through December 31, 2020)
2015 2016 2017 2018 2019 2020
EOG $ 100.00 $ 144.04 $ 154.79 $ 125.91 $ 122.37 $ 74.85
S&P 500 $ 100.00 $ 111.96 $ 136.40 $ 130.42 $ 171.49 $ 203.05
S&P O&G E&P $ 100.00 $ 132.83 $ 124.46 $ 100.19 $ 112.23 $ 73.61

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. Selected Financial Data
(In Thousands, Except Per Share Data)
The following selected consolidated financial information should be read in conjunction with ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations and ITEM 8, Financial Statements and Supplementary Data.
Year Ended December 31 2020 2019 2018 2017 2016
Statement of Income Data:
Operating Revenues and Other (1)
$ 11,032,048 $ 17,379,973 $ 17,275,399 $ 11,208,320 $ 7,650,632
Operating Income (Loss) $ (544,016) $ 3,699,011 $ 4,469,346 $ 926,402 $ (1,225,281)
Net Income (Loss) $ (604,572) $ 2,734,910 $ 3,419,040 $ 2,582,579 $ (1,096,686)
Net Income (Loss) Per Share
Basic $ (1.04) $ 4.73 $ 5.93 $ 4.49 $ (1.98)
Diluted $ (1.04) $ 4.71 $ 5.89 $ 4.46 $ (1.98)
Dividends Per Common Share $ 1.50 $ 1.0825 $ 0.81 $ 0.67 $ 0.67
Average Number of Common Shares
Basic 578,949 577,670 576,578 574,620 553,384
Diluted 578,949 580,777 580,441 578,693 553,384
At December 31 2020 2019 2018 2017 2016
Balance Sheet Data:
Total Property, Plant and Equipment, Net $ 28,598,627 $ 30,364,595 $ 28,075,519 $ 25,665,037 $ 25,707,078
Total Assets (2) (3) (4)
35,804,601 37,124,608 33,934,474 29,833,078 29,299,201
Total Debt 5,816,405 5,175,443 6,083,262 6,387,071 6,986,358
Total Stockholders' Equity 20,301,887 21,640,716 19,364,188 16,283,273 13,981,581
(1) Effective January 1, 2018, EOG adopted the provisions of Accounting Standards Update (ASU) 2014-09, "Revenue From Contracts With Customers" (ASU 2014-09). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees relating to certain processing and marketing agreements within its United States segment as Gathering and Processing Costs instead of as a deduction to Natural Gas Revenues. There was no impact to operating income, net income or cash flows resulting from changes to the presentation of natural gas processing fees. EOG elected to adopt ASU 2014-09 using the modified retrospective approach with no reclassification of amounts for the years ended December 31, 2017 and 2016 (see Note 1 to Consolidated Financial Statements).
(2) Effective January 1, 2020, EOG adopted the provisions of ASU 2016-13, "Measurement of Credit Losses on Financial Instruments" (ASU 2016-13). ASU 2016-13 changes the impairment model for financial assets and certain other instruments by requiring entities to adopt a forward-looking expected loss model that will result in earlier recognition of credit losses. EOG elected to adopt ASU 2016-13 using the modified retrospective approach with a cumulative-effect adjustment to retained earnings as of the effective date. Financial results reported in periods prior to January 1, 2020, are unchanged. There was no impact to retained earnings upon adoption of ASU 2016-13 and EOG expects current and future credit losses to be immaterial. EOG continues to monitor the credit risk from third-party companies to determine if expected credit losses may become material.
(3) Effective January 1, 2019, EOG adopted the provisions of ASU 2016-02, "Leases (Topic 842)" (ASU 2016-02), which require that lessees recognize a right-of-use (ROU) asset and related lease liability, representing the obligation to make lease payments of certain lease transactions, on the Consolidated Balance Sheets. EOG elected to adopt ASU 2016-02 and other related ASUs using the modified retrospective approach with a cumulative-effect adjustment to the opening balance of retained earnings as of the effective date. Financial results reported in periods prior to January 1, 2019, are unchanged. There was no impact to retained earnings upon adoption of ASU 2016-02 and other related ASUs. See Notes 1 and 18 to Consolidated Financial Statements.
(4) Effective January 1, 2017, EOG adopted the provisions of ASU 2015-17, "Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes" (ASU 2015-17), which simplifies the presentation of deferred taxes in a classified balance sheet by eliminating the requirement to separate deferred income tax liabilities and assets into current and noncurrent amounts. Instead, ASU 2015-17 requires that all deferred tax liabilities and assets be shown as noncurrent in a classified balance sheet. In connection with the adoption of ASU 2015-17, EOG restated $160 million from deferred tax liabilities to deferred tax assets on its Consolidated Balance Sheet at December 31, 2016.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Overview
EOG Resources, Inc., together with its subsidiaries (collectively, EOG), is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad and China. EOG operates under a consistent business and operational strategy that 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 deliver long-term growth in shareholder value and maintain a strong balance sheet. 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.
EOG realized a net loss of $605 million during 2020 as compared to net income of $2,735 million for 2019. At December 31, 2020, EOG's total estimated net proved reserves were 3,220 million barrels of oil equivalent (MMBoe), a decrease of 109 MMBoe from December 31, 2019. During 2020, net proved crude oil and condensate and natural gas liquids (NGLs) reserves decreased by 108 million barrels (MMBbl), and net proved natural gas reserves decreased by 9 billion cubic feet or 1 MMBoe, in each case from December 31, 2019.
Recent Developments
Commodity Prices. The COVID-19 pandemic and the measures being taken to address and limit the spread of the virus have adversely affected the economies and financial markets of the world, resulting in an economic downturn that has negatively impacted, and may continue to negatively impact, global demand and prices for crude oil and condensate, NGLs and natural gas. See ITEM 1A, Risk Factors for further discussion.
In early March 2020, due to the failure of the members of the Organization of the Petroleum Exporting Countries and Russia (OPEC+) to reach an agreement on individual crude oil production limits, Saudi Arabia unilaterally reduced the sales price of its crude oil and announced that it would increase its crude oil production. The combination of these actions, and the effects of the COVID-19 pandemic on crude oil demand, resulted in significantly lower commodity prices in March and April 2020. In April 2020, the members of OPEC+ reached an agreement to cut crude oil production beginning in May 2020 and extending through April 2022 with the quantity of the production cuts decreasing over time. Subsequent indications of conformity with these agreed-upon production cuts by OPEC+, combined with the evolving impacts of COVID-19 on crude oil demand, have resulted in gradually-improving market conditions. In the second half of 2020, crude oil prices increased, but remain significantly below average prices in 2019, as a result of the continuing rebalancing of crude oil supply resulting from the actions of OPEC+ and the continuing effect of the COVID-19 pandemic on global demand. In addition, NGL and natural gas prices have recovered to pre-pandemic levels.
In response to the commodity price environment in 2020, EOG reduced activity across its operating areas and decreased its total capital expenditures. EOG also elected to reduce crude oil production, by delaying initial production from new wells and shutting-in or otherwise curtailing existing production.
In early 2021, the members of OPEC+ met and agreed to taper off certain of their production curtailments (agreed to in April 2020) through March 2021. Subsequent to the meeting, Saudi Arabia announced that it would unilaterally cut its production by an additional one million barrels per day in February 2021 and March 2021. These announcements have had a positive impact on crude oil prices.
As a result of the many uncertainties associated with (i) the world economic environment, (ii) the COVID-19 pandemic and its continuing effect on the economies and financial markets of the world and (iii) any future actions by the members of OPEC+, and the effect of these uncertainties on worldwide supplies of, and demand for, crude oil and condensate, NGLs and natural gas, EOG is unable to predict what changes may occur in crude oil and condensate, NGLs and natural gas prices in the future. However, prices for crude oil and condensate, NGLs and natural gas have historically been volatile, and this volatility is expected to continue. For related discussion, see ITEM 1A, Risk Factors.
EOG will continue to monitor future market conditions and adjust its capital allocation strategy and production outlook accordingly in order to maximize shareholder value while maintaining its strong financial position.
2020 Election. In November 2020, Joseph R. Biden Jr. was elected President of the United States. 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 (i) 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 leasing practices and (ii) consider whether to adjust royalties associated with oil and gas resources extracted from federal lands and offshore waters to account for corresponding climate costs. In addition, 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 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. See "Regulation" in ITEM 1, Business and ITEM 1A, Risk Factors for further discussion.
EOG will continue to monitor and assess any actions that could impact the oil and gas industry, to determine the impact on its business and operations, and take appropriate actions where necessary.
Operations
Several important developments have occurred since January 1, 2020.
United States. EOG's efforts to identify plays with large reserve potential have proven to be successful. EOG continues to drill numerous wells in large acreage plays, which in the aggregate have contributed substantially to, and are expected to continue to contribute substantially to, EOG's crude oil and condensate, NGLs and natural gas production. EOG has placed an emphasis on applying its horizontal drilling and completion expertise to unconventional crude oil and liquids-rich reservoirs.
During 2020, EOG continued to focus on increasing drilling, completion and operating efficiencies gained in prior years. Such efficiencies, combined with new innovation and decreased service costs, resulted in lower operating, drilling and completion costs in 2020. In addition, EOG continued to evaluate certain potential crude oil and condensate, NGLs and natural gas exploration and development prospects and to look for opportunities to add drilling inventory through leasehold acquisitions, farm-ins, exchanges or tactical acquisitions. On a volumetric basis, as calculated using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas, crude oil and condensate and NGLs production accounted for approximately 76% and 77% of United States production during 2020 and 2019, respectively. During 2020, drilling and completion activities occurred primarily in the Delaware Basin play, Eagle Ford play and Rocky Mountain area. EOG's major producing areas in the United States are in New Mexico and Texas. In the second quarter of 2020, EOG delayed initial production from most newly-completed wells and shut in some existing production. During the third quarter of 2020, EOG resumed the process of initiating production from completed wells, and the legacy wells that were shut-in were largely brought back on-line. See ITEM 1, Business - Exploration and Production for further discussion.
Trinidad. In Trinidad, EOG continues to deliver natural gas under existing supply contracts. Several fields in the South East Coast Consortium Block, Modified U(a) Block, Block 4(a), Modified U(b) Block, the Banyan Field and the Sercan Area have been developed and are producing natural gas, which is sold to the National Gas Company of Trinidad and Tobago Limited and its subsidiary, and crude oil and condensate which is sold to Heritage Petroleum Company Limited.
In 2020, EOG drilled three net wells and completed two net wells in Trinidad. The remaining net well made a discovery that is being evaluated.
Other International. In the Sichuan Basin, Sichuan Province, China, EOG continues to work with its partner, PetroChina, under the Production Sharing Contract and other related agreements, to ensure uninterrupted production. All natural gas produced from the Baijaochang Field is sold under a long-term contract to PetroChina.
In 2020, EOG entered into two agreements related to exploration and production rights in the Sultanate of Oman (Oman). One agreement resulted in EOG acquiring exploration and production rights to Block 36 within Oman. The second agreement was a farm-in agreement allowing EOG to share in exploration and production rights within Block 49. Pursuant to that agreement, EOG participated in the drilling of one gross exploratory well which was in progress as of December 31, 2020.
In March 2020, EOG began the process of exiting its Canada operations.
EOG continues to evaluate other select crude oil and natural gas opportunities outside the United States, primarily by pursuing exploitation opportunities in countries where indigenous crude oil and natural gas reserves have been identified.
Capital Structure
One of management's key strategies is to maintain a strong balance sheet with a consistently below average debt-to-total capitalization ratio as compared to those in EOG's peer group. EOG's debt-to-total capitalization ratio was 22% at December 31, 2020 and 19% at December 31, 2019. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.
On April 1, 2020, EOG repaid upon maturity the $500 million aggregate principal amount of its 2.45% Senior Notes due 2020.
On April 14, 2020, EOG closed on its offering of $750 million aggregate principal amount of its 4.375% Senior Notes due 2030 and $750 million aggregate principal amount of its 4.950% Senior Notes due 2050 (together, the Notes). EOG received net proceeds of $1.48 billion from the issuance of the Notes, which were used to repay the 4.40% Senior Notes due 2020 when they matured on June 1, 2020 (see below), and for general corporate purposes, including the funding of capital expenditures.
On June 1, 2020, EOG repaid upon maturity the $500 million aggregate principal amount of its 4.40% Senior Notes due 2020.
On February 1, 2021, EOG repaid upon maturity the $750 million aggregate principal amount of its 4.100% Senior Notes due 2021.
During 2020, EOG funded $4.0 billion ($386 million of which was non-cash) in exploration and development and other property, plant and equipment expenditures (excluding asset retirement obligations), repaid $1.0 billion aggregate principal amount of long-term debt and paid $821 million in dividends to common stockholders, primarily by utilizing net cash provided from its operating activities, net proceeds of $1.48 billion from the issuance of the Notes and net proceeds of $192 million from the sale of assets.
Total anticipated 2021 capital expenditures are estimated to range from approximately $3.7 billion to $4.1 billion, excluding acquisitions and non-cash transactions. The majority of 2021 expenditures will be focused on United States crude oil drilling activities. EOG has significant flexibility with respect to financing alternatives, including borrowings under its commercial paper program, bank borrowings, borrowings under its senior unsecured revolving credit facility, joint development agreements and similar agreements and equity and debt offerings.
Management continues to believe EOG has one of the strongest prospect inventories in EOG's history. When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer incremental exploration and/or production opportunities.
Results of Operations
The following review of operations for each of the three years in the period ended December 31, 2020, should be read in conjunction with the consolidated financial statements of EOG and notes thereto beginning on page.
Operating Revenues and Other
During 2020, operating revenues decreased $6,348 million, or 37%, to $11,032 million from $17,380 million in 2019. Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, NGLs and natural gas, decreased $4,291, or 37%, to $7,290 million in 2020 from $11,581 million in 2019. Revenues from the sales of crude oil and condensate and NGLs in 2020 were approximately 89% of total wellhead revenues compared to 90% in 2019. During 2020, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $1,145 million compared to net gains of $180 million in 2019. Gathering, processing and marketing revenues decreased $2,777 million during 2020, to $2,583 million from $5,360 million in 2019. Net losses on asset dispositions of $47 million in 2020 were primarily due to the sales of proved properties and non-cash property exchanges of unproved leasehold in Texas and New Mexico and the disposition of the Marcellus Shale assets compared to net gains on asset dispositions of $124 million in 2019.
Wellhead volume and price statistics for the years ended December 31, 2020, 2019 and 2018 were as follows:
Year Ended December 31 2020 2019 2018
Crude Oil and Condensate Volumes (MBbld) (1)
United States 408.1 455.5 394.8
Trinidad 1.0 0.6 0.8
Other International (2)
0.1 0.1 4.3
Total 409.2 456.2 399.9
Average Crude Oil and Condensate Prices ($/Bbl) (3)
United States $ 38.65 $ 57.74 $ 65.16
Trinidad 30.20 47.16 57.26
Other International (2)
43.08 57.40 71.45
Composite 38.63 57.72 65.21
Natural Gas Liquids Volumes (MBbld) (1)
United States 136.0 134.1 116.1
Other International (2)
- - -
Total 136.0 134.1 116.1
Average Natural Gas Liquids Prices ($/Bbl) (3)
United States $ 13.41 $ 16.03 $ 26.60
Other International (2)
- - -
Composite 13.41 16.03 26.60
Natural Gas Volumes (MMcfd) (1)
United States 1,040 1,069 923
Trinidad 180 260 266
Other International (2)
32 37 30
Total 1,252 1,366 1,219
Average Natural Gas Prices ($/Mcf) (3)
United States $ 1.61 $ 2.22 $ 2.88
Trinidad 2.57 2.72 2.94
Other International (2)
4.66 4.44 4.08
Composite 1.83 2.38 2.92
Crude Oil Equivalent Volumes (MBoed) (4)
United States 717.5 767.8 664.7
Trinidad 30.9 44.0 45.1
Other International (2)
5.4 6.2 9.4
Total 753.8 818.0 719.2
Total MMBoe (4)
275.9 298.6 262.5
(1) Thousand barrels per day or million cubic feet per day, as applicable.
(2)Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.
(3)Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments (see Note 12 to Consolidated Financial Statements).
(4)Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas. 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 of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand.
2020 compared to 2019. Wellhead crude oil and condensate revenues in 2020 decreased $3,827 million, or 40%, to $5,786 million from $9,613 million in 2019, due primarily to a lower composite average wellhead crude oil and condensate price ($2,860 million) and a decrease in production ($967 million). EOG's composite wellhead crude oil and condensate price for 2020 decreased 33% to $38.63 per barrel compared to $57.72 per barrel in 2019. Wellhead crude oil and condensate production in 2020 decreased 10% to 409 MBbld as compared to 456 MBbld in 2019. The decreased production was primarily in the Eagle Ford and the Rocky Mountain area, partially offset by increased production in the Permian Basin.
NGLs revenues in 2020 decreased $116 million, or 15%, to $668 million from $784 million in 2019 primarily due to a lower composite average wellhead NGLs price ($130 million), partially offset by an increase in production ($13 million). EOG's composite average wellhead NGLs price decreased 16% to $13.41 per barrel in 2020 compared to $16.03 per barrel in 2019. NGL production in 2020 increased 1% to 136 MBbld as compared to 134 MBbld in 2019. The increased production was primarily in the Permian Basin, partially offset by decreased production in the Eagle Ford.
Wellhead natural gas revenues in 2020 decreased $347 million, or 29%, to $837 million from $1,184 million in 2019, primarily due to a lower composite wellhead natural gas price ($251 million) and a decrease in natural gas deliveries ($96 million). EOG's composite average wellhead natural gas price decreased 23% to $1.83 per Mcf in 2020 compared to $2.38 per Mcf in 2019. Natural gas deliveries in 2020 decreased 8% to 1,252 MMcfd as compared to 1,366 MMcfd in 2019. The decrease in production was primarily due to lower natural gas volumes in Trinidad, the Marcellus Shale and the Rocky Mountain area, partially offset by increased production of associated natural gas from the Permian Basin.
During 2020, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $1,145 million, which included net cash received for settlements of crude oil, NGL and natural gas financial derivative contracts of $1,071 million. During 2019, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $180 million, which included net cash received for settlements of crude oil and natural gas financial derivative contracts of $231 million.
Gathering, processing and marketing revenues are revenues generated from sales of third-party crude oil, NGLs and natural gas, as well as fees associated with gathering third-party natural gas and revenues from sales of EOG-owned sand. Purchases and sales of third-party crude oil and natural gas may be utilized in order to balance firm transportation capacity with production in certain areas and to utilize excess capacity at EOG-owned facilities. EOG sells sand in order to balance the timing of firm purchase agreements with completion operations and to utilize excess capacity at EOG-owned facilities. Marketing costs represent the costs to purchase third-party crude oil, natural gas and sand and the associated transportation costs, as well as costs associated with EOG-owned sand sold to third parties.
Gathering, processing and marketing revenues less marketing costs in 2020 decreased $124 million compared to 2019, primarily due to lower margins on crude oil and condensate marketing activities. The margin on crude oil marketing activities in 2020 was negatively impacted by the price decline for crude oil in inventory awaiting delivery to customers and EOG's decision early in the second quarter of 2020 to reduce commodity price volatility by selling May and June 2020 deliveries under fixed price arrangements.
2019 compared to 2018. Wellhead crude oil and condensate revenues in 2019 increased $96 million, or 1%, to $9,613 million from $9,517 million in 2018, due primarily to an increase in production ($1,351 million); partially offset by a lower composite average wellhead crude oil and condensate price ($1,255 million). EOG's composite wellhead crude oil and condensate price for 2019 decreased 11% to $57.72 per barrel compared to $65.21 per barrel in 2018. Wellhead crude oil and condensate production in 2019 increased 14% to 456 MBbld as compared to 400 MBbld in 2018. The increased production was primarily in the Permian Basin and the Eagle Ford.
NGLs revenues in 2019 decreased $343 million, or 30%, to $784 million from $1,127 million in 2018 primarily due to a lower composite average wellhead NGLs price ($518 million), partially offset by an increase in production ($175 million). EOG's composite average wellhead NGLs price decreased 40% to $16.03 per barrel in 2019 compared to $26.60 per barrel in 2018. NGL production in 2019 increased 16% to 134 MBbld as compared to 116 MBbld in 2018. The increased production was primarily in the Permian Basin.
Wellhead natural gas revenues in 2019 decreased $118 million, or 9%, to $1,184 million from $1,302 million in 2018, primarily due to a lower composite wellhead natural gas price ($280 million), partially offset by an increase in natural gas deliveries ($162 million). EOG's composite average wellhead natural gas price decreased 18% to $2.38 per Mcf in 2019 compared to $2.92 per Mcf in 2018. Natural gas deliveries in 2019 increased 12% to 1,366 MMcfd as compared to 1,219 MMcfd in 2018. The increase in production was primarily due to higher deliveries in the United States resulting from increased production of associated natural gas from the Permian Basin and higher natural gas volumes in South Texas.
During 2019, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $180 million, which included net cash received for settlements of crude oil and natural gas financial derivative contracts of $231 million. During 2018, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $166 million, which included net cash paid for settlements of crude oil and natural gas financial derivative contracts of $259 million.
Gathering, processing and marketing revenues less marketing costs in 2019 decreased $18 million compared to 2018, primarily due to lower margins on crude oil and condensate marketing activities, partially offset by higher margins on natural gas marketing activities.
Operating and Other Expenses
2020 compared to 2019. During 2020, operating expenses of $11,576 million were $2,105 million lower than the $13,681 million incurred during 2019. The following table presents the costs per barrel of oil equivalent (Boe) for the years ended December 31, 2020 and 2019:
2020 2019
Lease and Well $ 3.85 $ 4.58
Transportation Costs 2.66 2.54
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties 11.85 12.25
Other Property, Plant and Equipment 0.47 0.31
General and Administrative (G&A) 1.75 1.64
Net Interest Expense 0.74 0.62
Total (1)
$ 21.32 $ 21.94
(1)Total excludes gathering and processing costs, exploration costs, dry hole costs, impairments, marketing costs and taxes other than income.
The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A, G&A and net interest expense for 2020 compared to 2019 are set forth below. See "Operating Revenues and Other" above for a discussion of production volumes.
Lease and well expenses include expenses for EOG-operated properties, as well as expenses billed to EOG from other operators where EOG is not the operator of a property. Lease and well expenses can be divided into the following categories: costs to operate and maintain crude oil and natural gas wells, the cost of workovers and lease and well administrative expenses. Operating and maintenance costs include, among other things, pumping services, salt water disposal, equipment repair and maintenance, compression expense, lease upkeep and fuel and power. Workovers are operations to restore or maintain production from existing wells.
Each of these categories of costs individually fluctuates from time to time as EOG attempts to maintain and increase production while maintaining efficient, safe and environmentally responsible operations. EOG continues to increase its operating activities by drilling new wells in existing and new areas. Operating and maintenance costs within these existing and new areas, as well as the costs of services charged to EOG by vendors, fluctuate over time.
Lease and well expenses of $1,063 million in 2020 decreased $304 million from $1,367 million in 2019 primarily due to lower operating and maintenance costs in the United States ($157 million) and in Canada ($25 million), lower workovers expenditures in the United States ($103 million) and lower lease and well administrative expenses in the United States ($12 million). Lease and well expenses decreased in the United States primarily due to decreased operating activities resulting from decreased production, efficiency improvements and service cost reductions.
Transportation costs represent costs associated with the delivery of hydrocarbon products from the lease or an aggregation point on EOG's gathering system to a downstream point of sale. Transportation costs include transportation fees, the cost of compression (the cost of compressing natural gas to meet pipeline pressure requirements), the cost of dehydration (the cost associated with removing water from natural gas to meet pipeline requirements), gathering fees and fuel costs.
Transportation costs of $735 million in 2020 decreased $23 million from $758 million in 2019 primarily due to decreased transportation costs in the Fort Worth Basin Barnett Shale ($27 million), the Rocky Mountain area ($24 million) and the Eagle Ford ($20 million), partially offset by increased transportation costs in the Permian Basin ($56 million).
DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method. EOG's DD&A rate and expense are the composite of numerous individual DD&A group calculations. There are several factors that can impact EOG's composite DD&A rate and expense, such as field production profiles, drilling or acquisition of new wells, disposition of existing wells and reserve revisions (upward or downward) primarily related to well performance, economic factors and impairments. Changes to these factors may cause EOG's composite DD&A rate and expense to fluctuate from period to period. DD&A of the cost of other property, plant and equipment is generally calculated using the straight-line depreciation method over the useful lives of the assets.
DD&A expenses in 2020 decreased $350 million to $3,400 million from $3,750 million in 2019. DD&A expenses associated with oil and gas properties in 2020 were $390 million lower than in 2019 primarily due to a decrease in production in the United States ($222 million) and Trinidad ($22 million) and lower unit rates in the United States ($150 million). Unit rates in the United States decreased primarily due to upward reserve revisions and reserves added at lower costs as a result of increased efficiencies. DD&A expenses associated with other property, plant and equipment in 2020 were $40 million higher than in 2019 primarily due to an increase in expense related to gathering and storage assets and equipment.
G&A expenses of $484 million in 2020 decreased $5 million from $489 million in 2019 primarily due to decreased employee-related expenses ($43 million) and professional and other services ($7 million), partially offset by idle equipment and termination fees ($46 million).
Net interest expense of $205 million in 2020 was $20 million higher than 2019 primarily due to the issuance of the Notes in April 2020 ($51 million) and lower capitalized interest ($7 million), partially offset by repayment in June 2019 of the $900 million aggregate principal amount of 5.625% Senior Notes due 2019 ($21 million), repayment in June 2020 of the $500 million aggregate principal amount of 4.40% Senior Notes due 2020 ($13 million) and repayment in April 2020 of the $500 million aggregate principal amount of 2.45% Senior Notes due 2020 ($10 million).
Gathering and processing costs represent operating and maintenance expenses and administrative expenses associated with operating EOG's gathering and processing assets as well as natural gas processing fees and certain NGLs fractionation fees paid to third parties. EOG pays third parties to process the majority of its natural gas production to extract NGLs.
Gathering and processing costs decreased $20 million to $459 million in 2020 compared to $479 million in 2019 primarily due to decreased operating costs in the Eagle Ford ($16 million) and decreased gathering and processing fees in the Eagle Ford ($9 million) and the Fort Worth Basin Barnett Shale ($5 million); partially offset by increased gathering and processing fees in the Permian Basin ($15 million).
Exploration costs of $146 million in 2020 increased $6 million from $140 million in 2019 primarily due to increased geological and geophysical expenditures in the United States ($15 million), partially offset by decreased general and administrative expenses in the United States ($8 million).
Impairments include: amortization of unproved oil and gas property costs as well as impairments of proved oil and gas properties; other property, plant and equipment; and other assets. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. Unproved properties with individually significant acquisition costs are reviewed individually for impairment. When circumstances indicate that a proved property may be impaired, EOG compares expected undiscounted future cash flows at a DD&A group level to the unamortized capitalized cost of the asset. If the expected undiscounted future cash flows, based on EOG's estimates of (and assumptions regarding) future crude oil, NGLs and natural gas prices, operating costs, development expenditures, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated by using the Income Approach described in the Fair Value Measurement Topic of the Financial Accounting Standards Board's Accounting Standards Codification (ASC). In certain instances, EOG utilizes accepted offers from third-party purchasers as the basis for determining fair value.
The following table represents impairments for the years ended December 31, 2020 and 2019 (in millions):
2020 2019
Proved properties $ 1,268 $ 207
Unproved properties 472 220
Other assets 300 91
Firm commitment contracts 60 -
Total $ 2,100 $ 518
Impairments of proved properties were primarily due to the write-down to fair value of legacy and non-core natural gas and crude oil and combo plays in 2020 and legacy natural gas assets in 2019.
Taxes other than income include severance/production taxes, ad valorem/property taxes, payroll taxes, franchise taxes and other miscellaneous taxes. Severance/production taxes are generally determined based on wellhead revenues, and ad valorem/property taxes are generally determined based on the valuation of the underlying assets.
Taxes other than income in 2020 decreased $322 million to $478 million (6.6% of wellhead revenues) from $800 million (6.9% of wellhead revenues) in 2019. The decrease in taxes other than income was primarily due to decreased severance/production taxes in the United States ($232 million), decreased ad valorem/property taxes in the United States ($51 million) and a state severance tax refund ($27 million).
Other income, net, was $10 million in 2020 compared to other income, net, of $31 million in 2019. The decrease of $21 million in 2020 was primarily due to a decrease in interest income.
In response to the economic impacts of the COVID-19 pandemic, the President of the United States signed the Coronavirus Aid, Relief, and Economic Security Act (the CARES Act) into law on March 27, 2020. The CARES Act provides economic support to individuals and businesses through enhanced loan programs, expanded unemployment benefits, and certain payroll and income tax relief, among other provisions. The primary tax benefit of the CARES Act for EOG was the acceleration of approximately $150 million of additional refundable alternative minimum tax (AMT) credits into tax year 2019. These credits originated from AMT paid by EOG in years prior to 2018 and were reflected as a deferred tax asset and a non-current receivable as of December 31, 2019 since they had been expected to either offset future current tax liabilities or be refunded on a declining balance schedule through 2021. The $150 million of additional refundable AMT credits was received in July 2020.
Further pandemic relief was contained in the Consolidated Appropriations Act of 2021 (the CA Act) which was signed into law by the President of the United States on December 27, 2020. In addition, the CA Act provided government funding and limited corporate income tax relief primarily related to making permanent or extending certain tax provisions, none of which were a material benefit for EOG.
EOG recognized an income tax benefit of $135 million in 2020 compared to an income tax provision of $810 million in 2019, primarily due to decreased pretax income. The net effective tax rate for 2020 decreased to 18% from 23% in 2019. The lower effective tax rate is mostly due to taxes attributable to EOG's foreign operations and increased stock-based compensation tax deficiencies.
2019 compared to 2018. During 2019, operating expenses of $13,681 million were $875 million higher than the $12,806 million incurred during 2018. The following table presents the costs per Boe for the years ended December 31, 2019 and 2018:
2019 2018
Lease and Well $ 4.58 $ 4.89
Transportation Costs 2.54 2.85
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties 12.25 12.65
Other Property, Plant and Equipment 0.31 0.44
General and Administrative (G&A) 1.64 1.63
Net Interest Expense 0.62 0.93
Total (1)
$ 21.94 $ 23.39
(1)Total excludes gathering and processing costs, exploration costs, dry hole costs, impairments, marketing costs and taxes other than income.
The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A, G&A and net interest expense for 2019 compared to 2018 are set forth below. See "Operating Revenues and Other" above for a discussion of production volumes.
Lease and well expenses of $1,367 million in 2019 increased $84 million from $1,283 million in 2018 primarily due to higher operating and maintenance costs ($76 million) and higher lease and well administrative expenses ($29 million) in the United States, partially offset by lower operating and maintenance costs in the United Kingdom ($15 million) due to the sale of operations in the fourth quarter of 2018 and in Canada ($11 million). Lease and well expenses increased in the United States primarily due to increased operating activities resulting in increased production.
Transportation costs of $758 million in 2019 increased $11 million from $747 million in 2018 primarily due to increased transportation costs in the Permian Basin ($91 million) and South Texas ($11 million), partially offset by decreased transportation costs in the Eagle Ford ($77 million) and the Fort Worth Basin Barnett Shale ($13 million).
DD&A expenses in 2019 increased $315 million to $3,750 million from $3,435 million in 2018. DD&A expenses associated with oil and gas properties in 2019 were $337 million higher than in 2018 primarily due to an increase in production in the United States ($489 million), partially offset by lower unit rates in the United States ($119 million) and the sale of the United Kingdom operations in the fourth quarter of 2018 ($33 million). Unit rates in the United States decreased primarily due to upward reserve revisions and reserves added at lower costs as a result of increased efficiencies.
G&A expenses of $489 million in 2019 increased $62 million from $427 million in 2018 primarily due to increased employee-related expenses ($48 million) and increased information systems costs ($8 million) resulting from expanded operations.
Net interest expense of $185 million in 2019 was $60 million lower than 2018 primarily due to repayment of the $900 million aggregate principal amount of 5.625% Senior Notes due 2019 in June 2019 ($30 million) and the $350 million aggregate principal amount of 6.875% Senior Notes due 2018 in October 2018 ($18 million) and an increase in capitalized interest ($14 million).
Gathering and processing costs increased $42 million to $479 million in 2019 compared to $437 million in 2018 primarily due to increased operating costs and fees in the Permian Basin ($52 million), the Rocky Mountain area ($13 million) and South Texas ($5 million); partially offset by decreased operating costs in the United Kingdom ($33 million) due to the sale of operations in the fourth quarter of 2018.
Exploration costs of $140 million in 2019 decreased $9 million from $149 million in 2018 primarily due to decreased geological and geophysical expenditures in the Trinidad ($17 million), partially offset by increased general and administrative expenses in the United States ($7 million).
The following table represents impairments for the years ended December 31, 2019 and 2018 (in millions):
2019 2018
Proved properties $ 207 $ 121
Unproved properties 220 173
Other assets 91 49
Inventories - 4
Total $ 518 $ 347
Impairments of proved properties were primarily due to the write-down to fair value of legacy natural gas assets in 2019 and 2018.
Taxes other than income in 2019 increased $28 million to $800 million (6.9% of wellhead revenues) from $772 million (6.5% of wellhead revenues) in 2018. The increase in taxes other than income was primarily due to an increase in ad valorem/property taxes ($53 million), partially offset by an increase in credits available to EOG in 2019 for state incentive severance tax rate reductions ($12 million) and a decrease in severance/production taxes ($12 million) primarily as a result of decreased wellhead revenues, all in the United States.
Other income, net, was $31 million in 2019 compared to other income, net, of $17 million in 2018. The increase of $14 million in 2019 was primarily due to an increase in interest income ($14 million) and an increase in foreign currency transaction gains ($9 million), partially offset by an increase in deferred compensation expense ($4 million).
EOG recognized an income tax provision of $810 million in 2019 compared to an income tax provision of $822 million in 2018, primarily due to decreased pretax income, partially offset by the absence of tax benefits from certain tax reform measurement-period adjustments. The net effective tax rate for 2019 increased to 23% from 19% in the prior year, primarily due to the absence of tax benefits from certain tax reform measurement-period adjustments.
Capital Resources and Liquidity
Cash Flow
The primary sources of cash for EOG during the three-year period ended December 31, 2020, were funds generated from operations, net proceeds from the issuance of long-term debt, net cash received from settlements of commodity derivative contracts and proceeds from asset sales. The primary uses of cash were funds used in operations; exploration and development expenditures; repayments of debt; dividend payments to stockholders and other property, plant and equipment expenditures.
2020 compared to 2019. Net cash provided by operating activities of $5,008 million in 2020 decreased $3,155 million from $8,163 million in 2019 primarily due to a decrease in wellhead revenues ($4,291 million); unfavorable changes in working capital and other assets and liabilities ($166 million); a decrease in gathering, processing and marketing revenues less marketing costs ($124 million) and an increase in net cash paid for income taxes ($86 million); partially offset by an increase in cash received for settlements of commodity derivative contracts ($840 million) and a decrease in cash operating expenses ($641 million).
Net cash used in investing activities of $3,348 million in 2020 decreased by $2,829 million from $6,177 million in 2019 primarily due to a decrease in additions to oil and gas properties ($2,908 million); an increase in proceeds from the sale of assets ($52 million); a decrease in additions to other property, plant and equipment ($49 million); and a decrease in other investing activities ($10 million); partially offset by an unfavorable change in working capital associated with investing activities ($190 million).
Net cash used in financing activities of $359 million in 2020 included repayments of long-term debt ($1,000 million), cash dividend payments ($821 million), repayment of finance lease liabilities ($19 million) and purchases of treasury stock in connection with stock compensation plans ($16 million). Cash provided by financing activities in 2020 included long-term debt borrowings ($1,484 million) and proceeds from stock options exercised and employee stock purchase plan activity ($16 million).
2019 compared to 2018. Net cash provided by operating activities of $8,163 million in 2019 increased $394 million from $7,769 million in 2018 primarily reflecting an increase in cash received for settlements of commodity derivative contracts ($490 million), a decrease in net cash paid for income taxes ($367 million) and favorable changes in working capital and other assets and liabilities ($122 million); partially offset by a decrease in wellhead revenues ($365 million) and an increase in cash operating expenses ($202 million).
Net cash used in investing activities of $6,177 million in 2019 increased by $7 million from $6,170 million in 2018 primarily due to an increase in additions to oil and gas properties ($313 million), a decrease in proceeds from the sale of assets ($87 million) and an increase in additions to other property, plant and equipment ($33 million); partially offset by favorable changes in working capital associated with investing activities ($416 million) and a decrease in other investing activities ($10 million).
Net cash used in financing activities of $1,513 million in 2019 included repayments of long-term debt ($900 million), cash dividend payments ($588 million) and purchases of treasury stock in connection with stock compensation plans ($25 million). Cash provided by financing activities in 2019 included proceeds from stock options exercised and employee stock purchase plan activity ($18 million).
Total Expenditures
The table below sets out components of total expenditures for the years ended December 31, 2020, 2019 and 2018 (in millions):
2020 2019 2018
Expenditure Category
Capital
Exploration and Development Drilling $ 2,664 $ 4,951 $ 4,935
Facilities 347 629 625
Leasehold Acquisitions (1)
265 276 488
Property Acquisitions (2)
135 380 124
Capitalized Interest 31 38 24
Subtotal 3,442 6,274 6,196
Exploration Costs 146 140 149
Dry Hole Costs 13 28 5
Exploration and Development Expenditures 3,601 6,442 6,350
Asset Retirement Costs 117 186 70
Total Exploration and Development Expenditures 3,718 6,628 6,420
Other Property, Plant and Equipment (3)
395 272 286
Total Expenditures $ 4,113 $ 6,900 $ 6,706
(1)Leasehold acquisitions included $197 million, $98 million and $291 million related to non-cash property exchanges in 2020, 2019 and 2018, respectively.
(2)Property acquisitions included $15 million, $52 million and $71 million related to non-cash property exchanges in 2020, 2019 and 2018, respectively.
(3)Other property, plant and equipment included non-cash additions of $174 million, primarily related to finance lease transactions for storage facilities, and $49 million, primarily related to a finance lease transaction in the Permian Basin, in 2020 and 2018, respectively.
Exploration and development expenditures of $3,601 million for 2020 were $2,841 million lower than the prior year. The decrease was primarily due to decreased exploration and development drilling expenditures in the United States ($2,309 million), decreased facilities expenditures ($282 million) and decreased property acquisitions ($245 million), partially offset by increased exploration and development drilling expenditures in Trinidad ($27 million). The 2020 exploration and development expenditures of $3,601 million included $2,905 million in development drilling and facilities, $530 million in exploration, $135 million in property acquisitions and $31 million in capitalized interest. The 2019 exploration and development expenditures of $6,442 million included $5,513 million in development drilling and facilities, $511 million in exploration, $380 million in property acquisitions and $38 million in capitalized interest. The 2018 exploration and development expenditures of $6,350 million included $5,546 million in development drilling and facilities, $656 million in exploration, $124 million in property acquisitions and $24 million in capitalized interest.
The level of exploration and development expenditures, including acquisitions, will vary in future periods depending on energy market conditions and other economic factors. EOG believes it has significant flexibility and availability with respect to financing alternatives and the ability to adjust its exploration and development expenditure budget as circumstances warrant. While EOG has certain continuing commitments associated with expenditure plans related to its operations, such commitments are not expected to be material when considered in relation to the total financial capacity of EOG.
Commodity Derivative Transactions
Crude Oil Derivative Contracts. Prices received by EOG for its crude oil production generally vary from U.S. New York Mercantile Exchange (NYMEX) West Texas Intermediate (WTI) prices due to adjustments for delivery location (basis) and other factors. EOG has entered into crude oil basis swap contracts in order to fix the differential between Intercontinental Exchange (ICE) Brent pricing and pricing in Cushing, Oklahoma (ICE Brent Differential). Presented below is a comprehensive summary of EOG's ICE Brent Differential basis swap contracts through February 18, 2021. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts.
ICE Brent Differential Basis Swap Contracts
Volume (Bbld) Weighted Average Price Differential
($/Bbl)
May 2020 (closed) 10,000 $ 4.92
EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in Houston, Texas, and Cushing, Oklahoma (Houston Differential). Presented below is a comprehensive summary of EOG's Houston Differential basis swap contracts through February 18, 2021. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts.
Houston Differential Basis Swap Contracts
Volume (Bbld) Weighted Average Price Differential
($/Bbl)
May 2020 (closed) 10,000 $ 1.55
EOG has also entered into crude oil swaps in order to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month (Roll Differential). Presented below is a comprehensive summary of EOG's Roll Differential basis swap contracts through February 18, 2021. The weighted average price differential expressed in $/Bbl represents the amount of net addition (reduction) to delivery month prices for the notional volumes expressed in Bbld covered by the swap contracts.
Roll Differential Basis Swap Contracts
Volume (Bbld) Weighted Average Price Differential
($/Bbl)
February 1, 2020 through June 30, 2020 (closed) 10,000 $ 0.70
July 1, 2020 through September 30, 2020 (closed) 88,000 (1.16)
October 1, 2020 through December 31, 2020 (closed) 66,000 (1.16)
February 2021 (closed) 30,000 $ 0.11
March 1, 2021 through December 31, 2021 125,000 0.17
January 1, 2022 through December 31, 2022 125,000 $ 0.15
In May 2020, EOG entered into crude oil Roll Differential basis swap contracts for the period from July 1, 2020 through September 30, 2020, with notional volumes of 22,000 Bbld at a weighted average price differential of $(0.43) per Bbl, and for the period from October 1, 2020 through December 31, 2020, with notional volumes of 44,000 Bbld at a weighted average price differential of $(0.73) per Bbl. These contracts partially offset certain outstanding Roll Differential basis swap contracts for the same time periods and volumes at a weighted average price differential of $(1.16) per Bbl. EOG paid net cash of $3.2 million for the settlement of these contracts. The offsetting contracts were excluded from the above table.
Presented below is a comprehensive summary of EOG's crude oil NYMEX WTI price swap contracts through February 18, 2021, with notional volumes expressed in Bbld and prices expressed in $/Bbl.
Crude Oil NYMEX WTI Price Swap Contracts
Volume (Bbld) Weighted Average Price ($/Bbl)
January 1, 2020 through March 31, 2020 (closed) 200,000 $ 59.33
April 1, 2020 through May 31, 2020 (closed) 265,000 51.36
January 2021 (closed) 151,000 $ 50.06
February 1, 2021 through March 31, 2021 201,000 51.29
April 1, 2021 through June 30, 2021 150,000 51.68
July 1, 2021 through September 30, 2021 150,000 52.71
In April and May 2020, EOG entered into crude oil NYMEX WTI price swap contracts for the period from June 1, 2020 through June 30, 2020, with notional volumes of 265,000 Bbld at a weighted average price of $33.80 per Bbl, for the period from July 1, 2020 through July 31, 2020, with notional volumes of 254,000 Bbld at a weighted average price of $33.75 per Bbl, for the period from August 1, 2020 through September 30, 2020, with notional volumes of 154,000 Bbld at a weighted average price of $34.18 per Bbl and for the period from October 1, 2020 through December 31, 2020, with notional volumes of 47,000 Bbld at a weighted average price of $30.04 per Bbl. These contracts offset the remaining crude oil NYMEX WTI price swap contracts for the same time periods and volumes at a weighted average price of $51.36 per Bbl for the period from June 1, 2020 through June 30, 2020, $42.36 per Bbl for the period from July 1, 2020 through July 31, 2020, $50.42 per Bbl for the period from August 1, 2020 through September 30, 2020 and $31.00 per Bbl for the period from October 1, 2020 through December 31, 2020. EOG received net cash of $364.0 million for the settlement of these contracts. The offsetting contracts were excluded from the above table.
Presented below is a comprehensive summary of EOG's crude oil ICE Brent price swap contracts through February 18, 2021, with notional volumes expressed in Bbld and prices expressed in $/Bbl.
Crude Oil ICE Brent Price Swap Contracts
Volume (Bbld) Weighted Average Price ($/Bbl)
April 2020 (closed) 75,000 $ 25.66
May 2020 (closed) 35,000 26.53
NGLs Derivative Contracts. Presented below is a comprehensive summary of EOG's Mont Belvieu propane (non-TET) price swap contracts through February 18, 2021, with notional volumes expressed in Bbld and prices expressed in $/Bbl.
Mont Belvieu Propane Price Swap Contracts
Volume (Bbld) Weighted Average Price ($/Bbl)
January 1, 2020 through February 29, 2020 (closed) 4,000 $ 21.34
March 1, 2020 through April 30, 2020 (closed) 25,000 17.92
January 2021 (closed) 15,000 $ 29.44
February 1, 2021 through December 31, 2021 15,000 29.44
In April and May 2020, EOG entered into Mont Belvieu propane price swap contracts for the period from May 1, 2020 through December 31, 2020, with notional volumes of 25,000 Bbld at a weighted average price of $16.41 per Bbl. These contracts offset the remaining Mont Belvieu propane price swap contracts for the same time period with notional volumes of 25,000 Bbld at a weighted average price of $17.92 per Bbl. EOG received net cash of $9.2 million for the settlement of these contracts. The offsetting contracts were excluded from the above table.
Natural Gas Derivative Contracts. Presented below is a comprehensive summary of EOG's natural gas NYMEX Henry Hub price swap contracts through February 18, 2021, with notional volumes sold (purchased) expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu). In January 2021, EOG executed the early termination provision granting EOG the right to terminate certain 2022 natural gas NYMEX Henry Hub price swap contracts with notional volumes of 20,000 MMBtud at a weighted average price of $2.75 per MMBtu for the period from January 1, 2022 through December 31, 2022. EOG received net cash of $0.6 million for the settlement of these contracts.
Natural Gas NYMEX Henry Hub Price Swap Contracts
Volume (MMBtud) Weighted Average Price ($/MMBtu)
April 1, 2021 through September 30, 2021 (70,000) $ 2.64
January 1, 2022 through December 31, 2022 (closed) 20,000 $ 2.75
In December 2020 and January 2021, EOG entered into natural gas NYMEX Henry Hub price swap contracts for the period from January 1, 2021 through March 31, 2021, with notional volumes of 500,000 MMBtud at a weighted average price of $2.43 per MMBtu and for the period from April 1, 2021 through December 31, 2021, with notional volumes of 500,000 MMBtud at a weighted average price of $2.83 per MMBtu. These contracts offset the remaining natural gas NYMEX Henry Hub price swap contracts for the same time periods with notional volumes of 500,000 MMBtud at a weighted average price of $2.99 per MMBtu. EOG received net cash of $16.5 million through February 18, 2021, for the settlement of certain of these contracts, and expects to receive net cash of $30.3 million during the remainder of 2021 for the settlement of the remaining contracts. The offsetting contracts were excluded from the above table.
Presented below is a comprehensive summary of EOG's natural gas Japan Korea Marker (JKM) price swap contracts through February 18, 2021, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.
Natural Gas JKM Price Swap Contracts
Volume (MMBtud) Weighted Average Price ($/MMBtu)
April 1, 2021 through September 30, 2021 70,000 $ 6.65
EOG has entered into natural gas collar contracts, which establish ceiling and floor prices for the sale of notional volumes of natural gas as specified in the collar contracts. The collars require that EOG pay the difference between the ceiling price and the Henry Hub Index Price in the event the Henry Hub Index Price is above the ceiling price. The collars grant EOG the right to receive the difference between the floor price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the floor price. In March 2020, EOG executed the early termination provision granting EOG the right to terminate certain 2020 natural gas collar contracts with notional volumes of 250,000 MMBtud at a weighted average ceiling price of $2.50 per MMBtu and a weighted average floor price of $2.00 per MMBtu for the period from April 1, 2020 through July 31, 2020. EOG received net cash of $7.8 million for the settlement of these contracts. Presented below is a comprehensive summary of EOG's natural gas collar contracts through February 18, 2021, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.
Natural Gas Collar Contracts
Weighted Average Price ($/MMBtu)
Volume (MMBtud) Ceiling Price Floor Price
April 1, 2020 through July 31, 2020 (closed) 250,000 $ 2.50 $ 2.00
In April 2020, EOG entered into natural gas collar contracts for the period from August 1, 2020 through October 31, 2020, with notional volumes of 250,000 MMBtud at a ceiling price of $2.50 per MMBtu and a floor price of $2.00 per MMBtu. These contracts offset the remaining natural gas collar contracts for the same time period with notional volumes of 250,000 MMBtud at a ceiling price of $2.50 per MMBtu and a floor price of $2.00 per MMBtu. EOG received net cash of $1.1 million for the settlement of these contracts. The offsetting contracts were excluded from the above table.
Prices received by EOG for its natural gas production generally vary from NYMEX Henry Hub prices due to adjustments for delivery location (basis) and other factors. EOG has entered into natural gas basis swap contracts in order to fix the differential between pricing in the Rocky Mountain area and NYMEX Henry Hub prices (Rockies Differential). Presented below is a comprehensive summary of EOG's Rockies Differential basis swap contracts through February 18, 2021. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts.
Rockies Differential Basis Swap Contracts
Volume (MMBtud) Weighted Average Price Differential
($/MMBtu)
January 1, 2020 through December 31, 2020 (closed) 30,000 $ 0.55
EOG has also entered into natural gas basis swap contracts in order to fix the differential between pricing at the Houston Ship Channel (HSC) and NYMEX Henry Hub prices (HSC Differential). In March 2020, EOG executed the early termination provision granting EOG the right to terminate certain 2020 HSC Differential basis swaps with notional volumes of 60,000 MMBtud at a weighted average price differential of $0.05 per MMBtu for the period from April 1, 2020 through December 31, 2020. EOG paid net cash of $0.4 million for the settlement of these contracts. Presented below is a comprehensive summary of EOG's HSC Differential basis swap contracts through February 18, 2021. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts.
HSC Differential Basis Swap Contracts
Volume (MMBtud) Weighted Average Price Differential
($/MMBtu)
January 1, 2020 through December 31, 2020 (closed) 60,000 $ 0.05
EOG has also entered into natural gas basis swap contracts in order to fix the differential between pricing at the Waha Hub in West Texas and NYMEX Henry Hub prices (Waha Differential). Presented below is a comprehensive summary of EOG's Waha Differential basis swap contracts through February 18, 2021. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts.
Waha Differential Basis Swap Contracts
Volume (MMBtud) Weighted Average Price Differential
($/MMBtu)
January 1, 2020 through April 30, 2020 (closed) 50,000 $ 1.40
In April 2020, EOG entered into Waha Differential basis swap contracts for the period from May 1, 2020 through December 31, 2020, with notional volumes of 50,000 MMBtud at a weighted average price differential of $0.43 per MMBtu. These contracts offset the remaining Waha Differential basis swap contracts for the same time period with notional volumes of 50,000 MMBtud at a weighted average price differential of $1.40 per MMBtu. EOG paid net cash of $11.9 million for the settlement of these contracts. The offsetting contracts were excluded from the above table.
Financing
EOG's debt-to-total capitalization ratio was 22% at December 31, 2020, compared to 19% at December 31, 2019. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.
At December 31, 2020 and 2019, respectively, EOG had outstanding $5,640 million and $5,140 million aggregate principal amount of senior notes which had estimated fair values of $6,505 million and $5,452 million, respectively. The estimated fair value of debt was based upon quoted market prices and, where such prices were not available, other observable inputs regarding interest rates available to EOG at year-end. EOG's debt is at fixed interest rates. While changes in interest rates affect the fair value of EOG's senior notes, such changes do not expose EOG to material fluctuations in earnings or cash flow.
During 2020, EOG funded its capital program and operations primarily by utilizing cash provided by operating activities, issuance of the Notes and proceeds from asset sales. While EOG maintains a $2.0 billion revolving credit facility to back its commercial paper program, there were no borrowings outstanding at any time during 2020 and the amount outstanding at year-end was zero. EOG considers the availability of its $2.0 billion senior unsecured revolving credit facility, as described in Note 2 to Consolidated Financial Statements, to be sufficient to meet its ongoing operating needs.
Contractual Obligations
The following table summarizes EOG's contractual obligations at December 31, 2020 (in millions):
Contractual Obligations (1)
Total 2021 2022-2023 2024-2025 2026 & Beyond
Current and Long-Term Debt $ 5,640 $ 750 $ 1,250 $ 500 $ 3,140
Interest Payments on Long-Term Debt 2,297 207 366 309 1,415
Finance Leases (2)
239 36 60 56 87
Operating Leases (2)
1,039 323 344 166 206
Leases Effective, Not Commenced (2)
100 14 28 22 36
Transportation and Storage Service Commitments (3)
6,665 964 1,830 1,296 2,575
Purchase and Service Obligations 1,258 429 497 143 189
Total Contractual Obligations $ 17,238 $ 2,723 $ 4,375 $ 2,492 $ 7,648
(1)This table does not include the liability for unrecognized tax benefits, EOG's pension or postretirement benefit obligations or liability for dismantlement, abandonment and asset retirement obligations (see Notes 6, 7 and 15, respectively, to Consolidated Financial Statements). These amounts are excluded because they are subject to estimates and the timing of settlement is unknown.
(2)For more information on contracts that meet the definition of a lease under ASU 2016-02, see Note 18 to Consolidated Financial Statements.
(3)Amounts exclude transportation and storage service commitments that meet the definition of a lease. Amounts shown are based on current transportation and storage rates and the foreign currency exchange rates used to convert Canadian dollars into United States dollars at December 31, 2020. Management does not believe that any future changes in these rates before the expiration dates of these commitments will have a material adverse effect on the financial condition or results of operations of EOG.
Off-Balance Sheet Arrangements
EOG does not participate in financial transactions that generate relationships with unconsolidated entities or financial partnerships. Such entities or partnerships, often referred to as variable interest entities (VIE) or special purpose entities (SPE), are generally established for the purpose of facilitating off-balance sheet arrangements or other limited purposes. EOG was not involved in any unconsolidated VIE or SPE financial transactions or any other "off-balance sheet arrangement" (as defined in Item 303(a)(4)(ii) of Regulation S-K) during any of the periods covered by this report and currently has no intention of participating in any such transaction or arrangement in the foreseeable future.
Foreign Currency Exchange Rate Risk
During 2020, EOG was exposed to foreign currency exchange rate risk inherent in its operations in foreign countries, including Trinidad, China and Canada. EOG continues to monitor the foreign currency exchange rates of countries in which it is currently conducting business and may implement measures to protect against foreign currency exchange rate risk.
Outlook
Pricing. Crude oil, NGLs and natural gas prices have been volatile, and this volatility is expected to continue. As a result of the many uncertainties associated with the world political environment, worldwide supplies of, and demand for, crude oil and condensate, NGLs and natural gas, the availabilities of other worldwide energy supplies and the relative competitive relationships of the various energy sources in the view of consumers, EOG is unable to predict what changes may occur in crude oil and condensate, NGLs, natural gas, ammonia and methanol prices in the future. The market price of crude oil and condensate, NGLs and natural gas in 2021 will impact the amount of cash generated from EOG's operating activities, which will in turn impact EOG's financial position. As of February 18, 2021, the average 2021 NYMEX crude oil and natural gas prices were $57.51 per barrel and $2.98 per MMBtu, respectively, representing an increase of 46% for crude oil and an increase of 43% for natural gas from the average NYMEX prices in 2020. See ITEM 1A, Risk Factors.
Including 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 in 2021 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 $99 million for net income and $127 million for pretax cash flows from operating activities. Including 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 2021 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 million for net income and $40 million for pretax cash flows from operating activities. For information regarding EOG's crude oil, NGLs and natural gas financial commodity derivative contracts through February 18, 2021, see "Commodity Derivative Transactions" above.
Capital. EOG plans to continue to focus a substantial portion of its exploration and development expenditures in its major producing areas in the United States. In particular, EOG will be focused on United States crude oil drilling activity in its Delaware Basin, Eagle Ford and Rocky Mountain area where it generates its highest rates-of-return. To further enhance the economics of these plays, EOG expects to continue to improve well performance and lower drilling and completion costs through efficiency gains and lower service costs. In addition, EOG expects to spend a portion of its anticipated 2021 capital expenditures on leasing acreage and evaluating new prospects.
The total anticipated 2021 capital expenditures of approximately $3.7 billion to $4.1 billion, excluding acquisitions and non-cash transactions, is structured to maintain EOG's strategy of capital discipline by funding its exploration, development and exploitation activities primarily from available internally generated cash flows and cash on hand. EOG has significant flexibility with respect to financing alternatives, including borrowings under its commercial paper program, bank borrowings, borrowings under its $2.0 billion senior unsecured revolving credit facility and equity and debt offerings.
Operations. In 2021, total crude oil production is expected to remain at fourth quarter 2020 levels. In 2021, EOG expects to continue to focus on reducing operating costs through efficiency improvements.
Summary of Critical Accounting Policies
EOG prepares its financial statements and the accompanying notes in conformity with accounting principles generally accepted in the United States, which require management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes. EOG identifies certain accounting policies as critical based on, among other things, their impact on EOG's financial condition, results of operations or liquidity, and the degree of difficulty, subjectivity and complexity in their application. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management routinely discusses the development, selection and disclosure of each of the critical accounting policies. Following is a discussion of EOG's most critical accounting policies:
Proved Oil and Gas Reserves
EOG's engineers estimate proved oil and gas reserves in accordance with United States Securities and Exchange Commission (SEC) regulations, which directly impact financial accounting estimates, including depreciation, depletion and amortization and impairments of proved properties and related assets. Proved reserves represent estimated quantities of crude oil and condensate, NGLs and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. The process of estimating quantities of proved oil and gas reserves is complex, requiring significant subjective decisions in the evaluation of available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. For related discussion, see ITEM 1A, Risk Factors, and "Supplemental Information to Consolidated Financial Statements."
Oil and Gas Exploration and Development Costs
EOG accounts for its crude oil and natural gas exploration and production activities under the successful efforts method of accounting. Oil and gas exploration costs, other than the costs of drilling exploratory wells, are expensed as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether EOG has discovered commercial quantities of proved reserves. If commercial quantities of proved reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether commercial quantities of proved reserves have been discovered when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the estimated reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized.
Depreciation, Depletion and Amortization for Oil and Gas Properties
The quantities of estimated proved oil and gas reserves are a significant component of EOG's calculation of depreciation, depletion and amortization expense, and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserves are revised upward or downward, earnings will increase or decrease, respectively.
Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. The reserve base used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account.
Oil and gas properties are grouped in accordance with the provisions of the Extractive Industries - Oil and Gas Topic of the ASC. The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.
Depreciation, depletion and amortization rates are updated quarterly to reflect the addition of capital costs, reserve revisions (upwards or downwards) and additions, property acquisitions and/or property dispositions and impairments.
Depreciation and amortization of other property, plant and equipment is calculated on a straight-line basis over the estimated useful life of the asset.
Impairments
Oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. Unproved properties with individually significant acquisition costs are reviewed individually for impairment. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred.
When circumstances indicate that proved oil and gas properties may be impaired, EOG compares expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the unamortized capitalized cost of the asset. If the expected undiscounted future cash flows, based on EOG's estimates of (and assumptions regarding) future crude oil and natural gas prices, operating costs, development expenditures, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach described in the Fair Value Measurement Topic of the ASC. In certain instances, EOG utilizes accepted offers from third-party purchasers as the basis for determining fair value. Estimates of undiscounted future cash flows require significant judgment, and the assumptions used in preparing such estimates are inherently uncertain. In addition, such assumptions and estimates are reasonably likely to change in the future.
Crude oil, NGLs and natural gas prices have exhibited significant volatility in the past, and EOG expects that volatility to continue in the future. During the five years ended December 31, 2020, WTI crude oil spot prices have fluctuated from approximately $(36.98) per barrel to $77.41 per barrel, and Henry Hub natural gas spot prices have ranged from approximately $1.33 per MMBtu to $6.24 per MMBtu. Market prices for NGLs are influenced by the components extracted, including ethane, propane, butane and natural gasoline, among others, and the respective market pricing for each component.
EOG uses the five-year NYMEX futures strip for WTI crude oil and Henry Hub natural gas and the five-year Oil Price Information Services futures strip for NGLs components (in each case as of the applicable balance sheet date) as a basis to estimate future crude oil, NGLs and natural gas prices. EOG's proved reserves estimates, including the timing of future production, are also subject to significant assumptions and judgment, and are frequently revised (upwards and downwards) as more information becomes available. Proved reserves are estimated using a trailing 12-month average price, in accordance with SEC rules. In the future, if any combination of crude oil prices, NGLs prices, natural gas prices, actual production or operating costs diverge negatively from EOG's current estimates, impairment charges and downward adjustments to our estimated proved reserves may be necessary.
Income Taxes
Income taxes are accounted for using the asset and liability approach. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis. EOG assesses the realizability of deferred tax assets and recognizes valuation allowances as appropriate. Significant assumptions used in estimating future taxable income include future crude oil, NGLs and natural gas prices and levels of capital reinvestment. Changes in such assumptions or changes in tax laws and regulations could materially affect the recognized amounts of valuation allowances.
Stock-Based Compensation
In accounting for stock-based compensation, judgments and estimates are made regarding, among other things, the appropriate valuation methodology to follow in valuing stock compensation awards and the related inputs required by those valuation methodologies. Assumptions regarding expected volatility of EOG's common stock, the level of risk-free interest rates, expected dividend yields on EOG's common stock, the expected term of the awards, expected volatility in the price of shares and composition of EOG's peer companies and other valuation inputs are subject to change. Any such changes could result in different valuations and thus impact the amount of stock-based compensation expense recognized on the Consolidated Statements of Income and Comprehensive Income.
Information Regarding Forward-Looking Statements
This Annual Report on Form 10-K includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, goals, returns and rates of return, budgets, reserves, levels of production, capital expenditures, costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend,“ "plan," "target," "aims," "goal," "may," "will," "focused on," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness, or pay and/or increase dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:
•the timing, extent and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids, natural gas and related commodities;
•the extent to which EOG is successful in its efforts to acquire or discover additional reserves;
•the extent to which EOG is successful in its efforts to (i) economically develop its acreage in, (ii) produce reserves and achieve anticipated production levels and rates of return from, (iii) decrease or otherwise control its drilling, completion, operating and capital costs related to, and (iv) maximize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects and associated potential and existing drilling locations;
•the extent to which EOG is successful in its efforts to market its production of crude oil and condensate, natural gas liquids, and natural gas;
•security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, physical breaches of our facilities and other infrastructure or breaches of the information technology systems, facilities and infrastructure of third parties with which we transact business;
•the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, storage, transportation, refining, and export facilities;
•the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights-of-way, and EOG's ability to retain mineral licenses and leases;
•the impact of, and changes in, government policies, laws and regulations, including any changes or other actions which may result from the recent U.S. elections and change in U.S. administration and including tax laws and regulations; climate change and other environmental, health and safety laws and regulations relating to air emissions, disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations affecting the leasing of acreage and permitting for oil and gas drilling and the calculation of royalty payments in respect of oil and gas production; laws and regulations imposing additional permitting and disclosure requirements, additional operating restrictions and conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas; laws and regulations with respect to derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;
•EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and drilling, completing and operating costs with respect to such properties;
•the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully and economically;
•competition in the oil and gas exploration and production industry for the acquisition of licenses, leases and properties, employees and other personnel, facilities, equipment, materials and services;
•the availability and cost of employees and other personnel, facilities, equipment, materials (such as water and tubulars) and services;
•the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
•weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, compression, storage, transportation, and export facilities;
•the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;
•EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;
•the extent to which EOG is successful in its completion of planned asset dispositions;
•the extent and effect of any hedging activities engaged in by EOG;
•the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;
•the duration and economic and financial impact of epidemics, pandemics or other public health issues, including the COVID-19 pandemic;
•geopolitical factors and political conditions and developments around the world (such as the imposition of tariffs or trade or other economic sanctions, political instability and armed conflict), including in the areas in which EOG operates;
•the use of competing energy sources and the development of alternative energy sources;
•the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;
•acts of war and terrorism and responses to these acts; and
•the other factors described under ITEM 1A, Risk Factors of this Annual Report on Form 10-K and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration or extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk
The information required by this Item is incorporated by reference from Item 7 of this report, specifically the information set forth under the captions "Commodity Derivative Transactions," "Financing," "Foreign Currency Exchange Rate Risk" and "Outlook" in "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity."

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. Financial Statements and Supplementary Data
The information required by this Item is included in this report as set forth in the "Index to Financial Statements" on page and is incorporated by reference herein.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.

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ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. Controls and Procedures
Disclosure Controls and Procedures. EOG's management, with the participation of EOG's principal executive officer and principal financial officer, evaluated the effectiveness of EOG's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (Exchange Act)) as of December 31, 2020. EOG's disclosure controls and procedures are designed to provide reasonable assurance that information that is required to be disclosed in the reports EOG files or submits under the Exchange Act is accumulated and communicated to EOG's management, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the United States Securities and Exchange Commission. Based on that evaluation, EOG's principal executive officer and principal financial officer have concluded that EOG's disclosure controls and procedures were effective as of December 31, 2020.
Management's Annual Report on Internal Control over Financial Reporting. EOG's management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Exchange Act). Even an effective system of internal control over financial reporting, no matter how well designed, has inherent limitations, including the possibility of human error, circumvention of controls or overriding of controls and, therefore, can provide only reasonable assurance with respect to reliable financial reporting. Furthermore, the effectiveness of a system of internal control over financial reporting in future periods can change as conditions change.
EOG's management assessed the effectiveness of EOG's internal control over financial reporting as of December 31, 2020. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework (2013). Based on this assessment and such criteria, EOG's management believes that EOG's internal control over financial reporting was effective as of December 31, 2020. See also "Management's Responsibility for Financial Reporting" appearing on page of this report, which is incorporated herein by reference.
The report of EOG's independent registered public accounting firm relating to the consolidated financial statements and effectiveness of internal control over financial reporting is set forth on page of this report.
There were no changes in EOG's internal control over financial reporting that occurred during the quarter ended December 31, 2020, that have materially affected, or are reasonably likely to materially affect, EOG's internal control over financial reporting.

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ITEM 9B. OTHER INFORMATION
ITEM 9B. Other Information
None.
PART III

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10. Directors, Executive Officers and Corporate Governance
The information required by this Item is incorporated by reference from (i) EOG's Definitive Proxy Statement with respect to its 2021 Annual Meeting of Stockholders to be filed not later than April 30, 2021 and (ii) Item 1 of this report, specifically the information therein set forth under the caption "Information About Our Executive Officers."
Pursuant to Rule 303A.10 of the New York Stock Exchange and Item 406 of Regulation S-K promulgated under the Securities Exchange Act of 1934, as amended, EOG has adopted a Code of Business Conduct and Ethics for Directors, Officers and Employees (Code of Conduct) that applies to all EOG directors, officers and employees, including EOG's principal executive officer, principal financial officer and principal accounting officer. EOG has also adopted a Code of Ethics for Senior Financial Officers (Code of Ethics) that, along with EOG's Code of Conduct, applies to EOG's principal executive officer, principal financial officer, principal accounting officer and controllers.
You can access the Code of Conduct and Code of Ethics on the "Governance" page under "Investors" on EOG's website at www.eogresources.com, and any EOG stockholder who so requests may obtain a printed copy of the Code of Conduct and Code of Ethics by submitting a written request to EOG's Corporate Secretary.
EOG intends to disclose any amendments to the Code of Conduct or Code of Ethics, and any waivers with respect to the Code of Conduct or Code of Ethics granted to EOG's principal executive officer, principal financial officer, principal accounting officer, any of our controllers or any of our other employees performing similar functions, on its website at www.eogresources.com within four business days of the amendment or waiver. In such case, the disclosure regarding the amendment or waiver will remain available on EOG's website for at least 12 months after the initial disclosure. There have been no waivers granted with respect to EOG's Code of Conduct or Code of Ethics.

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ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. Executive Compensation
The information required by this Item is incorporated by reference from EOG's Definitive Proxy Statement with respect to its 2021 Annual Meeting of Stockholders to be filed not later than April 30, 2021. The Compensation Committee Report and related information incorporated by reference herein shall not be deemed "soliciting material" or to be "filed" with the United States Securities and Exchange Commission, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933, as amended, or Securities Exchange Act of 1934, as amended, except to the extent that EOG specifically incorporates such information by reference into such a filing.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required by this Item with respect to security ownership of certain beneficial owners and management is incorporated by reference from EOG's Definitive Proxy Statement with respect to its 2021 Annual Meeting of Stockholders to be filed not later than April 30, 2021.
Equity Compensation Plan Information
Stock Plans Approved by EOG Stockholders. EOG's stockholders approved the EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (2008 Plan) at the 2008 Annual Meeting of Stockholders in May 2008. At the 2010 Annual Meeting of Stockholders in April 2010 (2010 Annual Meeting), an amendment to the 2008 Plan was approved, pursuant to which the number of shares of common stock available for future grants of stock options, stock-settled stock appreciation rights (SARs), restricted stock, restricted stock units, performance units and other stock-based awards under the 2008 Plan was increased by an additional 13.8 million shares, to an aggregate maximum of 25.8 million shares plus shares underlying forfeited or canceled grants under the prior stock plans referenced in the 2008 Plan document. At the 2013 Annual Meeting of Stockholders in May 2013, EOG's stockholders approved the Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (Amended and Restated 2008 Plan). As more fully discussed in the Amended and Restated 2008 Plan document, the Amended and Restated 2008 Plan, among other things, authorizes an additional 31.0 million shares of EOG common stock for grant under the plan and extends the expiration date of the plan to May 2023. Under the Amended and Restated 2008 Plan, grants may be made to employees and non-employee members of EOG's Board.
Also at the 2010 Annual Meeting, an amendment to the EOG Resources, Inc. Employee Stock Purchase Plan (ESPP) was approved to increase the shares available for grant by 2.0 million shares. The ESPP was originally approved by EOG's stockholders in 2001, and would have expired on July 1, 2011. The amendment also extended the term of the ESPP to December 31, 2019, unless terminated earlier by its terms or by EOG. At the 2018 Annual Meeting of Stockholders in April 2018, stockholders approved an amendment and restatement of the ESPP to (among other changes) increase the number of shares available for grant by 2.5 million shares and further extend the term of the ESPP to December 31, 2027, unless terminated earlier by its terms or by EOG.
Stock Plans Not Approved by EOG Stockholders. In December 2008, the Board approved the amendment and continuation of the 1996 Deferral Plan as the "EOG Resources, Inc. 409A Deferred Compensation Plan" (Deferral Plan). Under the Deferral Plan (as subsequently amended), payment of up to 50% of base salary and 100% of annual cash bonus, director's fees, vestings of restricted stock units granted to non-employee directors (and dividends credited thereon) under the 2008 Plan and 401(k) refunds (as defined in the Deferral Plan) may be deferred into a phantom stock account. In the phantom stock account, deferrals are treated as if shares of EOG common stock were purchased at the closing stock price on the date of deferral. Dividends are credited quarterly and treated as if reinvested in EOG common stock. Payment of the phantom stock account is made in actual shares of EOG common stock in accordance with the Deferral Plan and the individual's deferral election. A total of 540,000 shares of EOG common stock have been authorized by the Board and registered for issuance under the Deferral Plan. As of December 31, 2020, 368,745 phantom shares had been issued. The Deferral Plan is currently EOG's only stock plan that has not been approved by EOG's stockholders.
The following table sets forth data for EOG's equity compensation plans aggregated by the various plans approved by EOG's stockholders and those plans not approved by EOG's stockholders, in each case as of December 31, 2020.
Plan Category (a)
Number of Securities to be
Issued Upon Exercise of
Outstanding Options,
Warrants and Rights (b)
Weighted-Average
Exercise Price of
Outstanding Options,
Warrants and Rights (1)
(c)
Number of Securities
Remaining Available
for Future Issuance Under
Equity Compensation
Plans (Excluding Securities
Reflected in Column (a))
Equity Compensation Plans Approved by EOG Stockholders 11,753,761 (2)
$ 84.08 3,891,544 (3)
Equity Compensation Plans Not Approved by EOG Stockholders 248,363 (4)
N/A 171,255 (5)
Total 12,002,124 $ 84.08 4,062,799
(1)The weighted-average exercise price is calculated based solely on the exercise prices of the outstanding stock option and SAR grants and does not reflect shares that will be issued upon the vesting of outstanding restricted stock unit and performance unit grants, or Deferral Plan phantom shares, all of which have no exercise price.
(2)Amount includes 954,949 outstanding restricted stock units, for which shares of EOG common stock will be issued, on a one-for-one basis, upon the vesting of such grants. Amount also includes 612,951 outstanding performance units and assumes, for purposes of this table, (i) the application of a 100% performance multiple upon the completion of each of the remaining performance periods in respect of such performance unit grants and (ii) accordingly, the issuance, on a one-for-one basis, of an aggregate 612,951 shares of EOG common stock upon the vesting of such grants. As more fully discussed in Note 7 to Consolidated Financial Statements, upon the application of the relevant performance multiple at the completion of each of the remaining performance periods in respect of such grants, (A) a minimum of 76,785 and a maximum of 1,149,117 performance units could be outstanding and (B) accordingly, a minimum of 76,785 and a maximum of 1,149,117 shares of EOG common stock could be issued upon the vesting of such grants.
(3)Consists of (i) 1,996,101 shares remaining available for issuance under the Amended and Restated 2008 Plan and (ii) 1,895,443 shares remaining available for purchase under the ESPP. Pursuant to the fungible share design of the Amended and Restated 2008 Plan, each share issued as a SAR or stock option under the Amended and Restated 2008 Plan counts as 1.0 share against the aggregate plan share limit, and each share issued as a "full value award" (i.e., as restricted stock, restricted stock units or performance units) counts as 2.45 shares against the aggregate plan share limit. Thus, from the 1,996,101 shares remaining available for issuance under the Amended and Restated 2008 Plan, (i) the maximum number of shares we could issue as SAR and stock option awards is 1,996,101 (i.e., if all shares remaining available for issuance under the Amended and Restated 2008 Plan are issued as SAR and stock option awards) and (ii) the maximum number of shares we could issue as full value awards is 814,735 (i.e., if all shares remaining available for issuance under the Amended and Restated 2008 Plan are issued as full value awards).
(4)Consists of shares of EOG common stock to be issued in accordance with the Deferral Plan and participant deferral elections (i.e., in respect of the 248,363 phantom shares issued and outstanding under the Deferral Plan as of December 31, 2020).
(5)Represents phantom shares that remain available for issuance under the Deferral Plan.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this Item is incorporated by reference from EOG's Definitive Proxy Statement with respect to its 2021 Annual Meeting of Stockholders to be filed not later than April 30, 2021.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14. Principal Accounting Fees and Services
The information required by this Item is incorporated by reference from EOG's Definitive Proxy Statement with respect to its 2021 Annual Meeting of Stockholders to be filed not later than April 30, 2021.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. Exhibits, Financial Statement Schedules
(a)(1) and (a)(2) Financial Statements and Financial Statement Schedule
See "Index to Financial Statements" set forth on page.
(a)(3), (b) Exhibits
See pages E-1 through E-6 for a listing of the exhibits.