EDGAR 10-K Filing

Company CIK: 821189
Filing Year: 2023
Filename: 821189_10-K_2023_0000821189-23-000015.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) 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, 2022, EOG's total estimated net proved reserves were 4,238 million barrels of oil equivalent (MMBoe), of which 1,661 million barrels (MMBbl) were crude oil and condensate reserves, 1,145 MMBbl were NGLs reserves and 8,591 billion cubic feet (Bcf), or 1,432 MMBoe, were natural gas reserves (see "Supplemental Information to Consolidated Financial Statements"). At such date, approximately 99% of EOG's net proved reserves, on a crude oil equivalent basis, were located in the United States and 1% in Trinidad. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet (Mcf) of natural gas.
EOG's operations are all crude oil and natural gas exploration and production related. For information regarding the risks associated with EOG's domestic and foreign operations, see ITEM 1A, Risk Factors.
EOG 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 maximize long-term growth in shareholder value and maintain a strong balance sheet. EOG is focused on innovation and cost-effective utilization of advanced technology associated with three-dimensional seismic and microseismic data, the development of reservoir simulation models and the use of improved drilling equipment and completion technologies for horizontal drilling and formation evaluation. These advanced technologies are used, as appropriate, throughout EOG to reduce the risks and costs associated with all aspects of oil and gas exploration, development and exploitation. EOG implements its strategy primarily by emphasizing the drilling of internally generated prospects in order to find and develop low-cost reserves. Maintaining the lowest possible operating cost structure, coupled with efficient and safe operations and robust environmental stewardship practices and performance, is integral in the implementation of EOG's strategy.
With respect to information on EOG's working interest in wells or acreage, "net" oil and gas wells or acreage are determined by multiplying "gross" oil and gas wells or acreage by EOG's working interest in the wells or acreage.
Exploration and Production
United States Operations
EOG's operations are located in most of the productive basins in the United States with a focus on crude oil and, to a lesser extent, natural gas plays.
At December 31, 2022, on a crude oil equivalent basis, 40% of EOG's net proved reserves in the United States were crude oil and condensate, 27% were NGLs and 33% were natural gas. The majority of these reserves are in long-lived fields with well-established production characteristics. EOG believes that opportunities exist to increase production through continued development in and around many of these fields and through the utilization of applicable technologies. EOG also maintains an active exploration program designed to extend fields and add new trends and resource plays to its already broad portfolio.
The following is a summary of wellhead volume statistics and net well completions for the year ended December 31, 2022, total net acres at December 31, 2022, and expected net well completions planned for 2023 for certain areas of EOG's United States operations.
2022 2023
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
Delaware Basin 277.0 138.8 764 395 358 365
South Texas 133.3 32.7 336 1,139 125 185
Rocky Mountain 42.1 13.7 135 764 31 55
Other Areas 8.3 12.5 80 1,184 19 20
Total 460.7 197.7 1,315 3,482 533 625
(1)Thousand barrels per day or million cubic feet per day, as applicable.
In the Delaware Basin, EOG completed 358 net wells in 2022, 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 395,000 net acre position.
In the Delaware Basin Wolfcamp play, EOG completed 196 net wells in 2022. EOG continued to focus on co-development of multiple Wolfcamp targets to maximize the value of the acreage. In 2023, the Delaware Basin Wolfcamp play will continue to be a primary area of focus.
In the Bone Spring play, EOG has three main sub-plays: the First, Second and Third Bone Spring. In 2022, EOG completed 141 total net Bone Spring wells within the three sub-plays. Of the three sub-plays, the Second Bone Spring had the majority of the activity in 2022 with EOG completing 106 net wells. The Bone Spring play continues to be an integral part of EOG's Delaware Basin plans and portfolio.
In the Leonard play, EOG executed its development plan with 21 net wells completed in 2022. EOG continued co-development of multiple Leonard zones simultaneously, and expects the Leonard play to become a more active part of EOG's program in the next several years.
Activity in 2023 will remain focused on the Delaware Basin Wolfcamp, Bone Spring, and Leonard plays, where EOG expects to complete approximately 365 net wells.
The South Texas area includes our Eagle Ford play and our Dorado gas play. EOG holds approximately 537,000 total net acres in the Eagle Ford play and approximately 160,000 net acres in the Dorado gas play. In the Dorado gas play, EOG has continued to delineate the Eagle Ford and Austin Chalk formations with excellent results. In 2022, EOG completed 103 net wells in the Eagle Ford play, and 22 net wells in the Dorado gas play. In 2023, EOG expects to complete approximately 155 net Eagle Ford play wells and 30 net Dorado wells.
Activity in the Rocky Mountain area in 2022 was focused on the Wyoming Powder River Basin. In the Powder River Basin, EOG operated a two-rig program and completed 27 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. In addition, in the DJ Basin, EOG drilled and completed two net wells in the Codell formation and, in the Williston Basin, EOG completed two net wells in the Bakken and Three Forks formations. In 2023, activity in the Rockies is expected to increase. EOG plans to complete approximately 10 net Williston Basin wells, five net DJ Basin wells and 40 net wells in the Powder River Basin.
Operations Outside the United States
EOG has operations offshore Trinidad and is making preparations to drill offshore Australia, as well as evaluating additional exploration, development and exploitation opportunities in these and other select international areas. In addition, EOG is in the process of exiting Block 36 and Block 49 in the Sultanate of Oman (Oman) and is executing an abandonment and reclamation program in Canada.
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 platforms and 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 the Modified U(a) and 4(a) Blocks. EOG relinquished its interest in the Modified U(b) Block in the fourth quarter of 2022.
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, with the exception of the Modified U(b) Block in which EOG ceased to have an interest in the production of natural gas and crude oil and condensate in the fourth quarter of 2022.
In March 2021, EOG signed a farmout agreement with Heritage Petroleum Company Limited (Heritage), which allows EOG to earn a 65% working interest in a portion of the contract area (EOG Area) governed by the Trinidad Northern Area License. The EOG Area is located offshore the southwest coast of Trinidad. In 2022, EOG drilled one net exploratory well, which was determined to be unsuccessful.
In 2022, EOG's net production in Trinidad averaged approximately 180 MMcfd of natural gas and approximately 0.6 MBbld of crude oil and condensate. In 2022, EOG completed the design, fabrication and installation of a platform and related facilities for its previously announced discovery in the Modified U(a) Block. Additionally, two exploratory wells from a pre-existing platform in the Modified U(a) Block were successfully drilled and put on production.
In 2023, EOG expects to complete three developmental and two exploratory wells in the Modified U(a) Block. Additionally, EOG expects to make progress on the design and construction of a platform and related facilities in the Mento Area.
Australia. In April 2021, a subsidiary of EOG entered into a purchase and sale agreement to acquire a 100% interest in the WA-488-P Block, located offshore Western Australia. In November 2021, the petroleum exploration permit for that block was transferred to that subsidiary.
In 2022, EOG continued preparing for the drilling of an exploration well, the timing of which will depend on obtaining regulatory approvals and subsequent equipment availability.
Oman. EOG, through its subsidiaries, holds interests in Exploration and Production Sharing Agreements in Block 36 and Block 49 (collectively, Blocks) located in Oman. In 2021, EOG's partner finished completing one net exploratory well in Block 49 and EOG drilled two exploratory wells in Block 36. The well results did not indicate sufficient projected returns for EOG to move forward with the project and, in 2022, EOG began the process of exiting these Blocks.
Canada. In March 2020, EOG began the process of exiting its Canada operations in the Horn River area in Northeast British Columbia.
Marketing
In 2022, EOG continued its diversified approach to marketing its wellhead crude oil and condensate production. The majority of EOG's United States wellhead crude oil and condensate production was transported by pipeline to downstream markets with the remainder sold into local markets. Major U.S. sales areas accessed by EOG were at various locations along the U.S. Gulf Coast, including Houston and Corpus Christi, Texas; Cushing, Oklahoma; the Permian Basin and the Midwest. In 2022, EOG also sold crude oil at 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 2023, the pricing mechanism for such production is expected to remain the same. At December 31, 2022, EOG was committed to deliver to multiple parties fixed quantities of crude oil of 7 MMBbls in 2023, 7 MMBbls in 2024 and 1 MMBbls in 2025, all of which is expected to be sourced from future production of available reserves.
In 2022, EOG processed certain of its United States wellhead natural gas production, either at EOG-owned facilities or at third-party facilities, extracting NGLs. NGLs were sold at prevailing market prices, into either local markets or downstream locations. In certain instances, EOG exchanged its NGLs production for purity products received downstream, which were sold at prevailing market prices. In 2023, such pricing mechanisms are expected to remain the same. In 2022, EOG also sold purity products at the Houston Ship Channel for export to foreign destinations. In each case, the price received was based on market prices at that specific sales point or based on the price index applicable for that location. In 2023, the pricing mechanism for such production is expected to remain the same. At December 31, 2022, EOG was not committed to deliver fixed quantities of NGLs in 2023.
In 2022, consistent with its diversified marketing strategy, the majority of EOG's United States wellhead natural gas production was transported by pipeline to various locations, including Katy, Texas; East Texas; the Agua Dulce Hub in South Texas; the Cheyenne Hub in Weld County, Colorado; Southern California; and Chicago, Illinois. Remaining natural gas production was sold into local markets. In each case, pricing was based on the spot market price at the ultimate sales point. In 2023, the pricing mechanism for such production is expected to remain the same. Additionally, EOG sells natural gas to a liquefaction facility near Corpus Christi, Texas, and receives pricing based on the Platts Japan Korea Marker. At December 31, 2022, EOG was committed to deliver to multiple parties fixed quantities of natural gas of 347 Bcf in 2023, 321 Bcf in 2024, 277 Bcf in 2025, 297 Bcf in 2026, 293 Bcf in 2027 and 3,540 Bcf thereafter, all of which is expected to be sourced from future production of available reserves.
In 2022, natural gas volumes from Trinidad were sold under a fixed price contract. In July 2022, EOG amended the natural gas sales contract with the National Gas Company of Trinidad and Tobago Limited and its subsidiary (NGC) to (i) extend the term to 2026 and (ii) effective September 1, 2020, provide for an increase in price realization if index prices for certain commodities exceed specified levels. The pricing mechanism for production in Trinidad is expected to remain the same in 2023.
In certain instances, EOG purchases and sells third-party crude oil and natural gas in order to balance firm capacity at third-party facilities with production in certain areas and to utilize excess capacity at EOG-owned facilities.
During 2022, three purchasers 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 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, 2022, 2021 and 2020. See ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations, for wellhead volumes on a per-day basis.
Year Ended December 31 2022 2021 2020
Crude Oil and Condensate Volumes (MMBbl) (1)
United States:
Eagle Ford Play 46.6 51.8 54.6
Delaware Basin 101.1 84.3 67.0
Other 20.3 25.7 27.8
United States 168.0 161.8 149.4
Trinidad 0.3 0.5 0.4
Other International (2)
- - -
Total 168.3 162.3 149.8
Natural Gas Liquids Volumes (MMBbl) (1)
United States:
Eagle Ford Play 10.5 9.0 9.7
Delaware Basin 50.7 30.9 27.7
Other 10.9 12.8 12.4
United States 72.1 52.7 49.8
Other International (2)
- - -
Total 72.1 52.7 49.8
Natural Gas Volumes (Bcf) (1)
United States:
Eagle Ford Play 52 55 53
Delaware Basin 279 238 168
Other 149 149 160
United States 480 442 381
Trinidad 66 79 66
Other International (2)
- 3 11
Total 546 524 458
Crude Oil Equivalent Volumes (MMBoe) (3)
United States:
Eagle Ford Play 65.8 70.0 73.1
Delaware Basin 198.3 154.9 122.7
Other 56.0 63.3 66.9
United States 320.1 288.2 262.7
Trinidad 11.4 13.7 11.4
Other International (2)
- 0.6 1.8
Total 331.5 302.5 275.9
Year Ended December 31 2022 2021 2020
Average Crude Oil and Condensate Prices ($/Bbl) (4)
United States $ 97.22 $ 68.54 $ 38.65
Trinidad 86.16 56.26 30.20
Other International (2)
- 42.36 43.08
Composite 97.21 68.50 38.63
Average Natural Gas Liquids Prices ($/Bbl) (4)
United States $ 36.70 $ 34.35 $ 13.41
Other International (2)
- - -
Composite 36.70 34.35 13.41
Average Natural Gas Prices ($/Mcf) (4)
United States $ 7.27 $ 4.88 $ 1.61
Trinidad 4.43 (5) 3.40 2.57
Other International (2)
- 5.67 4.66
Composite 6.93 4.66 1.83
(1)Million barrels or billion cubic feet, as applicable.
(2)Other International includes EOG's China and Canada operations. The China operations were sold in the second quarter of 2021.
(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).
(5)Includes positive revenue adjustment of $0.76 per Mcf ($0.09 per Mcf of EOG's composite wellhead natural gas price) for the twelve months ended December 31, 2022, related to a price adjustment per a provision of the natural gas sales contract with NGC amended in July 2022 for natural gas sales during the period from September 2020 through June 2022.
Human Capital Management
As of December 31, 2022, EOG employed approximately 2,850 persons, including foreign national employees. EOG's approach to human capital management includes oversight by the Board of Directors (Board) and the Compensation and Human Resources Committee of the Board and focuses on various areas, including the following:
Culture; Recruiting; Retention. EOG's culture is key to its sustainable success. By providing employees with a quality work environment and 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 values attracting and retaining talent, and so it provides 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, new-hire stock grants, annual stock grants and an employee stock purchase plan give every employee the opportunity to be a participant in EOG's success.
Training and Development. EOG supports employees’ professional development and provides training in leadership, management skills, communication, team effectiveness, technical skills and use of EOG systems and applications. EOG's leadership training, in particular, is focused on providing continuity of leadership at EOG by further 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 costs of professional certifications.
Diversity and Inclusion. EOG values gender, racial, ethnic and cultural diversity and works to foster a collaborative work environment of different talents, perspectives and experiences. EOG believes such diversity in background and experience promotes diversity of thought, which helps drive innovation. EOG continues to raise employee awareness to help advance diversity and inclusion efforts within EOG. Further, 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.
Safety. EOG's safety management programs and processes provide a framework for assessing 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 and contractors. 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
General. New or revised rules, regulations and policies may be issued, and new legislation may be proposed, 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, (vi) U.S. federal income tax laws applicable to oil and gas exploration and production companies and (vii) the use of financial derivative instruments to hedge the financial impact of fluctuations in crude oil, NGLs and natural gas prices. 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 the below discussion and ITEM 1A, Risk Factors.
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 and Wyoming, 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. In addition, the Inflation Reduction Act of 2022 (IRA) requires that all leases granted and administered by the BLM and entered into on or after August 16, 2022 include a royalty rate of 16.67 percent in respect of the associated oil and gas production.
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. From time to time, the U.S. Department of the Interior has also considered limiting or pausing new oil and natural gas leases on federal lands or in offshore waters. 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 unregulated market prices, subject to applicable contract provisions. EOG's jurisdictional sales, however, may be subject in the future to greater federal oversight, including the possibility that the FERC might prospectively impose more restrictive conditions on such sales. Conversely, sales of crude oil and condensate and NGLs by EOG are made at unregulated market prices.
EOG owns certain gathering and/or processing facilities supporting EOG's operations in the Permian Basin in West Texas and New Mexico, the Powder River Basin in Wyoming, the Fort Worth Basin Barnett Shale in North Texas, the Williston Basin Bakken and Three Forks plays in North Dakota, and the Eagle Ford play and Dorado gas play 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 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 and permitting 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 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 2022.
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 or release 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 and related activities (e.g., carbon capture and storage). 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, results of operations or capital expenditures (for environmental control facilities or otherwise). In addition, it is not anticipated, based on current laws and regulations, that EOG will be required in the near future to expend amounts (whether for environmental control facilities or otherwise) that are material in relation to its total exploration and development expenditure program in order to comply with such laws and regulations. However, EOG is unable to predict (i) the timing, scope and effect of any currently proposed or future laws or regulations regarding the environment and (ii) the ultimate cost of compliance or the ultimate effect on EOG's operations, financial condition, results of operations and capital expenditures relating to such future laws and regulations. The direct and indirect cost of such laws and regulations (if enacted) could materially and adversely affect EOG's operations, financial condition, results of operations and capital expenditures.
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. The U.S. Congress has, from time to time, proposed legislation for imposing restrictions or requiring fees or carbon taxes for GHG emissions. The IRA imposes a methane emissions charge on certain oil and gas facilities, including onshore and offshore petroleum and natural gas production facilities, that exceed certain emissions thresholds. The charges will be levied annually based on emissions reported under the EPA's GHG reporting program. The U.S. EPA is expected to publish, in the first half of 2023, regulations specific to the calculation of such annual charge. EOG does not currently expect such annual methane emissions charges to have a material impact on its financial condition, results of operations, capital expenditures or operations.
In addition to the U.S. EPA's rule requiring annual reporting of GHG emissions from covered facilities (which is amended from time to time and under which EOG reports), the U.S. EPA has adopted regulations for certain large sources regulating GHG emissions as pollutants under the federal Clean Air Act. Further, the U.S. EPA, in May 2016, issued regulations that require operators to reduce methane emissions and emissions of volatile organic compounds (VOC) from new, modified and reconstructed crude oil and natural gas wells and equipment located at natural gas production gathering and booster stations, gas processing plants and natural gas transmission compressor stations. In November 2021, the EPA proposed a rule to further reduce methane and VOC emissions from new and existing sources in the oil and natural gas sector and, in November 2022, the U.S. EPA issued a supplemental proposal to expand its November 2021 proposed rule, including proposed regulation of additional sources of methane and VOC emissions, such as abandoned and unplugged wells.
At the international level, the U.S., in December 2015, participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The Paris Agreement (adopted at the conference) calls for nations to undertake efforts with respect to global temperatures and GHG emissions. The Paris Agreement went into effect on November 4, 2016, and which the United States formally rejoined in February 2021. The United States has established economy-wide targets of (i) reducing its net GHG emissions by 50-52 percent below 2005 levels by 2030 and (ii) achieving net zero GHG emissions economy-wide by no later than 2050. In addition, many state and local officials have stated their intent to intensify efforts to uphold the commitments set forth in the international accord.
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 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.), but the direct and indirect costs of such investigations, laws, regulations, treaties or policies (if enacted, issued or applied) could materially and adversely affect EOG's operations, financial condition, results of operations and capital expenditures. The potential increase in the costs of our operations could include costs to operate and maintain our facilities, install new emissions controls on our facilities, acquire allowances or credits to cover our GHG emissions, pay taxes or fees related to our GHG emissions, or administer and manage a GHG emissions program. In addition, changes in regulatory policies that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to GHG emissions, or restrictions on their use, could also adversely affect market demand for, and in turn the prices we receive for our production of, crude oil, NGLs and natural gas. Further, the increasing attention to global climate change risks has created the potential for a greater likelihood of governmental investigations and private and public litigation, which could increase our costs or otherwise adversely affect our business. See ITEM 1A, Risk Factors, for additional discussion regarding climate change-related developments.
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 November 2021, the U.S. EPA proposed a rule to further reduce methane and VOC emissions from new and existing sources in the oil and natural gas sector and, in November 2022, the U.S. EPA issued a supplemental proposal to further strengthen and expand its November 2021 proposal. From time to time, there have been various other proposals to regulate hydraulic fracturing at the federal level.
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 prohibitions 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, results of operations or capital expenditures (for environmental control facilities or otherwise). In addition, it is not anticipated, based on current laws and regulations, that EOG will be required in the near future to expend amounts that are material in relation to its total exploration and development expenditure program in order to comply with such laws and regulations. However, EOG is unable to predict (i) the timing, scope and effect of any currently proposed or future laws or regulations regarding hydraulic fracturing in the United States or other aspects of our operations and (ii) the ultimate cost of compliance or the ultimate effect on EOG's operations, financial condition, results of operations and capital expenditures relating to such future laws and regulations. The direct and indirect costs of such laws and regulations (if enacted) could materially and adversely affect EOG's operations, financial condition, results of operations and capital expenditures.
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 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, results of operations and capital expenditures. 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 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 increased 42% in 2022, increased 77% in 2021 and decreased 33% in 2020, each as compared to the immediately preceding year. Average NGLs prices received by EOG for production in the United States increased 7% in 2022, increased 156% in 2021 and decreased 16% in 2020, each as compared to the immediately preceding year. Fluctuations in average natural gas prices received by EOG for production in the United States resulted in a 49% increase in 2022, a 203% increase in 2021, and a 27% decrease in 2020, 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), the global supply of, and demand for, crude oil, NGLs and natural gas and the availability of other energy supplies, the relative competitive relationships of the various energy sources in the view of consumers and other factors, EOG is unable to predict what changes may occur in the prices of crude oil and condensate, NGLs and natural gas in the future. For additional discussion regarding changes in crude oil and condensate, NGLs and natural gas prices, the potential impacts on EOG and the risks that such changes may present to EOG, see ITEM 1A, Risk Factors.
Including the impact of EOG's crude oil financial derivative contracts (exclusive of basis swaps) and based on EOG's tax position, EOG's price sensitivity in 2023 for each $1.00 per barrel increase or decrease in wellhead crude oil and condensate price, combined with the estimated change in NGLs price, is approximately $137 million for net income and $175 million for pretax cash flows from operating activities. Including the impact of EOG's natural gas financial derivative contracts and based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2023 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 $35 million for net income and $44 million for pretax cash flows from operating activities. For a summary of EOG's financial commodity derivative contracts through February 16, 2023, see ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Financial Commodity Derivative Transactions. For a summary of EOG's financial commodity derivative contracts for the year ended December 31, 2022, 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 16, 2023, see ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Financial Commodity Derivative Transactions.
All of EOG's crude oil, NGLs and natural gas activities are subject to the risks normally incident to the exploration for, and development, production and transportation of, crude oil, NGLs and natural gas, including rig and well explosions, cratering, fires, loss of well control and leaks and spills, each of which could result in damage to life, property and/or the environment. EOG's operations are also subject to certain perils, including hurricanes, tropical storms, flooding, winter storms and other adverse weather events. Moreover, EOG's activities are subject to governmental regulations as well as interruption or termination by governmental authorities based on environmental and other considerations. Losses and liabilities arising from such events could reduce EOG's revenues and increase costs to EOG to the extent not covered by insurance.
Insurance is maintained by EOG against some, but not all, of these risks in accordance with what EOG believes are customary industry practices and in amounts and at costs that EOG believes to be prudent and commercially practicable. Specifically, EOG maintains commercial general liability and excess liability coverage provided by third-party insurers for bodily injury or death claims resulting from an incident involving EOG's operations (subject to policy terms and conditions). Moreover, for any incident involving EOG's operations which results in negative environmental effects, EOG maintains operators extra expense coverage provided by third-party insurers for obligations, expenses or claims that EOG may incur from such an incident, including obligations, expenses or claims in respect of seepage and pollution, cleanup and containment, evacuation expenses and control of the well (subject to policy terms and conditions). In the event of a well control incident resulting in negative environmental effects, such operators extra expense coverage would be EOG's primary coverage, with the commercial general liability and excess liability coverage referenced above also providing certain coverage to EOG. All of EOG's drilling activities are conducted on a contractual basis with independent drilling contractors and other third-party service contractors. The indemnification and other risk allocation provisions included in such contracts are negotiated on a contract-by-contract basis and are each based on the particular circumstances of the services being provided and the anticipated operations.
In addition to the above-described risks, EOG's operations outside the United States are subject to certain risks, including the risk of increases in taxes and governmental royalties, changes in laws and policies governing the operations of foreign-based companies, expropriation of assets, unilateral or forced renegotiation, modification or nullification of existing contracts with governmental entities, currency restrictions and exchange rate fluctuations. Please refer to ITEM 1A, Risk Factors, for further discussion of the risks to which EOG is subject with respect to its operations outside the United States.
Information About Our Executive Officers
The current executive officers of EOG and their names and ages (as of February 23, 2023) are as follows:
Name Age Position
Ezra Y. Yacob 46 Chairman of the Board and Chief Executive Officer
Lloyd W. Helms, Jr. 65 President and Chief Operating Officer
Kenneth W. Boedeker 60 Executive Vice President, Exploration and Production
Jeffrey R. Leitzell 43 Executive Vice President, Exploration and Production
Timothy K. Driggers 61 Executive Vice President and Chief Financial Officer
Michael P. Donaldson 60 Executive Vice President, General Counsel and Corporate Secretary
Ezra Y. Yacob was appointed Chairman of the Board, effective October 2022, and elected Chief Executive Officer and appointed as a Director effective October 2021. Prior to that, he served as President from January 2021 through September 2021; Executive Vice President, Exploration and Production from December 2017 to January 2021; and 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.
Lloyd W. Helms, Jr. was elected President and Chief Operating Officer effective October 2021. Mr. Helms has served as Chief Operating Officer since December 2017. Prior to that, he served as Executive Vice President, Exploration and Production from August 2013 to December 2017. He was elected Vice President, Engineering and Acquisitions in September 2006, Vice President and General Manager of EOG's Calgary, Alberta, Canada office in March 2008, and served as Executive Vice President, Operations from February 2012 to August 2013. Mr. Helms joined a predecessor of EOG in February 1981.
Kenneth W. Boedeker was elected Executive Vice President, Exploration and Production in December 2018. He served as Vice President and General Manager of EOG's Denver, Colorado, office from October 2016 to December 2018, and as Vice President, Engineering and Acquisitions from July 2015 to October 2016. Prior to that, Mr. Boedeker held technical and managerial positions of increasing responsibility across multiple offices and functional areas within EOG. Mr. Boedeker joined EOG in July 1994.
Jeffrey R. Leitzell was elected Executive Vice President, Exploration and Production in May 2021. Mr. Leitzell previously served as Vice President and General Manager of EOG's Midland, Texas office from December 2017 to May 2021 and as Operations Manager in Midland from August 2015 to December 2017. Prior to that, Mr. Leitzell held various engineering roles of increasing responsibility in multiple offices and functional areas within EOG. Mr. Leitzell joined EOG in October 2008.
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, NGLs and natural gas 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, and consumer and industrial/commercial demand for, 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;
•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 COVID-19 pandemic;
•the availability, proximity and capacity of appropriate transportation, gathering, processing, compression, storage, refining and export 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 legislation, policies, initiatives and developments;
•technological advances and consumer and industrial/commercial behavior, preferences and attitudes, in each case affecting energy generation, transmission, storage and consumption;
•the nature and extent of governmental regulation, including environmental and other climate change-related regulation, regulation of financial derivative 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
•natural disasters, weather conditions and changes in weather patterns.
The above-described factors and the volatility of commodity prices make it difficult to predict crude oil, NGLs and natural gas prices in 2023 and thereafter. As a result, there can be no assurance that the prices for crude oil, NGLs and/or natural gas will sustain, or increase from, their current levels, nor can there be any assurance that the prices for crude oil, NGLs and/or natural gas will not decline.
Our cash flows, financial condition 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; our results of operations; and our financial condition, including (but not limited to) our ability to pay dividends on our common stock. As a result, the trading price of our common stock may be materially and adversely affected.
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 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.
Our cost-mitigation initiatives and actions may not offset, largely or at all, the impacts of inflationary pressures on our operating costs and capital expenditures.
Beginning in the second half of 2021 and continuing throughout 2022, we, similar to other companies in our industry, experienced inflationary pressures on our operating costs and capital expenditures - namely the costs of fuel, steel (i.e., wellbore tubulars and facilities manufactured using steel), labor and drilling and completion services. Such inflationary pressures on our operating and capital costs, which we currently expect to continue in 2023, have impacted our cash flows and results of operations. We have undertaken, and plan to continue with, certain initiatives and actions (such as agreements with service providers to secure the costs and availability of services) to mitigate such inflationary pressures. However, there can be no assurance that such efforts will offset, largely or at all, the impacts of any future inflationary pressures on our operating costs and capital expenditures and, in turn, our cash flows and results of operations. For additional discussion, see ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview - Recent Developments.
We have substantial capital requirements, and we may be unable to obtain needed financing on satisfactory terms, if at all.
We make, and expect to continue to make, substantial capital expenditures for the acquisition, exploration, development and production of crude oil, NGLs and natural gas reserves. We intend to finance our capital expenditures primarily through our cash flows from operations and cash on hand 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 any planned 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.
In addition, companies in the oil and gas sector may be exposed to increasing reputational risks and, in turn, certain financial risks. Specifically, certain financial institutions (including certain investment advisors and sovereign wealth, pension and endowment funds), in response to concerns related to climate change and the requests and other influence of environmental groups and similar stakeholders, have elected to shift some or all of their investments away from oil and gas-related sectors, and additional financial institutions and other investors may elect to do likewise in the future. As a result, fewer financial institutions and other investors may be willing to invest in, and provide capital to, companies in the oil and gas sector. A material reduction in capital available to the oil and gas sector could make it more difficult (e.g., due to a lack of investor interest in our equity or debt securities) and/or more costly (e.g., due to higher interest rates on our debt securities or other borrowings) to secure funding for our operations, which, in turn, could adversely affect our ability to successfully carry out our business strategy and have a material and adverse effect on our business, financial condition and operations.
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, NGLs 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 ability to declare and pay dividends is subject to certain considerations.
Dividends are authorized and determined by our Board of Directors (Board) in its sole discretion and depend upon a number of factors, including:
•cash available for dividends;
•our results of operations and anticipated future results of operations;
•our financial condition, especially in relation to the anticipated future capital expenditures and other commitments required to conduct our operations and carry out our business strategy;
•our operating expenses;
•the levels of dividends paid by comparable companies; and
•other factors our Board deems relevant.
We expect to continue to pay dividends to our stockholders; however, our Board may reduce our dividend or cease declaring dividends at any time, including if it determines that our current or forecasted future cash flows provided by our operating activities (after deducting our capital expenditures and other commitments) are not sufficient to pay our desired levels of dividends to our stockholders or to pay dividends to our stockholders at all. Any reduction in the amount of dividends we pay to stockholders could have an adverse effect on the trading price of our common stock.
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 financial 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 2023 is subject to fluctuating market prices. If we are ultimately unable to hedge additional production volumes for 2023 and beyond, we may be materially and adversely impacted by any declines in commodity prices, which may result in lower net cash provided by our 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 (i) the unavailability of required facilities or equipment due to mechanical failure or market conditions or (ii) financial, operational or strategic actions taken by the customer or counterparty that adversely impact its financial condition, results of operations and cash flows and, in turn, its ability to satisfy its contractual obligations to us. 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, export 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;
•leasehold 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, NGLs 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, NGLs and 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, transporting and exporting crude oil, NGLs 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, transportation and export of crude oil, NGLs and natural gas; and
•malfunctions of, or damage to, gathering, processing, compression, storage, transportation and export 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. In the future, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums, retentions and deductibles for our insurance policies will change over time and could escalate. In addition, some forms of insurance may become unavailable or unavailable on economically acceptable terms.
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, refining 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, refining 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, refining 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, refining 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 transportation 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, refining and export facilities and equipment or the availability of these facilities and equipment, including due to our failure or inability to obtain access to these facilities and equipment on terms acceptable to us or at all, could materially and adversely affect our business and, in turn, our financial condition and results of operations.
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.
Our operations are substantially dependent upon the availability of water. Restrictions on our ability to obtain water may have a material and adverse effect on our financial condition, results of operations and cash flows.
Water is an essential component of our operations, both during the drilling and hydraulic fracturing processes. Limitations or restrictions on our ability to secure sufficient amounts of water (including limitations resulting from natural causes such as drought) could materially and adversely impact our operations. Further, severe drought conditions can result in local authorities taking steps to restrict the use of water in their jurisdiction for drilling and hydraulic fracturing in order to protect the local water supply. If we are unable to obtain water to use in its operations from local sources, it may need to be obtained from new sources and transported to drilling sites, resulting in increased costs, which could have a material adverse effect on our financial condition, results of operations and cash flows.
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 issues, 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. 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 issues (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 issues 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, NGLs and natural gas reserves (as discussed further above), actual future production rates and associated costs with respect to acquired properties. Actual reserves, production rates and costs may vary substantially from those assumed in our estimates. In addition, an acquisition may have a material and adverse effect on our business and results of operations, particularly during the periods in which the operations of the acquired properties are being integrated into our ongoing operations or if we are unable to effectively integrate the acquired properties into our ongoing operations.
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 ESG/Sustainability, Regulatory and Legal Matters
Developments and concerns related to climate change may have a material and adverse effect on us.
Governmental and regulatory bodies, investors, consumers, industry and other stakeholders have been increasingly focused on climate change matters in recent years. This focus, together with changes in consumer and industrial/commercial behavior, preferences and attitudes with respect to the generation and consumption of energy, the use of crude oil, NGLs and natural gas and the use of products manufactured with, or powered by, crude oil, NGLs and natural gas, may result in (i) the enactment of climate change-related regulations, policies and initiatives (at the government, corporate and/or investor community levels), including alternative energy requirements, energy conservation measures and emissions-related legislation, (ii) technological advances with respect to the generation, transmission, storage and consumption of energy (e.g., wind, solar and hydrogen power, smart grid technology and battery technology) and (iii) increased availability of, and increased consumer and industrial/commercial demand for, non-hydrocarbon energy sources (e.g., alternative energy sources) and products manufactured with, or powered by, non-hydrocarbon sources (e.g., electric vehicles and renewable residential and commercial power supplies). These developments may adversely affect the demand for products manufactured with, or powered by, crude oil, NGLs and natural gas and the demand for, and in turn the prices of, the crude oil, NGLs and natural gas that we sell. See the risk factor above for a discussion of the impact of commodity prices (including fluctuations in commodity prices) on our financial condition, cash flows and results of operations.
In addition to potentially adversely affecting the demand for, and prices of, the crude oil, NGLs and natural gas that we produce and sell, such developments may also adversely impact, among other things, the availability to us of necessary third-party services and facilities that we rely on, which may increase our operational costs and adversely affect our ability to explore for, produce, transport and process crude oil, NGLs and natural gas and successfully carry out our business strategy. For further discussion of the potential impact of such availability-related risks on our financial condition and results of operations, see the discussion in the section above entitled "Risks Related to our Operations."
Further, climate change-related developments may result in negative perceptions of the oil and gas industry and, in turn, reputational risks associated with the exploration for, and production of, hydrocarbons. Such negative perceptions and reputational risks may adversely affect our ability to successfully carry out our business strategy, for example, by adversely affecting the availability and cost of capital to us. For further discussion of the potential impact of such risks on our financial condition, cash flows and results of operations, see the discussion below in this section and in the section above entitled "Risks Related to Our Operations."
In addition, the enactment of climate change-related regulations, policies and initiatives (at the government, corporate and/or investor community levels) may also result in increases in our compliance costs and other operating costs. For further discussion regarding the risks to us of climate change-related regulations, policies and initiatives, see the discussion in this section. Also, continuing political and social concerns relating to climate change may have adverse effects on our business and operations, such as a greater potential for shareholder activism, governmental inquiries and enforcement actions and litigation (including, but not limited to, litigation brought by governmental entities and shareholder litigation) and resulting expenses and potential disruption to our day-to-day operations.
Regulatory, legislative and policy changes may materially and adversely affect the oil and gas exploration and production industry.
New or revised rules, regulations and policies may be issued, and new legislation may be proposed, 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 state, tribal and federal lands, (ii) the leasing of state, tribal and 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 state, tribal and federal lands, (v) the calculation of royalty payments in respect of oil and gas production from state, tribal and federal lands (including, but not limited to, an increase in applicable royalty percentages), (vi) U.S. federal income tax laws applicable to oil and gas exploration and production companies and (vii) the use of financial derivative instruments to hedge the financial impact of fluctuations in crude oil, NGLs and natural gas prices.
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, financial condition and capital expenditures.
For related discussion, see the below risk factors regarding legislative and regulatory matters impacting the oil and gas exploration and production industry and the discussion in ITEM 1, Business - Regulation.
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, financial condition and capital expenditures.
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, could lead to increased operating and compliance costs and, in turn, materially and adversely affect our business, results of operations, financial condition and capital expenditures.
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.
Any new requirements, restrictions, conditions or prohibitions 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, financial condition and capital expenditures. 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 financial derivative 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 which is subject to amendment from time to time. 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. Our operations will also be subject to the methane emissions charges, once published by the U.S. EPA, imposed under the Inflation Reduction Act of 2022.
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 in November 2016 and to which the United States formally rejoined in February 2021. The United States has established an economy-wide target of reducing its net GHG emissions by 50-52 percent below 2005 levels by 2030 and achieving net zero GHG emissions economy-wide by no later than 2050. In addition, many state and local officials have stated their intent to intensify efforts to uphold the commitments set forth in the international accord.
It is possible that the Paris Agreement and subsequent domestic and international regulations and government policies related to climate change and GHG emissions will have adverse effects on the market for crude oil, NGLs and natural gas as well as adverse effects on the business and operations of companies engaged in the exploration for, and production of, crude oil, NGLs and natural gas.
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.), but the direct and indirect costs of such developments (if enacted, issued or applied) could materially and adversely affect our operations, financial condition, results of operations and capital expenditures. The potential increase in the costs of our operations could include costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay taxes or fees related to our GHG emissions, or administer and manage a GHG emissions program. In addition, changes in regulatory policies that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to GHG emissions, or restrictions on their use, could also adversely affect market demand for, and in turn the prices we receive for our production of, crude oil, NGLs and natural gas. For additional discussion regarding the regulation of GHG emissions and climate change generally, see ITEM 1, Business - Regulation.
Our initiatives, targets and ambitions related to emissions and other ESG matters, including our related public statements and disclosures, may expose us to certain risks.
We have developed, and will continue to develop, targets and ambitions related to our environmental, social and governance (ESG) initiatives, including, but not limited to, our emissions reduction targets and our ambition to reach net zero Scope 1 and Scope 2 GHG emissions by 2040. Our public disclosures and other statements related to these initiatives, targets and ambitions reflect our plans and expectations at the time such disclosures and statements are made and are not a guarantee the initiatives will be successfully developed, implemented and carried out or that the targets or ambitions will be achieved or achieved on the anticipated timelines.
Our ability to achieve our ESG-related targets and ambitions is subject to numerous factors and conditions, some of which are outside of our control and include evolving government regulation, the pace of changes in technology, the successful development and deployment of existing or new technologies and business solutions on a commercial scale, the availability, timing and cost of necessary equipment, goods, services and personnel, and the availability of requisite financing and federal and state incentive programs. For example, we are exploring technology to capture and store carbon dioxide emissions, which includes a pilot carbon capture and storage (CCS) project related to our operations. CCS projects face operational, technological, legal and regulatory risks that could be considerable due to the early-stage nature of such projects and the CCS sector generally. Our ability to successfully develop, implement and carry out our CCS activities will depend on a number of factors that we will not be able to fully control, including timing of regulatory approvals and availability of subsurface pore space. Further, financial or tax incentives in respect of CCS projects could be changed or terminated. In addition, our failure to properly operate a CCS project could put at risk certain governmental tax credits and potentially expose us to commercial, legal, reputational and other risks.
In addition, the pursuit and achievement of our current or future initiatives, targets and ambitions relating to the reduction of GHG emissions may increase our costs, including requiring us to purchase emissions credits or offsets, the availability and price of which are outside of our control, and may impact or otherwise limit our ability to execute on our business strategy. Such initiatives, targets and ambitions are also subject to business, regulatory, economic and competitive uncertainties and contingencies, and required advancements in technology. Also, our continuing efforts to research, establish, accomplish and accurately report on our emissions and other ESG-related initiatives, targets and ambitions may create additional operational risks and expenses and expose us to reputational, legal and other risks.
Further, investor and regulatory focus on ESG matters continues to increase. If our ESG-related initiatives, targets and ambitions do not meet our investors' or other stakeholders' evolving expectations and standards, investment in our stock may be viewed as less attractive and our reputation and contractual, employment and other business relationships may be adversely impacted.
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 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, whether imposed on producers or consumers, would generally increase the prices for crude oil, NGLs and natural gas. Such price increases may, in turn, reduce demand for crude oil, NGLs and natural gas 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.
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 the 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, 2022, EOG had no net operating revenues related to operations of our foreign subsidiaries whose functional currency was not the U.S. dollar.
Risks Related to Cybersecurity, Outbreaks/Pandemics and Other External Factors
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, gathering and processing, transportation, pipelines and other related activities and (iv) communicate with our employees and vendors, suppliers and other third parties. Further, our reliance on technology has increased due to the increased use of personal devices, remote communications and other work-from-home practices adopted in response to the COVID-19 pandemic. 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, NGLs 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 incidents in the past, we have not had, to date, any business interruptions or material losses from breaches of cybersecurity. However, there is no assurance that we will not suffer any such interruptions or 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.
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, NGLs and natural gas, 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, NGLs and natural gas prices.
For example, the recent pandemic involving a highly transmissible and pathogenic coronavirus (COVID-19) and the measures taken to address and limit the spread of the virus adversely affected the economies and financial markets of the world, resulting in an economic downturn that negatively impacted global demand and prices for crude oil, NGLs and natural gas. In fact, the substantial declines in crude oil, NGLs and natural gas 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 the prices for crude oil, NGLs and natural gas have since recovered to at or above pre-pandemic 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, in the event of a future outbreak or pandemic, we may 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 such a future outbreak or pandemic results in an economic downturn, 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 would be many variables and uncertainties associated with any future outbreak or pandemic, including the duration and severity of the outbreak; the emergence, contagiousness and threat of new and different strains of the virus; the development, availability, acceptance, and effectiveness of treatments or vaccines; the extent of travel restrictions, business closures and other measures imposed by governmental authorities; disruptions in the supply chain; a prolonged delay in the resumption of operations by one or more contractual parties; an increasingly competitive labor market due to a sustained labor shortage or increased turnover caused by the outbreak/pandemic; increased logistics costs; additional operating costs due to remote working arrangements, adherence to social distancing guidelines, and other related challenges; increased risk of cyberattacks on information technology systems used in remote working arrangements; increased privacy-related risks due to processing health-related personal information; absence of employees due to illness; the impact of the pandemic on EOG's customers and contractual counterparties; and other factors that may be currently unknown or considered immaterial, to fully assess the potential impact on our business, financial condition and results of operations.
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, NGLs and natural gas, increased volatility in crude oil, NGLs and natural gas prices or the possibility that the facilities and other infrastructure on which we rely could be a direct target or an indirect casualty of an act of terrorism, and, in turn, could materially and adversely affect our business, financial condition and results of operations.
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 and/or transportation facilities and the availability of, and our access to, necessary third-party services and facilities, such as gathering, processing, compression, storage, transportation and export services and facilities. 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 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 reserves, conducts successful exploration, exploitation and development activities resulting in additional reserves or, through engineering studies, identifies additional behind-pipe zones or secondary recovery reserves, the 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, 2022 (in thousands of acres). 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 2,062 1,630 2,753 1,852 4,815 3,482
Trinidad 77 65 216 125 293 190
Australia - - 1,009 1,009 1,009 1,009
Total 2,139 1,695 3,978 2,986 6,117 4,681
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 0.1 million net acres will expire in 2023, 0.1 million net acres will expire in 2024 and 1.0 million acres will expire in 2025 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, 2022, there were no proved undeveloped reserves (PUDs) associated with undeveloped leases on which drilling was planned after the expiration dates of such leases. 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 offshore Australia is set to expire at various dates through 2025 depending on EOG's decision to move forward with its defined work program or unless EOG is either granted a production license or an extension of the permit. In the fourth quarter of 2022, EOG applied for a one-year extension of the permit.
Productive Well Summary. The following table represents EOG's gross and net productive wells at December 31, 2022, including 2,530 wells in which we hold a royalty interest.
Crude Oil Natural Gas Total
Gross Net Gross Net Gross Net
United States 8,918 6,369 3,579 1,805 12,497 8,174
Trinidad 2 2 35 29 37 31
Total (1)
8,920 6,371 3,614 1,834 12,534 8,205
(1) EOG operated 9,039 gross and 8,053 net producing crude oil and natural gas wells at December 31, 2022. Gross crude oil and natural gas wells include 143 wells with multiple completions.
Drilling and Acquisition Activities. During the years ended December 31, 2022, 2021 and 2020, EOG expended $5.2 billion, $4.0 billion and $3.7 billion, respectively, for exploratory and development drilling, facilities and acquisition of leases and producing properties, including asset retirement costs of $298 million, $127 million and $117 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, 2022, 2021 and 2020:
Gross Development Wells Completed Gross Exploratory Wells Completed
Crude Oil Natural Gas Dry Hole Total Crude Oil Natural Gas Dry Hole Total
United States
462 133 11 606 3 - 8 11
Trinidad
- - - - - 2 1 3
Total
462 133 11 606 3 2 9 14
United States 474 72 5 551 10 1 1 12
Trinidad - - - - - - - -
Oman - - - - - - 3 3
Total 474 72 5 551 10 1 4 15
United States 580 13 15 608 3 - 4 7
Trinidad - - - - - 3 - 3
Total 580 13 15 608 3 3 4 10
The following tables set forth the results of the net crude oil and natural gas wells completed for the years ended December 31, 2022, 2021 and 2020:
Net Development Wells Completed Net Exploratory Wells Completed
Crude Oil Natural Gas Dry Hole Total Crude Oil Natural Gas Dry Hole Total
United States
395 117 10 522 3 - 8 11
Trinidad
- - - - - 2 1 3
Total
395 117 10 522 3 2 9 14
United States 434 66 4 504 10 1 1 12
Trinidad - - - - - - - -
Oman - - - - - - 3 3
Total 434 66 4 504 10 1 4 15
United States 516 12 15 543 2 - 3 5
Trinidad - - - - - 2 - 2
Total 516 12 15 543 2 2 3 7
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, 2022, 2021 and 2020:
Wells in Progress at End of Period
2022 2021 2020
Gross Net Gross Net Gross Net
United States 251 213 191 167 155 147
Trinidad 1 1 1 1 1 1
China - - - - 3 3
Oman - - - - 1 1
Total 252 214 192 168 160 152
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, 2022, there were approximately 88 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
2022 2021 2020
Gross Net Gross Net Gross Net
United States 122 98 121 105 89 86
China - - - - 3 3
Total 122 98 121 105 92 89
EOG acquired wells as set forth in the following table (excluding the acquisition of additional interests in 74, 5 and 8 net wells in which EOG previously owned an interest for the years ended December 31, 2022, 2021 and 2020, respectively) for the years ended December 31, 2022, 2021 and 2020:
Gross Acquired Wells Net Acquired Wells
Crude
Oil Natural
Gas Total Crude
Oil Natural
Gas Total
United States
25 5 30 19 1 20
Total
25 5 30 19 1 20
United States 2 14 16 1 13 14
Total 2 14 16 1 13 14
United States 80 3 83 70 3 73
Total 80 3 83 70 3 73
Other Property, Plant and Equipment. EOG's other property, plant and equipment primarily includes gathering, transportation and processing infrastructure assets and buildings 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 this item, EOG uses 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, 2022.

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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 16, 2023, there were approximately 2,800 record holders and approximately 1,075,000 beneficial owners of EOG's common stock.
EOG expects to continue to pay dividends to its stockholders; however, EOG's Board may reduce the dividend or cease declaring dividends at any time, including if it determines that EOG's current or forecasted future cash flows provided by its operating activities (after deducting capital expenditures and other commitments) are not sufficient to pay EOG's desired levels of dividends to its stockholders or to pay dividends to its stockholders at all. For additional discussion, see ITEM 1A, Risk Factors.
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 or Value of Shares Purchased as
Part of Publicly
Announced Plans or
Programs (d)
Approximate Dollar Value of Shares
that May Yet Be Purchased Under the Plans or Programs (2)
October 1, 2022 - October 31, 2022 76,033 $ 128.00 - $ 5,000,000,000
November 1, 2022 - November 30, 2022 86,759 145.63 - $ 5,000,000,000
December 1, 2022 - December 31, 2022 4,793 133.85 - $ 5,000,000,000
Total 167,585 137.30
(1)The 167,585 total shares for the quarter ended December 31, 2022, and the 996,588 total shares for the full year 2022, 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 November 2021 Authorization (as defined and further discussed below).
(2)Effective November 4, 2021, the Board established a new share repurchase authorization to allow for the repurchase by EOG of up to $5 billion of its common stock (November 2021 Authorization). Under the November 2021 Authorization, EOG may repurchase shares from time to time, at management's discretion, in accordance with applicable securities laws, including through open market transactions, privately negotiated transactions or any combination thereof. The timing and amount of repurchases, if any, will be at the discretion of EOG's management and will depend on a variety of factors, including the then-trading price of EOG's common stock, corporate and regulatory requirements, and other market and economic conditions. Repurchased shares will be held as treasury shares and will be available for general corporate purposes. The November 2021 Authorization has no time limit, does not require EOG to repurchase a specific number of shares and may be modified, suspended, or terminated by the Board at any time. EOG did not repurchase any shares under the November 2021 Authorization during the fourth quarter of 2022.
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, 2017 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, 2022)
2017 2018 2019 2020 2021 2022
EOG $ 100.00 $ 81.33 $ 79.03 $ 48.50 $ 91.51 $ 143.55
S&P 500 $ 100.00 $ 95.62 $ 125.72 $ 148.85 $ 191.58 $ 156.88
S&P O&G E&P $ 100.00 $ 80.50 $ 90.17 $ 58.24 $ 108.95 $ 172.69

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. Reserved

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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 and Trinidad. 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 maximize long-term 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 net income of $7,759 million during 2022 as compared to net income of $4,664 million for 2021. At December 31, 2022, EOG's total estimated net proved reserves were 4,238 million barrels of oil equivalent (MMBoe), an increase of 491 MMBoe from December 31, 2021. During 2022, net proved crude oil and condensate and natural gas liquids (NGLs) reserves increased by 429 million barrels (MMBbl), and net proved natural gas reserves increased by 369 billion cubic feet or 62 MMBoe, in each case from December 31, 2021.
Recent Developments
Commodity Prices. Prices for crude oil and condensate, NGLs and natural gas have historically been volatile. This volatility is expected to continue due to the many uncertainties associated with the world political and economic environment and 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.
The market prices of crude oil and condensate, NGLs and natural gas impact the amount of cash generated from EOG's operating activities, which, in turn, impact EOG's financial position and results of operations.
For the year ended December 31, 2022, the average U.S. New York Mercantile Exchange (NYMEX) crude oil and natural gas prices were $94.23 per barrel and $6.64 per million British thermal units (MMBtu), respectively, representing increases of 39% and 72%, respectively, from the average NYMEX prices for the year ended December 31, 2021. Market prices for NGLs are influenced by the components extracted, including ethane, propane and butane and natural gasoline, among others, and the respective market pricing for each component.
The increases in crude oil and natural gas prices during 2022 were due to numerous factors, including the continued recovery in demand for crude oil, natural gas and NGLs from the impacts of the COVID-19 pandemic; low worldwide inventory levels; continued supply restraint by OPEC+ (a consortium of OPEC (Organization of Petroleum Exporting Countries) and certain non-OPEC global producers); and the impact resulting from the ongoing conflict between Russia and Ukraine.
Inflation Considerations; Availability of Materials, Labor & Services. Beginning in the second half of 2021 and continuing throughout 2022, EOG, similar to other companies in its industry, has experienced inflationary pressures on its operating and capital costs - namely the costs of fuel, steel (i.e., wellbore tubulars and facilities manufactured using steel), labor and drilling and completion services. Such inflationary pressures have resulted from (i) supply chain disruptions caused by the COVID-19 pandemic and the resulting limited availability of certain materials and products manufactured using such materials; (ii) increased demand for fuel and steel; (iii) increased demand for drilling and completion services coupled with a limited number of available service providers, resulting in increased competition for such services among EOG and other companies in its industry; (iv) labor shortages; and (v) other factors, including the ongoing conflict between Russia and the Ukraine which began in late February 2022.
Such inflationary pressures on EOG's operating and capital costs have, in turn, impacted its cash flows and results of operations. However, by virtue of its continued focus on increasing its drilling, completion and operating efficiencies and improving the performance of its wells, as well as the flexibility provided by its multi-basin drilling portfolio, EOG has been able to largely offset such impacts. EOG currently expects such inflationary pressures to result in an increase of approximately 10 percent in its fiscal year 2023 well costs (i.e., its costs for drilling, completions and well-site facilities) versus fiscal year 2022. Accordingly, such expected increase in EOG's fiscal year 2023 well costs is not expected to have a material impact on EOG's full-year 2023 results of operations. Further, such inflationary pressures and the factors contributing to such inflationary pressures (described above) are not expected to impact EOG's liquidity, capital resources, cash requirements or financial position or its ability to conduct its day-to-day drilling, completion and production operations.
The initiatives EOG has undertaken (and continues to undertake) to increase its drilling, completion and operating efficiencies and improve the performance of its wells and, in turn, partially mitigate such inflationary pressures, include (among others): (i) EOG's downhole drilling motor program, which has resulted in increased footage drilled per day and, in turn, reduced drilling times; (ii) enhanced techniques for completing its wells, which has resulted in increased footage completed per day and pumping hours per day; and (iii) EOG's self-sourced sand program, which has resulted in continued costs savings for the sand utilized in its well completion operations. In addition, EOG enters into agreements with its service providers from time to time, when available and advantageous, to secure the costs and availability of certain of the drilling and completion services it utilizes as part of its operations.
EOG plans to continue with these initiatives and actions, though there can be no assurance that such efforts will offset, largely or at all, the impacts of any future inflationary pressures on EOG's operating and capital costs, cash flows and results of operations. Further, there can be no assurance that the factors contributing to any future inflationary pressures will not impact EOG's ability to conduct its future day-to-day drilling, completion and production operations. See ITEM 1A, Risk Factors, for related discussion.
Climate Change. For a discussion of climate change matters and related regulatory matters, including potential developments related to climate change and the potential impacts and risks of such developments on EOG, see ITEM 1A, Risk Factors, and the related discussion in ITEM 1, Business - Regulation. EOG will continue to monitor and assess any climate change-related developments that could impact EOG and 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, 2022.
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 natural gas plays.
In 2022, EOG continued to focus on increasing drilling, completion and operating efficiencies, to improve well performance and, as is further discussed above, to partially mitigate inflationary pressures on its operating and capital costs. 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 or bolt-on 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 75% of EOG's United States production during both 2022 and 2021. During 2022, EOG's 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. See ITEM 1, Business - Exploration and Production for further discussion regarding EOG's 2022 United States operations.
Trinidad. In the Republic of Trinidad and Tobago (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 (NGC), and crude oil and condensate which is sold to Heritage Petroleum Company Limited (Heritage), with the exception of the Modified U(b) Block in which the company ceased to have an interest in the production of natural gas and crude oil and condensate in the fourth quarter of 2022. In July 2022, EOG amended the natural gas sales contract with NGC to extend the term and provide for an increase in price realizations if index prices for certain commodities exceed specified levels. The pricing component of this amendment was effective September 2020.
In March 2021, EOG signed a farmout agreement with Heritage, which allows EOG to earn a 65% working interest in a portion of the contract area (EOG Area) governed by the Trinidad Northern Area License. The EOG Area is located offshore the southwest coast of Trinidad. In 2022, EOG drilled one net exploratory well, which was determined to be unsuccessful.
Also in 2022, EOG completed the design, fabrication and installation of a platform and related facilities for its previously announced discovery in the Modified U(a) Block. Additionally in 2022, EOG completed the drilling of, and put on production, two net exploratory wells from a pre-existing platform in the Modified U(a) Block. In 2023, EOG expects to complete three developmental and two exploratory wells in the Modified U(a) Block. Additionally, EOG expects to make progress on the design and construction of a platform and related facilities in the Mento Area.
Other International. In November 2021, a subsidiary of EOG was granted an exploration permit for the WA-488-P Block, located offshore Western Australia. In 2022, EOG continued preparing for the drilling of an exploration well, the timing of which will depend on obtaining regulatory approvals and subsequent equipment availability.
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 17% at December 31, 2022 and 19% at December 31, 2021. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.
During 2022, EOG funded $5.3 billion ($153 million of which was non-cash) in exploration and development and other property, plant and equipment expenditures (excluding asset retirement obligations) and paid $5.1 billion in dividends to common stockholders, primarily by utilizing net cash provided from its operating activities.
Total anticipated 2023 capital expenditures are estimated to range from approximately $5.8 billion to $6.2 billion, excluding acquisitions, non-cash transactions and exploration costs. The majority of 2023 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.
Cash Return Framework. On May 5, 2022, EOG announced the addition of quantitative guidance to its cash return framework - specifically, a commitment to return a minimum of 60% of annual net cash provided by operating activities before certain balance sheet-related changes, less total capital expenditures, to stockholders, through a combination of quarterly dividends, special dividends and share repurchases. For related discussion regarding our payment of dividends, see ITEM 1A, Risk Factors, and ITEM 5, Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities, of EOG's Annual Report on Form 10-K for the year ended December 31, 2022, filed on February 23, 2023 (EOG's 2022 Annual Report).
Dividend Declarations. On February 24, 2022, EOG's Board of Directors (Board) declared a quarterly cash dividend on the common stock of $0.75 per share paid on April 29, 2022, to stockholders of record as of April 15, 2022. The Board also declared on such date a special dividend of $1.00 per share paid on March 29, 2022, to stockholders of record as of March 15, 2022.
On May 5, 2022, the Board declared a quarterly cash dividend on the common stock of $0.75 per share paid on July 29, 2022, to stockholders of record as of July 15, 2022. The Board also declared on such date a special dividend of $1.80 per share paid on June 30, 2022, to stockholders of record as of June 15, 2022.
On August 4, 2022, the Board declared a special dividend on the common stock of $1.50 per share paid on September 29, 2022, to stockholders of record as of September 15, 2022.
On September 29, 2022, the Board declared a quarterly cash dividend on the common stock of $0.75 per share paid on October 31, 2022, to stockholders of record as of October 17, 2022.
On November 3, 2022, the Board (i) increased the quarterly cash dividend on the common stock from the previous $0.75 per share to $0.825 per share, effective beginning with the dividend paid on January 31, 2023, to stockholders of record as of January 17, 2023, and (ii) declared a special cash dividend on the common stock of $1.50 per share, paid on December 30, 2022, to stockholders of record as of December 15, 2022.
On February 23, 2023, the Board declared a quarterly cash dividend on the common stock of $0.825 per share to be paid on April 28, 2023, to stockholders of record as of April 14, 2023. The Board also declared on such date a special dividend on the common stock of $1.00 per share to be paid on March 30, 2023, to stockholders of record as of March 16, 2023.
Results of Operations
The following review of operations for each of the three years in the period ended December 31, 2022, should be read in conjunction with the consolidated financial statements of EOG and notes thereto beginning on page.
Operating Revenues and Other
During 2022, operating revenues increased $7,060 million, or 38%, to $25,702 million from $18,642 million in 2021. Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, NGLs and natural gas, increased $7,415 million, or 48%, to $22,796 million in 2022 from $15,381 million in 2021. Revenues from the sales of crude oil and condensate and NGLs in 2022 were approximately 83% of total wellhead revenues compared to 84% in 2021. During 2022, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $3,982 million compared to net losses of $1,152 million in 2021. Gathering, processing and marketing revenues increased $2,408 million during 2022, to $6,696 million from $4,288 million in 2021. EOG recognized net gains on asset dispositions of $74 million in 2022 compared to net gains on asset dispositions of $17 million in 2021.
Wellhead volume and price statistics for the years ended December 31, 2022, 2021 and 2020 were as follows:
Year Ended December 31 2022 2021 2020
Crude Oil and Condensate Volumes (MBbld) (1)
United States 460.7 443.4 408.1
Trinidad 0.6 1.5 1.0
Other International (2)
- 0.1 0.1
Total 461.3 445.0 409.2
Average Crude Oil and Condensate Prices ($/Bbl) (3)
United States $ 97.22 $ 68.54 $ 38.65
Trinidad 86.16 56.26 30.20
Other International (2)
- 42.36 43.08
Composite 97.21 68.50 38.63
Natural Gas Liquids Volumes (MBbld) (1)
United States 197.7 144.5 136.0
Other International (2)
- - -
Total 197.7 144.5 136.0
Average Natural Gas Liquids Prices ($/Bbl) (3)
United States $ 36.70 $ 34.35 $ 13.41
Other International (2)
- - -
Composite 36.70 34.35 13.41
Natural Gas Volumes (MMcfd) (1)
United States 1,315 1,210 1,040
Trinidad 180 217 180
Other International (2)
- 9 32
Total 1,495 1,436 1,252
Average Natural Gas Prices ($/Mcf) (3)
United States $ 7.27 $ 4.88 $ 1.61
Trinidad 4.43 (5)
3.40 2.57
Other International (2)
- 5.67 4.66
Composite 6.93 4.66 1.83
Crude Oil Equivalent Volumes (MBoed) (4)
United States 877.5 789.6 717.5
Trinidad 30.7 37.7 30.9
Other International (2)
- 1.6 5.4
Total 908.2 828.9 753.8
Total MMBoe (4)
331.5 302.5 275.9
(1) Thousand barrels per day or million cubic feet per day, as applicable.
(2)Other International includes EOG's China and Canada operations. The China operations were sold in the second quarter of 2021.
(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.
(5)Includes positive revenue adjustment of $0.76 per Mcf ($0.09 per Mcf of EOG's composite wellhead natural gas price) for the twelve months ended December 31, 2022, related to a price adjustment per a provision of the natural gas sales contact with NGC amended in July 2022 for natural gas sales during the period from September 2020 through June 2022.
2022 compared to 2021. Wellhead crude oil and condensate revenues in 2022 increased $5,242 million, or 47%, to $16,367 million from $11,125 million in 2021, due primarily to a higher composite average wellhead crude oil and condensate price ($4,831 million) and an increase in production ($411 million). EOG's composite wellhead crude oil and condensate price for 2022 increased 42% to $97.21 per barrel compared to $68.50 per barrel in 2021. Wellhead crude oil and condensate production in 2022 increased 4% to 461 MBbld as compared to 445 MBbld in 2021. The increased production was primarily in the Permian Basin, partially offset by decreased production in the Eagle Ford play and the Rocky Mountain area.
NGLs revenues in 2022 increased $836 million, or 46%, to $2,648 million from $1,812 million in 2021 primarily due to an increase in production ($666 million) and a higher composite average wellhead NGLs price ($170 million). EOG's composite average wellhead NGLs price increased 7% to $36.70 per barrel in 2022 compared to $34.35 per barrel in 2021. NGLs production in 2022 increased 37% to 198 MBbld as compared to 145 MBbld in 2021. The increased production was primarily in the Permian Basin.
Wellhead natural gas revenues in 2022 increased $1,337 million, or 55%, to $3,781 million from $2,444 million in 2021, primarily due to a higher composite wellhead natural gas price ($1,234 million) and an increase in natural gas deliveries ($103 million). EOG's composite average wellhead natural gas price increased 49% to $6.93 per Mcf in 2022 compared to $4.66 per Mcf in 2021. Natural gas deliveries in 2022 increased 4% to 1,495 MMcfd as compared to 1,436 MMcfd in 2021. The increase in production was primarily due to increased production of associated natural gas from the Permian Basin and higher deliveries in the Dorado gas play, partially offset by lower natural gas volumes due to the sale of certain legacy natural gas assets in the Rocky Mountain area in the first quarter of 2022, lower natural gas volumes in Trinidad and decreased production of associated natural gas from the Eagle Ford play.
During 2022, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $3,982 million, which included net cash paid for settlements of crude oil, NGLs and natural gas financial derivative contracts of $3,501 million. During 2021, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $1,152 million, which included net cash paid for settlements of crude oil, NGLs and natural gas financial derivative contracts of $638 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 capacity at third-party facilities with production in certain areas and to utilize excess capacity at EOG-owned facilities. EOG sells sand primarily in order to balance the timing of firm purchase agreements with completion operations. 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 2022 increased $46 million compared to 2021, primarily due to higher margins on natural gas marketing activities, partially offset by lower margins on crude oil and condensate marketing activities.
2021 compared to 2020. Wellhead crude oil and condensate revenues in 2021 increased $5,339 million, or 92%, to $11,125 million from $5,786 million in 2020, due primarily to a higher composite average wellhead crude oil and condensate price ($4,852 million) and an increase in production ($487 million). EOG's composite wellhead crude oil and condensate price for 2021 increased 77% to $68.50 per barrel compared to $38.63 per barrel in 2020. Wellhead crude oil and condensate production in 2021 increased 9% to 445 MBbld as compared to 409 MBbld in 2020. The increased production was primarily in the Permian Basin, partially offset by decreased production in the Eagle Ford play.
NGLs revenues in 2021 increased $1,144 million, or 171%, to $1,812 million from $668 million in 2020 primarily due to a higher composite average wellhead NGLs price ($1,104 million) and an increase in production ($40 million). EOG's composite average wellhead NGLs price increased 156% to $34.35 per barrel in 2021 compared to $13.41 per barrel in 2020. NGLs production in 2021 increased 6% to 145 MBbld as compared to 136 MBbld in 2020. The increased production was primarily in the Permian Basin.
Wellhead natural gas revenues in 2021 increased $1,607 million, or 192%, to $2,444 million from $837 million in 2020, primarily due to a higher composite wellhead natural gas price ($1,486 million) and an increase in natural gas deliveries ($121 million). EOG's composite average wellhead natural gas price increased 155% to $4.66 per Mcf in 2021 compared to $1.83 per Mcf in 2020. Natural gas deliveries in 2021 increased 15% to 1,436 MMcfd as compared to 1,252 MMcfd in 2020. The increase in production was primarily due to increased production of associated natural gas from the Permian Basin and higher natural gas volumes in Trinidad, partially offset by lower natural gas volumes associated with the dispositions of the Marcellus Shale assets in the third quarter of 2020 and the China assets in the second quarter of 2021.
During 2021, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $1,152 million, which included net cash paid for settlements of crude oil, NGLs and natural gas financial derivative contracts of $638 million. 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 from settlements of crude oil, NGLs and natural gas financial derivative contracts of $1,071 million.
Gathering, processing and marketing revenues less marketing costs in 2021 increased $230 million compared to 2020, primarily due to higher margins on crude oil and condensate and natural gas 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.
Operating and Other Expenses
2022 compared to 2021. During 2022, operating expenses of $15,736 million were $3,196 million higher than the $12,540 million incurred during 2021. The following table presents the costs per barrel of oil equivalent (Boe) for the years ended December 31, 2022 and 2021:
Lease and Well $ 4.02 $ 3.75
Transportation Costs 2.91 2.85
Gathering and Processing Costs 1.87 1.85
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties 10.21 11.58
Other Property, Plant and Equipment 0.48 0.49
General and Administrative (G&A) 1.72 1.69
Net Interest Expense 0.54 0.59
Total (1)
$ 21.75 $ 22.80
(1)Total excludes 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, gathering and processing costs, DD&A and G&A for 2022 compared to 2021 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, produced 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 $1,331 million in 2022 increased $196 million from $1,135 million in 2021 primarily due to higher operating and maintenance costs in the United States ($172 million) and higher workovers expenditures in the United States ($27 million). Lease and well expenses increased in the United States primarily due to increased operating activities resulting from increased production.
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, storage and terminal 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 $966 million in 2022 increased $103 million from $863 million in 2021 primarily due to increased transportation costs related to production from the Permian Basin ($98 million), the Eagle Ford play ($10 million) and the Dorado gas play ($7 million), partially offset by decreased transportation costs related to production from the Rocky Mountain area ($8 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 increased $62 million to $621 million in 2022 compared to $559 million in 2021 primarily due to increased gathering and processing fees related to production from the Permian Basin ($66 million) and increased operating and maintenance expenses related to production from the Permian Basin ($43 million) and the Eagle Ford play ($7 million), partially offset by decreased gathering and processing fees related to production from the Eagle Ford play ($30 million) and due to the sale of certain legacy natural gas assets in the Rocky Mountain area in the first quarter of 2022 ($28 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 2022 decreased $109 million to $3,542 million from $3,651 million in 2021. DD&A expenses associated with oil and gas properties in 2022 were $117 million lower than in 2021 primarily due to lower unit rates in the United States ($472 million) and lower production in Trinidad ($15 million), partially offset by an increase in production in the United States ($375 million). Unit rates in the United States decreased primarily due to upward reserve revisions related to higher average crude oil, NGLs and natural gas prices used in the prior year's reserve estimation process and to reserves added at lower costs as a result of increased efficiencies.
G&A expenses of $570 million in 2022 increased $59 million from $511 million in 2021 primarily due to a net increase in costs associated with corporate support activities, including employee-related expenses, and professional and other services.
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 group. 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, 2022 and 2021 (in millions):
Proved properties $ 120 $ 20
Unproved properties 206 310
Other assets 29 28
Inventories 25 13
Firm commitment contracts 2 5
Total $ 382 $ 376
Impairments of unproved oil and gas properties included charges of $38 million in 2021 due to the decision in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman.
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 2022 increased $538 million to $1,585 million (7.0% of wellhead revenues) from $1,047 million (6.8% of wellhead revenues) in 2021. The increase in taxes other than income was primarily due to increased severance/production taxes ($514 million), increased ad valorem/property taxes ($130 million) and increased payroll taxes ($7 million), partially offset by increased state severance tax refunds ($119 million), all in the United States.
Other income, net, was $114 million in 2022 compared to other income, net, of $9 million in 2021. The increase of $105 million in 2022 was primarily due to an increase in interest income ($81 million) and higher equity income from ammonia plants in Trinidad ($28 million).
EOG recognized an income tax provision of $2,142 million in 2022 compared to an income tax provision of $1,269 million in 2021, primarily due to increased pretax income. The net effective tax rate for 2022 increased to 22% from 21% in 2021.
2021 compared to 2020. During 2021, operating expenses of $12,540 million were $964 million lower than the $11,576 million incurred during 2020. The following table presents the costs per Boe for the years ended December 31, 2021 and 2020:
Lease and Well $ 3.75 $ 3.85
Transportation Costs 2.85 2.66
Gathering and Processing Costs 1.85 1.66
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties 11.58 11.85
Other Property, Plant and Equipment 0.49 0.47
General and Administrative (G&A) 1.69 1.75
Net Interest Expense 0.59 0.74
Total (1)
$ 22.80 $ 22.98
(1)Total excludes 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, gathering and processing costs, DD&A, G&A and net interest expense for 2021 compared to 2020 are set forth below. See "Operating Revenues and Other" above for a discussion of production volumes.
Lease and well expenses of $1,135 million in 2021 increased $72 million from $1,063 million in 2020 primarily due to higher operating and maintenance costs in the United States ($33 million) and in Trinidad ($5 million), higher workovers expenditures in the United States ($25 million) and higher lease and well administrative expenses in the United States ($12 million); partially offset by lower operating and maintenance costs in Canada ($6 million) and as a result of the disposition of all of the China assets in the second quarter of 2021 ($5 million). Lease and well expenses increased in the United States primarily due to increased operating activities resulting from increased production.
Transportation costs of $863 million in 2021 increased $128 million from $735 million in 2020 primarily due to increased transportation costs in the Permian Basin ($121 million) and the Rocky Mountain area ($22 million), partially offset by decreased transportation costs in the Eagle Ford play ($13 million).
Gathering and processing costs increased $100 million to $559 million in 2021 compared to $459 million in 2020 primarily due to increased gathering and processing fees related to production from the Permian Basin ($51 million) and the Rocky Mountain area ($10 million), increased operating costs in the Permian Basin ($26 million) and the Rocky Mountain area ($7 million) and increased administrative expenses in the United States ($15 million); partially offset by decreased gathering and processing fees in the Eagle Ford play ($5 million).
DD&A expenses in 2021 increased $251 million to $3,651 million from $3,400 million in 2020. DD&A expenses associated with oil and gas properties in 2021 were $235 million higher than in 2020 primarily due to an increase in production in the United States ($307 million) and Trinidad ($12 million) and higher unit rates in Trinidad ($14 million), partially offset by lower unit rates in the United States ($85 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 2021 were $15 million higher than in 2020 primarily due to an increase in expense related to storage assets.
G&A expenses of $511 million in 2021 increased $27 million from $484 million in 2020 primarily due to a net increase in costs associated with corporate support activities, including employee-related expenses and increased information system costs ($54 million); partially offset by a decrease in idle equipment and termination fees ($46 million).
Net interest expense of $178 million in 2021 was $27 million lower than 2020 primarily due to repayment in February 2021 of the $750 million aggregate principal amount of 4.100% Senior Notes due 2021 ($29 million), repayment in June 2020 of the $500 million aggregate principal amount of 4.40% Senior Notes due 2020 ($9 million), repayment in April 2020 of the $500 million aggregate principal amount of 2.45% Senior Notes due 2020 ($3 million) and lower interest payments for late royalty payments on Oklahoma properties ($6 million), partially offset by the issuance in April 2020 of the $750 million aggregate principal amount of 4.950% Senior Notes due 2050 ($11 million) and $750 million aggregate principal amount of 4.375% Senior Notes due 2030 ($10 million).
Exploration costs of $154 million in 2021 increased $8 million from $146 million in 2020 primarily due to increased geological and geophysical expenditures in the United States.
The following table represents impairments for the years ended December 31, 2021 and 2020 (in millions):
2021 2020
Proved properties $ 20 $ 1,268
Unproved properties 310 472
Other assets 28 300
Inventories 13 -
Firm commitment contracts 5 60
Total $ 376 $ 2,100
Impairments of proved properties in 2020 were primarily due to the decline in commodity prices and were primarily related to the write-down to fair value of legacy and non-core natural gas, crude oil and combo plays in the United States. Impairments of unproved oil and gas properties included charges of $38 million in 2021 due to the decision in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman and $252 million in 2020 for certain leasehold costs that are no longer expected to be developed before expiration. Impairments of other assets in 2020 were primarily for the write-down to fair value of sand and crude-by-rail assets and a commodity price-related write-down of other assets. Impairments of firm commitment contracts in 2020 were a result of the decision to exit the Horn River Basin in Canada.
Taxes other than income in 2021 increased $569 million to $1,047 million (6.8% of wellhead revenues) from $478 million (6.6% of wellhead revenues) in 2020. The increase in taxes other than income was primarily due to increased severance/production taxes in the United States ($522 million), increased severance/production taxes in Trinidad ($7 million) and decreased state severance tax refunds ($39 million).
EOG recognized an income tax provision of $1,269 million in 2021 compared to an income tax benefit of $134 million in 2020, primarily due to increased pretax income. The net effective tax rate for 2021 increased to 21% from 18% in 2020. The higher effective tax rate is mostly due to taxes attributable to EOG's foreign operations and stock-based compensation tax deficiencies increasing the effective tax rate on pretax income in 2021 and decreasing the effective tax rate on pretax loss in 2020.
Capital Resources and Liquidity
Cash Flow
The primary sources of cash for EOG during the three-year period ended December 31, 2022, were funds generated from operations and proceeds from asset sales. The primary uses of cash were funds used in operations; exploration and development expenditures; dividend payments to stockholders; net repayment of debt; net cash paid for settlements of financial commodity derivative contracts; other property, plant and equipment expenditures; and net collateral posted for financial commodity derivative contracts.
2022 compared to 2021. Net cash provided by operating activities of $11,093 million in 2022 increased $2,302 million from $8,791 million in 2021 primarily due to an increase in wellhead revenues ($7,415 million), partially offset by an increase in net cash paid for settlements of financial commodity derivative contracts ($2,863 million); an increase in net cash paid for income taxes ($1,361 million); and an increase in cash operating expenses ($982 million).
Net cash used in investing activities of $5,056 million in 2022 increased by $1,637 million from $3,419 million in 2021 primarily due to an increase in additions to oil and gas properties ($981 million), net cash used in working capital associated with investing activities in 2022 ($375 million) compared to net cash provided by working capital associated with investing activities in 2021 ($200 million); an increase in additions to other property, plant and equipment ($169 million); and an increase in other investing activities ($30 million), partially offset by an increase in proceeds from the sales of assets ($118 million).
Net cash used in financing activities of $5,273 million in 2022 included cash dividend payments ($5,148 million), purchases of treasury stock in connection with stock compensation plans ($118 million) and repayment of finance lease liabilities ($35 million). Cash provided by financing activities in 2022 included proceeds from stock options exercised and employee stock purchase plan activity ($28 million).
2021 compared to 2020. Net cash provided by operating activities of $8,791 million in 2021 increased $3,783 million from $5,008 million in 2020 primarily due to an increase in wellhead revenues ($8,090 million) and an increase in gathering, processing and marketing revenues less marketing costs ($230 million); partially offset by an increase in net cash paid for settlements of financial commodity derivative contracts ($1,709 million); an increase in net cash paid for income taxes ($1,320 million); net cash used in working capital in 2021 ($817 million) compared to net cash provided by working capital in 2020 ($193 million); and an increase in cash operating expenses ($882 million).
Net cash used in investing activities of $3,419 million in 2021 increased by $71 million from $3,348 million in 2020 primarily due to an increase in additions to oil and gas properties ($394 million), partially offset by net cash provided by working capital associated with investing activities in 2021 ($200 million) compared to net cash used in working capital associated with investing activities in 2020 ($75 million); an increase in proceeds from the sales of assets ($39 million); and a decrease in additions to other property, plant and equipment ($9 million).
Net cash used in financing activities of $3,493 million in 2021 included cash dividend payments ($2,684 million), repayments of long-term debt ($750 million), purchases of treasury stock in connection with stock compensation plans ($41 million) and repayment of finance lease liabilities ($37 million). Cash provided by financing activities in 2021 included proceeds from stock options exercised and employee stock purchase plan activity ($19 million).
Total Expenditures
The table below sets out components of total expenditures for the years ended December 31, 2022, 2021 and 2020 (in millions):
2022 2021 2020
Expenditure Category
Capital
Exploration and Development Drilling $ 3,675 $ 2,864 $ 2,664
Facilities 411 405 347
Leasehold Acquisitions (1)
186 215 265
Property Acquisitions (2)
419 100 135
Capitalized Interest 36 33 31
Subtotal 4,727 3,617 3,442
Exploration Costs 159 154 146
Dry Hole Costs 45 71 13
Exploration and Development Expenditures 4,931 3,842 3,601
Asset Retirement Costs 298 127 117
Total Exploration and Development Expenditures 5,229 3,969 3,718
Other Property, Plant and Equipment (3)
381 286 395
Total Expenditures $ 5,610 $ 4,255 $ 4,113
(1)Leasehold acquisitions included $127 million, $45 million and $197 million related to non-cash property exchanges in 2022, 2021 and 2020, respectively.
(2)Property acquisitions included $26 million, $5 million and $15 million related to non-cash property exchanges in 2022, 2021 and 2020, respectively.
(3)Other property, plant and equipment included non-cash additions of $74 million and $174 million, primarily related to finance lease transactions for storage facilities in 2021 and 2020, respectively.
Exploration and development expenditures of $4,931 million for 2022 were $1,089 million higher than the prior year. The increase was primarily due to increased exploration and development drilling expenditures in the United States ($763 million) and increased property acquisitions ($319 million). The 2022 exploration and development expenditures of $4,931 million included $3,962 million in development drilling and facilities, $514 million in exploration, $419 million in property acquisitions and $36 million in capitalized interest. The 2021 exploration and development expenditures of $3,842 million included $3,172 million in development drilling and facilities, $537 million in exploration, $100 million in property acquisitions and $33 million in capitalized interest. 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 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.
Financial Commodity Derivative Transactions
Presented below is a comprehensive summary of EOG's financial commodity derivative contracts settled during the year ended December 31, 2022 (closed) and remaining for 2023 and thereafter, as of February 16, 2023. Crude oil volumes are presented in MBbld and prices are presented in $/Bbl. Natural gas volumes are presented in MMBtu per day (MMBtud) and prices are presented in dollars per MMBtu ($/MMBtu).
Crude Oil Financial Price Swap Contracts
Contracts Sold Contracts Purchased
Period Settlement Index Volume (MBbld) Weighted Average
Price ($/Bbl) Volume (MBbld) Weighted Average
Price ($/Bbl)
January - March 2022 (closed) NYMEX WTI 140 $ 65.58 - $ -
April - June 2022 (closed) NYMEX WTI 140 65.62 - -
July - September 2022 (closed) NYMEX WTI 140 65.59 - -
October - December 2022 (closed) (1)
NYMEX WTI 53 66.11 - -
October - December 2022 (closed) NYMEX WTI 87 65.41 87 88.85
January - March 2023 (closed) (1) (2)
NYMEX WTI 55 67.96 - -
January 2023 (closed) NYMEX WTI 95 67.90 6 102.26
February - March 2023 NYMEX WTI 95 67.90 6 102.26
April - May 2023 (closed) (1)
NYMEX WTI 29 68.28 - -
April - May 2023 NYMEX WTI 91 67.63 2 98.15
June 2023 (closed) (1)
NYMEX WTI 118 67.77 - -
June 2023 NYMEX WTI 2 69.10 2 98.15
July - September 2023 (closed) (1)
NYMEX WTI 100 70.15 - -
October - December 2023 (closed) (1)
NYMEX WTI 69 69.41 - -
_________________
(1) In the second quarter of 2022, EOG executed the early termination provision granting EOG the right to terminate certain of its October 2022 - December 2023 crude oil financial price swap contracts which were open at that time. EOG paid net cash of $593 million for the settlement of these contracts.
(2) In the third quarter of 2022, EOG executed the early termination provision granting EOG the right to terminate certain of its January 2023 - March 2023 crude oil financial price swap contracts which were open at that time. EOG paid net cash of $63 million for the settlement of these contracts.
Crude Oil Basis Swap Contracts
Contracts Sold
Period Settlement Index Volume
(MBbld) Weighted Average
Price Differential
($/Bbl)
January - December 2022 (closed) NYMEX WTI Roll Differential (1)
125 $ 0.15
_________________
(1) This settlement index is used to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month.
Natural Gas Financial Price Swap Contracts
Contracts Sold
Period Settlement Index Volume
(MMBtud in thousands) Weighted Average
Price ($/MMBtu)
January - September 2022 (closed) NYMEX Henry Hub 725 $ 3.57
October - December 2022 (closed) (1)
NYMEX Henry Hub 425 3.05
October - December 2022 (closed) NYMEX Henry Hub 300 4.32
January - December 2023 (closed) (1)
NYMEX Henry Hub 425 3.05
January - February 2023 (closed) NYMEX Henry Hub 300 3.36
March - December 2023 NYMEX Henry Hub 300 3.36
January - December 2024 NYMEX Henry Hub 725 3.07
January - December 2025 NYMEX Henry Hub 725 3.07
_________________
(1) In the second quarter of 2022, EOG executed the early termination provision granting EOG the right to terminate certain of its October 2022 - December 2023 natural gas financial price swap contracts which were open at that time. EOG paid net cash of $735 million for the settlement of these contracts.
Natural Gas Basis Swap Contracts
Contracts Sold
Period Settlement Index Volume
(MMBtud in thousands) Weighted Average
Price Differential
($/MMBtu)
January - December 2022 (closed) NYMEX Henry Hub HSC Differential (1)
210 $ 0.01
January - February 2023 (closed) NYMEX Henry Hub HSC Differential 135 0.01
March - December 2023 NYMEX Henry Hub HSC Differential 135 0.01
January - December 2024 NYMEX Henry Hub HSC Differential 10 0.00
January - December 2025 NYMEX Henry Hub HSC Differential 10 0.00
_________________
(1) This settlement index is used to fix the differential between pricing at the Houston Ship Channel and NYMEX Henry Hub prices.
Financing
EOG's debt-to-total capitalization ratio was 17% at December 31, 2022, compared to 19% at December 31, 2021. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.
At both December 31, 2022 and 2021, EOG had outstanding $4,890 million aggregate principal amount of senior notes which had estimated fair values of $4,740 million and $5,577 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 2022, EOG funded its capital program and operations primarily by utilizing cash provided by operating activities and cash on hand. 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 2022 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.
Foreign Currency Exchange Rate Risk
During 2022, EOG was exposed to foreign currency exchange rate risk inherent in its operations in foreign countries, including Trinidad, Australia, Oman 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 economic and political environment, worldwide supplies of, and demand for, crude oil and condensate, NGLs and natural gas, the availabilities of other 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 2023 will impact the amount of cash generated from EOG's operating activities, which will in turn impact EOG's financial position. As of February 16, 2023, the average 2023 NYMEX crude oil and natural gas prices were $75.99 per barrel and $3.05 per MMBtu, respectively, representing a decrease of 19% for crude oil and a decrease of 54% for natural gas from the average NYMEX prices in 2022. See ITEM 1A, Risk Factors for additional discussion of the impact of commodity prices (including fluctuations in commodity prices) on our financial condition, cash flows and results of operations.
Including the impact of EOG's crude oil and NGLs financial derivative contracts (exclusive of basis swaps) and based on EOG's tax position, EOG's price sensitivity in 2023 for each $1.00 per barrel increase or decrease in wellhead crude oil and condensate price, combined with the estimated change in NGLs price, is approximately $137 million for net income and $175 million for pretax cash flows from operating activities. Including the impact of EOG's natural gas financial derivative contracts and based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2023 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 $35 million for net income and $44 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 16, 2023, see "Financial 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 drilling activity in its Delaware Basin, Eagle Ford play, Rocky Mountain area and Dorado gas play 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 lessen inflationary pressure through efficiency gains and by locking in certain service costs for drilling and completion activities. In addition, EOG expects to spend a portion of its anticipated 2023 capital expenditures on leasing acreage, evaluating new prospects, gathering and processing infrastructure, transportation infrastructure and environmental projects.
The total anticipated 2023 capital expenditures of approximately $5.8 billion to $6.2 billion, excluding acquisitions, non-cash transactions and exploration costs, 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 2023, crude oil and total crude oil equivalent production are expected to increase from 2022 levels. In 2023, EOG expects to continue to focus on mitigating inflationary pressure on operating costs through efficiency improvements.
Cash Requirements. Certain of EOG's capital expenditures and operating expenses are subject to contracts with minimum commitments, including those that meet the definition of a lease under ASC "Leases (Topic 842)". In 2023, EOG anticipates the following cash requirements under these commitments (in millions):
Finance Leases (1)
$ 37
Operating Leases (1)
Leases Effective, Not Commenced (1)
Transportation and Storage Service Commitments (2) (3)
Purchase and Service Obligations (3)
Total Cash Requirements $ 1,832
(1) For more information on contracts that meet the definition of a lease under ASC "Leases (Topic 842)," see Note 18 to Consolidated Financial Statements.
(2) 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, 2022. 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.
(3) For more information on transportation and storage service commitments and purchase and service obligations, see Note 8 to Consolidated Financial Statements.
In 2023, EOG has $1.25 billion of senior notes maturing, which are expected to be repaid with cash on hand. Additionally, in 2023, EOG expects to pay interest of $175 million on senior notes. For more information on EOG's current and long-term debt, see Note 2 to Consolidated Financial Statements.
Cash requirements to settle the liability for unrecognized tax benefits, EOG's pension and postretirement benefit obligations and the liability for dismantlement, abandonment and asset retirement obligations (see Notes 6, 7, and 15, respectively, to Consolidated Financial Statements) are excluded because they are subject to estimates and the timing of settlement is unknown.
EOG expects to fund its exploration, development and exploitation activities and other cash requirements, both in 2023 and in future years, primarily from internally generated cash flows and cash on hand. As discussed above, 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.
Summary of Critical Accounting Policies and Estimates
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 and estimates 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 and estimates 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 and estimates. Following is a discussion of EOG's most critical accounting policies and estimates:
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. Proved reserves are estimated using a trailing 12-month average price, in accordance with SEC rules. Crude oil, NGLs and natural gas prices have exhibited significant volatility in the past, and EOG expects that volatility to continue in the future. 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.
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.
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. The concept of sufficient progress is subject to significant judgment and may require further operational actions or require additional approvals from government agencies or partners in oil and gas operations, among other factors, the timing of which may delay management's determinations. See Note 16 to Consolidated Financial Statements.
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.
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 group. 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, 2022, WTI crude oil spot prices have fluctuated from approximately $(36.98) per barrel to $123.64 per barrel, and Henry Hub natural gas spot prices have ranged from approximately $1.33 per MMBtu to $23.86 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. In the future, if any combination of crude oil prices, NGLs prices, natural gas prices or estimated proved reserves diverge negatively from EOG's current estimates, impairment charges may be necessary.
See Notes 13 and 14 to Consolidated Financial Statements for further disclosures of impairments of oil and gas properties and other assets.
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. See Note 6 to Consolidated Financial Statements.
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," "ambition," "initiative," "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 financial or 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 drilling, completion and operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, other environmental matters, safety matters or other ESG (environmental/social/governance) matters, 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 such assumptions are accurate or will prove to have been correct or that any of such expectations will be achieved (in full or at all) or will be achieved on the expected or anticipated timelines. 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 (NGLs), 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 and operating costs and capital expenditures 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 success of EOG's cost-mitigation initiatives and actions in offsetting the impact of inflationary pressures on EOG's operating costs and capital expenditures;
•the extent to which EOG is successful in its efforts to market its production of crude oil and condensate, NGLs 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 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 climate change-related regulations, policies and initiatives (for example, with respect to air emissions); tax laws and regulations (including, but not limited to, carbon tax and emissions-related legislation); environmental, health and safety laws and regulations relating to 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, NGLs and natural gas; laws and regulations with respect to financial derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;
•the impact of climate change-related policies and initiatives at the corporate and/or investor community levels and other potential developments related to climate change, such as (but not limited to) changes in consumer and industrial/commercial behavior, preferences and attitudes with respect to the generation and consumption of energy; increased availability of, and increased consumer and industrial/commercial demand for, competing energy sources (including alternative energy sources); technological advances with respect to the generation, transmission, storage and consumption of energy; alternative fuel requirements; energy conservation measures and emissions-related legislation; decreased demand for, and availability of, services and facilities related to the exploration for, and production of, crude oil, NGLs and natural gas; and negative perceptions of the oil and gas industry and, in turn, reputational risks associated with the exploration for, and production of, crude oil, NGLs and natural gas;
•continuing political and social concerns relating to climate change and the greater potential for shareholder activism, governmental inquiries and enforcement actions and litigation and the resulting expenses and potential disruption to EOG's day-to-day operations;
•the extent to which EOG is able to successfully and economically develop, implement and carry out its emissions and other ESG-related initiatives and achieve its related targets ad initiatives;
•EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, identify and resolve existing and potential issues with respect to such properties and accurately estimate reserves, production, drilling, completion and operating costs and capital expenditures with respect to such properties;
•the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully, economically and in compliance with applicable laws and regulations;
•competition in the oil and gas exploration and production industry for the acquisition of licenses, leases and properties;
•the availability and cost of, and competition in the oil and gas exploration and production industry for, employees, labor and other personnel, facilities, equipment, materials (such as water, sand, fuel 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;
•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 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 "Financial 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, 2022. 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, 2022.
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. See "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, 2022, 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
On and effective February 23, 2023, the Board of Directors (Board) of EOG Resources, Inc. (EOG) approved certain amendments to EOG's bylaws with respect to, among other matters, (i) the submission by a stockholder of a director nomination or other proposal for an annual stockholders meeting and (ii) the authority of the Board with respect to stockholder meetings. The amendments, which are further described below, take into account (1) the new universal proxy rules adopted by the United States Securities and Exchange Commission (SEC) and (2) recent amendments to certain provisions of the General Corporation Law of the State of Delaware (DGCL).
Section of Bylaws Description of Amendment
Place of Meetings
(Art. II, § 1)
To provide that stockholder meetings may be held by means of remote communication in accordance with Section 211(a) of the DGCL.
Quorum; Adjournment of Meetings
(Art. II, § 2)
To provide that, to the fullest extent permitted by law, the Board may postpone, reschedule or cancel any previously scheduled stockholder meeting before it is to be held.
Notice of Stockholder Business and Nominations
(Art. II § 3)
To provide that a stockholder submitting a director nomination or other proposal shall represent that it will continue to be a stockholder through the annual meeting date and will appear at the meeting (in person or by proxy) to make such nomination/proposal.
To expand existing information requirements for submitting a director nomination or other proposal to cover the submitting stockholder's beneficial owners and their respective affiliates and associates.
To provide that a stockholder giving notice of a director nomination shall provide: (i) evidence of compliance with Rule 14a-19 (the SEC's universal proxy rules) no later than five business days prior to the applicable stockholders meeting, (ii) all information required to be set forth in a Schedule 13D (e.g., investment purpose for buying EOG shares and the source of funds for the share purchases), (iii) the names of all solicitation participants and (iv) a representation that at least 67% of EOG's voting stock will be solicited by the stockholder.
To provide that a stockholder proposal to amend EOG's bylaws shall include the full text of the proposed amendment(s).
Stockholder List
(Art. II, § 7)
To remove requirement that a list of EOG's stockholders be made available at stockholder meetings.
Proxies
(Art. II, § 8)
To provide that a stockholder soliciting proxies must use a proxy card color other than white.
Conduct of Meetings
(Art. II, § 10)
To provide that the Board, the chairman of the meeting and the Chairman of the Board may make rules and procedures for the conduct of stockholder meetings as they shall deem necessary (e.g., the opening and closing of polls and time allotted to questions and comments from attendees).
Emergency Bylaws
(Art. VII, § 7)
To permit a subset of the Board to take certain actions during an emergency condition (e.g., catastrophe or similar emergency condition).
The foregoing descriptions of the amendments to EOG's bylaws do not purport to be complete and are qualified in its entirety by reference to EOG's amended and restated bylaws, which are filed as Exhibit 3.2(b) to this report and are incorporated herein by reference.

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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 2023 Annual Meeting of Stockholders to be filed not later than April 30, 2023 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 2023 Annual Meeting of Stockholders to be filed not later than April 30, 2023. The Compensation and Human Resources 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 2023 Annual Meeting of Stockholders to be filed not later than April 30, 2023.
Equity Compensation Plan Information
Stock Plans Approved by EOG Stockholders. EOG's stockholders approved the EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (2021 Plan) at the 2021 Annual Meeting of Stockholders in April 2021. From and after the April 29, 2021 effective date of the 2021 Plan, no further grants have been (or will be) made from the Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (Amended and Restated 2008 Plan).
The 2021 Plan provides for grants of stock options, SARs, restricted stock, restricted stock units (which may include performance-based conditions) and other stock-based awards, up to an aggregate maximum of 20 million shares of EOG common stock, plus any shares that were subject to outstanding awards under the Amended and Restated 2008 Plan as of April 29, 2021 that subsequently are canceled or forfeited, expire or are otherwise not issued or are settled in cash. Under the 2021 Plan, grants may be made to employees and non-employee members of EOG's Board of Directors (Board).
The Amended and Restated 2008 Plan was approved by EOG's stockholders at the 2013 Annual Meeting of Stockholders in May 2013. The Amended and Restated 2008 Plan authorized an additional 31.0 million shares of EOG common stock for grant under the plan and extended the expiration date of the plan to May 2023.
At the 2018 Annual Meeting of Stockholders in April 2018, stockholders approved an amendment and restatement of the EOG Resources, Inc. Employee Stock Purchase Plan (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 Amended and Restated 2008 Plan and the 2021 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, 2022, 432,281 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, 2022.
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 5,653,833 (2)
$ 77.49 17,803,386 (3)
Equity Compensation Plans Not Approved by EOG Stockholders 340,078 (4)
N/A 107,719 (5)
Total 5,993,911 17,911,105
(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 (i) shares that will be issued upon the vesting of outstanding grants of restricted stock units or the vesting of outstanding grants of performance units and restricted stock units with performance-based conditions (collectively, performance units) or (ii) shares that will be issued in respect of issued and outstanding Deferral Plan phantom shares, all of which have no exercise price.
(2)Amount includes (i) 4,224,628 outstanding stock option and SAR grants, (ii) 741,411 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, and (iii) 687,794 outstanding performance units and assumes, for purposes of this table, (A) the application of a 100% performance multiple upon the completion of each of the remaining performance periods in respect of such grants and (B) accordingly, the issuance, on a one-for-one basis, of an aggregate 687,794 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 0 and a maximum of 1,375,588 performance units could be outstanding and (B) accordingly, a minimum of 0 and a maximum of 1,375,588 shares of EOG common stock could be issued upon the vesting of such grants.
(3)Consists of (i) 16,425,288 shares remaining available for issuance under the 2021 Plan and (ii) 1,378,098 shares remaining available for purchase under the ESPP. As noted above, from and after the April 29, 2021 effective date of the 2021 Plan, no further grants have been (or will be) made from the Amended and Restated 2008 Plan.
(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 340,078 phantom shares issued and outstanding under the Deferral Plan as of December 31, 2022).
(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 2023 Annual Meeting of Stockholders to be filed not later than April 30, 2023.

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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 2023 Annual Meeting of Stockholders to be filed not later than April 30, 2023.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. Exhibit and 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.